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As filed with the Securities and Exchange Commission on July 3, 2012

Registration No. 333-179502

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

AMENDMENT NO. 3

to

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Diamondback Energy, Inc.

(Exact name of registrant as specified in its charter)

 

Delaware		1311		45-4502447
(State or other jurisdiction of incorporation or organization)		(Primary Standard Industrial Classification Code Number)		(I.R.S. Employer Identification Number)

 

 

500 West Texas

Suite 1225

Midland, Texas 79701

(432) 221-7400

(Address, including zip code and telephone number, including area code, of registrant’s principal executive offices)

 

 

Teresa Dick

Chief Financial Officer

Diamondback Energy, Inc.

14301 Caliber Drive

Suite 300

Oklahoma City, Oklahoma 73134

(405) 463-6900

(Name, address, including zip code and telephone number, including area code, of agent for service)

 

 

Copies to:

Seth R. Molay, P.C. Akin Gump Strauss Hauer & Feld LLP 1700 Pacific Avenue, Suite 4100 Dallas, TX 75201 (214) 969-4780		J. Michael Chambers Keith Benson Latham & Watkins LLP 811 Main Street, Suite 3700 Houston, TX 77002 (713) 546-7416

 

 

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement is declared effective.

If any securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, as amended (the “Securities Act”), check the following box.  ¨

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer		¨				Accelerated filer		¨
Non-accelerated filer		x		(Do not check if a smaller reporting company)		Smaller reporting company		¨

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act or until this Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

 

 

 

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The information in this prospectus is not complete and may be changed. We and the selling stockholders may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and we and the selling stockholders are not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

 

SUBJECT TO COMPLETION, DATED JULY 3, 2012.

PROSPECTUS

             Shares

 

Diamondback Energy, Inc.

Common Stock

 

 

We are selling              shares of common stock and the selling stockholders are selling              shares of common stock. We will not receive any of the proceeds from the shares of common stock sold by the selling stockholders.

Prior to this offering, there has been no public market for our common stock. The initial public offering price of the common stock is expected to be between $         and $         per share. We have applied to list our common stock on The NASDAQ Global Market under the symbol “FANG.”

We and the selling stockholders granted the underwriters an option to purchase up to              and             , respectively, additional shares of our common stock, in each case to cover the underwriters’ option to purchase additional shares.

We are an “emerging growth company” under applicable Securities and Exchange Commission rules and will be subject to reduced public company reporting requirements. Investing in our common stock involves risks. See “Risk Factors” beginning on page 16.

 

		Price to Public		Underwriting Discounts and Commissions		Proceeds to Diamondback		Proceeds to Selling Stockholders
Per Share		$		$		$		$
Total		$		$		$		$

Delivery of the shares of common stock will be made on or about                     , 2012.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

Credit Suisse

The date of this prospectus is                     , 2012.

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ABOUT THIS PROSPECTUS

You should rely only on the information contained in this prospectus. We have not, and the selling stockholders and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. We, the selling stockholders and the underwriters are only offering to sell, and only seeking offers to buy, our common stock in jurisdictions where offers and sales are permitted.

The information contained in this prospectus is accurate and complete only as of the date of this prospectus, regardless of the time of delivery of this prospectus or of any sale of our common stock by us, the selling stockholders or the underwriters. Our business, financial condition, results of operations and prospects may have changed since that date.

Dealer Prospectus Delivery Obligation

Until                      (25 days after the commencement of the offering), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

Industry and Market Data

This prospectus includes industry data and forecasts that we obtained from internal company surveys, publicly available information and industry publications and surveys. Our internal research and forecasts are based on management’s understanding of industry conditions, and such information has not been verified by independent sources. Industry publications and surveys generally state that the information contained therein has been obtained from sources believed to be reliable.

Unless the context otherwise requires, the information in this prospectus (other than in the historical financial statements) assumes that the underwriters will not exercise their option to purchase additional shares.

 

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RISK FACTORS

An investment in our common stock involves a high degree of risk. You should carefully consider the following risks and all of the other information contained in this prospectus before deciding to invest in our common stock. Our business, financial condition and results of operations could be materially and adversely affected by any of these risks. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider immaterial also may adversely affect us.

Risks Related to the Oil and Natural Gas Industry and Our Business

Our business is difficult to evaluate because we have a limited operating history.

We were incorporated in Delaware on December 30, 2011. All of our historical oil and natural gas assets, operations and results described in this prospectus are currently those of Windsor Permian, which is an entity controlled by our equity sponsor, Wexford. Immediately prior to the closing of this offering, Windsor Permian will become our wholly-owned subsidiary and we will acquire the oil and gas assets of Gulfport located in the Permian Basin in the Gulfport transaction. The oil and natural gas properties of Windsor Permian, Gulfport and Windsor UT described in this prospectus have been acquired by Windsor Permian, Gulfport and Windsor UT since December 2007. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.

We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.

As a recently-formed company, growth in accordance with our business plan, if achieved, could place a significant strain on our financial, technical, operational and management resources. As we expand our activities and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and natural gas industry, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

Approximately 86% of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.

Approximately 86% of our net leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.

Our development and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. In 2011, our total capital expenditures, including expenditures for

 

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leasehold interest and property acquisitions, drilling, seismic and infrastructure, were approximately $75.4 million. Our 2012 capital budget for drilling, completion and infrastructure, including investments in water disposal infrastructure and gathering line projects, is estimated to be approximately $180.0 million to $190.0 million after giving effect to the Transactions. To date, we have financed capital expenditures primarily with funding from Wexford, our equity sponsor, borrowings under our revolving credit facility and cash generated by operations. However, neither Wexford nor any of its affiliates has made any commitment to provide us additional funding. Notwithstanding prior contributions and loans to us by Wexford or its affiliates, you should not assume that any of them will provide any debt or equity funding to us in the future.

In the near term, we intend to finance our capital expenditures with cash flow from operations, proceeds from this offering and borrowings under our revolving credit facility. Our cash flow from operations and access to capital are subject to a number of variables, including:

 

•

our proved reserves;

 

•

the volume of oil and natural gas we are able to produce from existing wells;

 

•

the prices at which oil and natural gas are sold; and

 

•

our ability to acquire, locate and produce new reserves.

We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2012 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include traditional reserve base borrowings, debt financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt or equity securities or other means. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.

If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or may be otherwise unable to implement our development plan, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies and related cost savings.

Our success depends on finding, developing or acquiring additional reserves.

Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. We have made and expect to make in the future substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of oil and natural gas reserves. We may not have sufficient resources to undertake our exploration, development and production activities or the acquisition of oil and natural gas reserves, our exploratory projects or other replacement activities may not result in significant additional reserves and we may not have success drilling productive wells at low finding and development costs. Furthermore, although our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.

Our project areas, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.

Our project areas are in various stages of development, ranging from project areas with current drilling or production activity to project areas that consist of recently acquired leasehold acreage or that have limited drilling or production history. From inception through June 30, 2012, after giving effect to the Transactions, we drilled a total of 159 gross wells and participated in an additional 15 gross non-operated wells, of which 160

 

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wells were completed as producing wells and 14 wells were in various stages of completion. If the wells in the process of being completed do not produce sufficient revenues to return a profit or if we drill dry holes in the future, our business may be materially affected.

Our identified potential drilling locations, which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

As of June 30, 2012, after giving effect to the Transactions, we had 925 identified potential vertical drilling locations on our existing acreage based on 40-acre spacing and an additional 1,122 identified potential vertical drilling locations based on 20-acre downspacing. Only 309 of these identified potential vertical drilling locations were attributed to proved reserves. These drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs and drilling results. Further, our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. We cannot predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable or whether wells drilled on 20-acre downspacing will produce at the same rates as those on 40-acre spacing. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Permian Basin may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. As of June 30, 2012 after giving effect to the Transactions, we had leases representing 160 net acres expiring in 2012, 222 net acres expiring in 2013, 2,065 net acres expiring in 2014, 17,846 net acres expiring in 2015 and 7,133 net acres expiring in 2016. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Any reduction in our current drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations. In addition, in order to hold our current leases expiring in 2014 and 2015, we will need to operate at least a four-rig program. We cannot assure you that we will have the liquidity to deploy these rigs in this time frame, or that commodity prices will warrant operating such a drilling program. Any such losses of leases could materially and adversely affect the growth of our asset basis, cash flows and results of operations.

 

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The volatility of oil and natural gas prices due to factors beyond our control greatly affects our profitability.

Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:

 

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the domestic and foreign supply of oil and natural gas;

 

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the level of prices and expectations about future prices of oil and natural gas;

 

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the level of global oil and natural gas exploration and production;

 

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the cost of exploring for, developing, producing and delivering oil and natural gas;

 

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the price of foreign imports;

 

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political and economic conditions in oil producing countries, including the Middle East, Africa, South America and Russia;

 

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the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

 

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speculative trading in crude oil and natural gas derivative contracts;

 

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the level of consumer product demand;

 

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weather conditions and other natural disasters;

 

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risks associated with operating drilling rigs;

 

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technological advances affecting energy consumption;

 

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domestic and foreign governmental regulations and taxes;

 

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the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;

 

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proximity and capacity of oil and natural gas pipelines and other transportation facilities;

 

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the price and availability of alternative fuels; and

 

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overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the past five years, the posted price for West Texas intermediate light sweet crude oil, which we refer to as West Texas Intermediate or WTI, has ranged from a low of $30.28 per barrel, or Bbl, in December 2008 to a high of $145.31 per Bbl in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $1.82 per million British thermal units, or MMBtu, in April 2012 to a high of $13.31 per MMBtu in July 2008. During 2011, West Texas Intermediate prices ranged from $75.40 to $113.39 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.84 to $4.92 per MMBtu. On March 31, 2012, the West Texas Intermediate posted price for crude oil was $103.03 per Bbl and the Henry Hub spot market price of natural gas was $2.02 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development results deteriorate, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties.

 

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We have entered into price swap derivatives and may in the future enter into forward sale contracts or additional price swap derivatives for a portion of our production, which may result in our making cash payments or prevent us from receiving the full benefit of increases in prices for oil and gas.

We use price swap derivatives to reduce price volatility associated with certain of our oil sales. Under these swap contracts, we receive a fixed price per barrel of oil and pay a floating market price per barrel of oil to the counterparty based on New York Mercantile Exchange Light Sweet Crude Oil pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. For the purpose of locking-in the value of a swap, we enter into counter-swaps from time to time. Under the counter-swap, we receive a floating price for the hedged commodity and pay a fixed price to the counterparty. The counter-swap is effective in locking-in the value of a swap since subsequent changes in the market value of the swap are entirely offset by subsequent changes in the market value of the counter-swap.

In December 2007, we placed a swap contract covering 1,680,000 Bbls of crude oil for the period from January 2008 to December 2012 at various fixed prices. In April 2008, we entered into a series of counter-swaps to lock-in the value of certain of these swaps settling 1,188,000 Bbls of crude oil swaps. In June 2009, we entered into an additional series of counter-swaps to lock-in the value of the remaining swaps settling 324,000 Bbls of crude oil swaps. Locking in the value of our swaps with counter-swaps, without entering into new swaps, exposes us to commodity price risks on the originally swapped position. As of December 31, 2010 and 2009, all of our swap contracts were locked-in with counter swaps. In October 2011, we placed a swap contract covering 1,000 Bbls per day of crude oil for the period from January 1, 2012 through December 31, 2013 at a price of $78.50 per barrel in 2012 and $80.55 per barrel in 2013. Such contracts and any future hedging arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in the price of oil. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.

Our hedging transactions expose us to counterparty credit risk.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract.

The inability of one or more of our customers to meet their obligations may adversely affect our financial results.

In addition to credit risk related to receivables from commodity derivative contracts, our principal exposure to credit risk is through receivables from joint interest owners on properties we operate (approximately $5.3 million at March 31, 2012) and receivables from purchasers of our oil and natural gas production (approximately $5.7 million at March 31, 2012). Joint interest receivables arise from billing entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We are generally unable to control which co-owners participate in our wells.

We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the three months ended March 31, 2012, three purchasers accounted for more than 10% of our revenue: Plains Marketing, L.P. (64%); Andrews Oil Buyers, Inc. (14%); and Occidental Energy Marketing, Inc. (13%). For the years ended December 31, 2011 and 2010, one purchaser, Windsor Midstream LLC, an entity controlled by Wexford, our equity sponsor, accounted for approximately 78% and 81% of our revenue, respectively. For the year ended December 31, 2009, two purchasers accounted for more than 10% of our revenue: Windsor Midstream LLC (68.3%) and DCP Midstream, LP (14.8%). No other customer accounted for more than 10% of our revenue during these periods. This concentration of customers may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Current

 

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economic circumstances may further increase these risks. We do not require our customers to post collateral. The inability or failure of our significant customers or joint working interest owners to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial results.

Our method of accounting for investments in oil and natural gas properties may result in impairment of asset value.

We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Income from services provided to working interest owners of properties in which we also own an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves. The average depletion rate per barrel equivalent unit of production was $23.00 and $26.42 for the three months ended March 31, 2012 and 2011, respectively, and $25.40, $17.78 and $11.21 for the years ended December 31, 2011, 2010 and 2009, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties for the three months ended March 31, 2012 and 2011 was $4.6 million and $3.6 million, respectively, and for the years ended December 31, 2011, 2010 and 2009 was $15.2 million, $7.4 million and $3.2 million, respectively.

The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment exceed the discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. Beginning December 31, 2009, we have used the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date in estimating discounted future net revenues.

No impairment on proved oil and natural gas properties was recorded for the years ended December 31, 2011, 2010 and 2009 or for the three months ended March 31, 2012 and 2011. We may experience additional ceiling test write downs in the future. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Method of accounting for oil and natural gas properties” beginning of page 78 of this prospectus for a more detailed description of our method of accounting.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may be incorrect. Our historical estimates of proved reserves and related valuations are based on reports prepared by Ryder Scott as of December 31, 2011 and by Pinnacle as of December 31, 2010 and 2009, each an independent petroleum engineering firm. The estimates of proved reserves and related valuations attributable to the Windsor UT properties and the properties subject to the Gulfport transaction are based, in each case, on reports prepared by Ryder Scott as of December 31, 2011. Ryder Scott and Pinnacle, as applicable, conducted a well-by-well review of all our

 

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properties for the periods covered by their respective reserve reports using information provided by us. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing and production. Also, certain assumptions regarding future oil and natural gas prices, production levels and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas we ultimately recover being different from our reserve estimates.

The estimates of reserves as of December 31, 2011, 2010 and 2009 included in this prospectus were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods ended December 31, 2011, 2010 and 2009, respectively, in accordance with the revised SEC guidelines applicable to reserves estimates for such periods. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage. The reserve estimates represent our net revenue interest in our properties.

The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves.

SEC rules that went into effect for fiscal years ending on or after December 31, 2009 could limit our ability to book additional proved undeveloped reserves in the future.

SEC rules that went into effect for fiscal years ending on or after December 31, 2009 require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.

Approximately 76% of our total estimated proved reserves at December 31, 2011 were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve engineer reports assumes that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.

Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in one major geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area.

All of our producing properties are geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services

 

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market limitations or interruption of the processing or transportation of crude oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

In addition to the geographic concentration of our producing properties described above, at December 31, 2011, all of our proved reserves were attributable to the Wolfberry play. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.

We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil and natural gas we produce.

The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of gas sold in interstate commerce. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. For the three months ended March 31, 2012, three purchasers accounted for more than 10% of our revenue: Plains Marketing, L.P. (64%); Andrews Oil Buyers, Inc. (14%); and Occidental Energy Marketing, Inc. (13%). For the years ended December 31, 2011 and 2010, one purchaser, Windsor Midstream LLC, an entity controlled by Wexford, our equity sponsor, accounted for approximately 78.4% and 81.7% of our revenue, respectively. For the year ended December 31, 2009, two purchasers accounted for more than 10% of our revenue: Windsor Midstream LLC (68.3%) and DCP Midstream, LP (14.8%). No other customer accounted for more than 10% of our revenue during these periods. We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production.

The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies or personnel may restrict our operations.

The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. In accordance with customary industry practice, we rely on independent third party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. In addition, we do not have long-term contracts securing the use of our existing rigs, and the operator of those rigs may choose to cease providing services to us. In addition, we intend to increase the number of rigs we have operating in 2012 and 2013. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use

 

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in our operations. According to the Lower Colorado River Authority, during 2011, Texas experienced the lowest inflows of water of any year in recorded history. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.

Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European debt crisis, the United States mortgage market and a declining real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil, natural gas and natural gas liquids, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad continues to deteriorate, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our oil, natural gas and natural gas liquids, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.

We have incurred losses from operations during certain periods since our inception and may do so in the future.

We incurred a net loss of $0.5 million for the year ended December 31, 2011. Our development of and participation in an increasingly larger number of drilling locations has required and will continue to require substantial capital expenditures. The uncertainty and risks described in this prospectus may impede our ability to economically find, develop and acquire oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows provided by operating activities in the future.

Part of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques; therefore, the results of our planned exploratory drilling in these plays are subject to drilling and completion technique risks and drilling results may not meet our expectations for reserves or production.

Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and consequently we are less able to predict future drilling results in these areas.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease

 

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expirations, access to gathering systems, and/or natural gas and oil prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and gas properties and the value of our undeveloped acreage could decline in the future.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. When these facilities are unavailable, our operations can be interrupted and our revenues reduced.

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our oil production is transported from the wellhead to our tank batteries by our gathering system. Our purchasers then transport the oil by truck to a pipeline for transportation. Our gas production is generally transported by our gathering lines from the wellhead to an interconnection point with the purchaser. We do not control these trucks and other third party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced, would adversely affect our financial condition and results of operations.

Our operations are subject to various governmental regulations which require compliance that can be burdensome and expensive.

Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operations. Moreover, these laws and regulations have continually imposed increasingly strict requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. We believe the trend of more expansive and stricter environmental legislation and regulations will continue. See “Business—Regulation—Environmental Matters and Regulation” and “Business—Regulation—Other Regulation of the Oil and Natural Gas Industry” beginning on pages 101 and 105, respectively, of this prospectus for a description of the laws and regulations that affect us.

 

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Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC, program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. The EPA, however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. At the same time, the Environmental Protection Agency, or EPA, has commenced a study of the potential environmental impacts of hydraulic fracturing activities, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. As part of these studies, both the EPA and the House committee have requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.

Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the Safe Drinking Water Act.

On April 17, 2012, EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds , or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule includes a 95 percent reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules will require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The federal government is currently undertaking several studies of hydraulic fracturing’s potential impacts, the results of which are expected between later in 2012 and 2014.

These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities.

Several states, including Texas, and the Department of the Interior, in a May 4, 2012 proposed rule covering federal lands, have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Railroad Commission recently adopted rules and regulations requiring that the well operator disclose

the list of chemical ingredients subject to the requirements of federal Occupational Safety and Health Act

 

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(OSHA) for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. We plan to use hydraulic fracturing extensively in connection with the development and production of certain of our oil and natural gas properties and any increased federal, state, local, foreign or international regulation of hydraulic fracturing could reduce the volumes of oil and gas that we can economically recover, which could materially and adversely affect our revenues and results of operations.

There has been increasing public controversy regarding hydraulic fracturing with regard to use of fracturing fluids, impacts on drinking water supplies, use of waters and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing, such as the FRAC Act, are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities.

We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to our exploration, development and production activities. These laws and regulations may require us to obtain a variety of permits or other authorizations governing our air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, producing and other operations; regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; require remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or impose substantial liabilities for spills, pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations.

Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. In addition, the risk of accidental spills or releases from our operations could expose us to significant liabilities under environmental laws. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The

 

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trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.

The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. The U.S. Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The new legislation was signed into law by the President on July 21, 2010, and requires the Commodities Futures Trading Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In its rulemaking under the new legislation, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. Although the CFTC has promulgated numerous final rules based on its proposals, it is not possible at this time to predict when the CFTC will finalize its proposed regulations or the effect of such regulations on our business. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our existing or future derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our derivative contracts in existence at that time, and increase our exposure to less creditworthy counterparties. If we reduce or change the way we use derivative instruments as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations or cash flows.

 

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Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations and cash flows.

The U.S. President’s Fiscal Year 2013 Budget Proposal includes provisions that would, if enacted, make significant changes to U.S. tax laws. These changes include, but are not limited to, (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) eliminating the deduction from income for domestic production activities relating to oil and natural gas exploration and development, (iii) the repeal of the of the percentage depletion allowance for oil and gas properties, (iv) an extension of the amortization period for certain geological and geophysical expenditures and (iv) implementing certain international tax reforms. These proposed changes in the U.S. tax laws, if adopted, or other similar changes that reduce or eliminate deductions currently available with respect to oil and natural gas exploration and development, could adversely affect our business, financial condition, results of operations and cash flows.

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce.

Many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas, and refined petroleum products, are “greenhouse gases,” or GHGs, regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol at this time, several states or geographic regions have adopted legislation and regulations to reduce emissions of greenhouse gases. Additionally, on April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts, et al. v. EPA, that the EPA has the authority to regulate carbon dioxide emissions from automobiles as “air pollutant” under the federal Clean Air Act. Thereafter, in December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Subsequently, the EPA adopted two sets of related rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule in April 2010 and it became effective January 2011, although it does not require immediate reductions in GHG emissions. The EPA adopted the stationary source rule, also known as the “Tailoring Rule,” in May 2010, and it also became effective January 2011, although it remains subject of several pending lawsuits filed by industry groups. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. In addition, the EPA has continued to adopt GHG regulations of other industries, such as the March 2012 proposed GHG rule restricting future development of coal-fired power plants. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the

 

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number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly.

Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry. Currently, while we are subject to certain federal GHG monitoring and reporting requirements, our operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Section 1(b) of the Natural Gas Act of 1938, or the NGA, exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission, or FERC. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish whether a pipeline performs a gathering function and therefore is exempt from FERC’s jurisdiction under the NGA. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is a fact-based determination. The classification of facilities as unregulated gathering is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress, which could cause our revenues to decline and operating expenses to increase and may materially adversely affect our business, financial condition or results of operations. In addition, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, which could have a material adverse effect on our business, financial condition or results of operations.

We rely on a few key employees whose absence or loss could adversely affect our business.

Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our new executive team, including our Chief Executive Officer, Travis D. Stice, could disrupt our operations. We have employment agreements with these executives which contain restrictions on competition with us in the event they cease to be employed by us. However, as a practical matter, such employment agreements may not assure the retention of our employees. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

A significant reduction by Wexford of its ownership interest in us could adversely affect us.

Prior to the Gulfport transaction, Wexford will beneficially own 100% of our equity interests. Upon completion of this offering, Wexford will beneficially own approximately     % of our common stock, or     % if the underwriters exercise in full their option to purchase additional shares. See “Principal and Selling Stockholders”

 

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beginning on page 133 of this prospectus. Further, we anticipate that several individuals who will serve as our directors upon completion of this offering will be affiliates of Wexford. We believe that Wexford’s substantial ownership interest in us provides Wexford with an economic incentive to assist us to be successful. Upon the expiration of the lock-up restrictions on transfers or sales of our securities by or on behalf of DB Holdings following the completion of this offering, Wexford will not be subject to any obligation to maintain its ownership interest in us and may elect at any time thereafter to sell all or a substantial portion of or otherwise reduce its ownership interest in us. If Wexford sells all or a substantial portion of its ownership interest in us, Wexford may have less incentive to assist in our success and its affiliate(s) that are expected to serve as members of our board of directors may resign. Such actions could adversely affect our ability to successfully implement our business strategies which could adversely affect our cash flows or results of operations. We also receive certain services, including drilling services from entities controlled by Wexford. These service contracts may generally be terminated on 30-days notice. In the event Wexford ceases to own a significant ownership interest in us, such services may not be available to us on terms acceptable to us, if at all.

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may result in a total loss of investment and adversely affect our business, financial condition or results of operations.

Our drilling activities are subject to many risks. For example, we cannot assure you that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such wells. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control, and increases in those costs can adversely affect the economics of a project. Further, our drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:

 

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unusual or unexpected geological formations;

 

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loss of drilling fluid circulation;

 

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title problems;

 

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facility or equipment malfunctions;

 

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unexpected operational events;

 

•

shortages or delivery delays of equipment and services;

 

•

compliance with environmental and other governmental requirements; and

 

•

adverse weather conditions.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties.

Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.

Historically, we have acquired significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be

 

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economically viable or that we will not abandon our investments. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.

Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.

Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of operations and repairs to resume operations.

We endeavor to contractually allocate potential liabilities and risks between us and the parties that provide us with services and goods, which include pressure pumping and hydraulic fracturing, drilling and cementing services and tubular goods for surface, intermediate and production casing. Under our agreements with our vendors, to the extent responsibility for environmental liability is allocated between the parties, (i) our vendors generally assume all responsibility for control and removal of pollution or contamination which originates above the surface of the land and is directly associated with such vendors’ equipment while in their control and (ii) we generally assume the responsibility for control and removal of all other pollution or contamination which may occur during our operations, including pre-existing pollution and pollution which may result from fire, blowout, cratering, seepage or any other uncontrolled flow of oil, gas or other substances, as well as the use or disposition of all drilling fluids. In addition, we generally agree to indemnify our vendors for loss or destruction of vendor-owned property that occurs in the well hole (except for damage that occurs when a vendor is performing work on a footage, rather than day work, basis) or as a result of the use of equipment, certain corrosive fluids, additives, chemicals or proppants. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into contractual arrangements with the terms that vary from the above allocations of risk. As a result, we may incur substantial losses which could materially and adversely affect our financial condition and results of operation.

In accordance with what we believe to be customary industry practice, we historically have maintained insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flow. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.

Since hydraulic fracturing activities are part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have no coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for

 

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all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

Our failure to successfully identify, complete and integrate future acquisitions of properties or businesses could reduce our earnings and slow our growth.

There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently operate, which could result in unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Completed acquisitions could require us to invest further in operational, financial and management information systems and to attract, retain, motivate and effectively manage additional employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.

Acquiring oil and gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

We may incur losses as a result of title defects in the properties in which we invest.

It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest.

Prior to the drilling of an oil or gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

 

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Competition in the oil and natural gas industry is intense, which may adversely affect our ability to succeed.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

We will be subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our profitability, stock price and results of operations and financial condition could be materially adversely affected.

We will be required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002 as early as December 31, 2013. Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls upon becoming a large accelerated filer, as defined in the SEC rules, or otherwise ceasing to qualify for an exemption from the requirement to provide auditors’ attestation on internal controls afforded to emerging growth companies under the “Jumpstart Our Business Startups Act” enacted by the U.S. Congress in April 2012. We are currently evaluating our existing controls against the standards adopted by the Committee of Sponsoring Organizations of the Treadway Commission. During the course of our ongoing evaluation and integration of the internal control over financial reporting, we may identify areas requiring improvement, and we may have to design enhanced processes and controls to address issues identified through this review. For example, we anticipate the need to hire additional administrative and accounting personnel to conduct our financial reporting.

We believe that the out-of-pocket costs, the diversion of management’s attention from running the day-to-day operations and operational changes caused by the need to comply with the requirements of Section 404 of the Sarbanes-Oxley Act could be significant. If the time and costs associated with such compliance exceed our current expectations, our results of operations could be adversely affected.

We cannot be certain at this time that we will be able to successfully complete the procedures, certification and attestation requirements of Section 404 or that we or our auditors will not identify material weaknesses in internal control over financial reporting. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report such material weaknesses, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our

 

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reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.

Increased costs of capital could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

We recorded compensation expense in 2011 and we may incur substantial additional compensation expense related to our future grants of stock compensation which may have a material negative impact on our operating results for the foreseeable future.

As a result of outstanding stock-based compensation awards, we recorded $0.5 million of compensation expense in 2011. In addition, our compensation expenses may increase in the future as compared to our historical expenses because of the costs associated with our existing and anticipated stock-based incentive plans. These additional expenses will adversely affect our net income. We cannot determine the actual amount of these new stock-related compensation and benefit expenses at this time because applicable accounting practices generally require that they be based on the fair market value of the options or shares of common stock at the date of the grant; however, they may be significant. We will recognize expenses for restricted stock awards and stock options generally over the vesting period of awards made to recipients.

Our level of indebtedness may increase and reduce our financial flexibility.

In the future, we may incur significant indebtedness in order to make future acquisitions or to develop our properties.

Our level of indebtedness could affect our operations in several ways, including the following:

 

•

a significant portion of our cash flows could be used to service our indebtedness;

 

•

a high level of debt would increase our vulnerability to general adverse economic and industry conditions;

 

•

the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

 

•

a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;

 

•

our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

 

•

a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; and

 

•

a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

 

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A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

Our revolving credit facility contains restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.

Our revolving credit facility contains restrictive covenants that limit our ability to, among other things:

 

•

incur additional indebtedness;

 

•

create additional liens;

 

•

sell assets;

 

•

merge or consolidate with another entity;

 

•

pay dividends or make other distributions;

 

•

engage in transactions with affiliates; and

 

•

enter into certain swap agreements.

In addition, our revolving credit facility requires us to maintain certain financial ratios and tests. The requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.

If we are unable to comply with the restrictions and covenants in our revolving credit facility, there could be an event of default under the terms of our revolving credit facility, which could result in an acceleration of repayment.

If we are unable to comply with the restrictions and covenants in our revolving credit facility, there could be an event of default under the terms of this facility. Our ability to comply with these restrictions and covenants, including meeting the financial ratios and tests under our revolving credit facility, may be affected by events beyond our control. As a result, we cannot assure that we will be able to comply with these restrictions and covenants or meet such financial ratios and tests. In the event of a default under our revolving credit facility, the lenders could terminate their commitments to lend or accelerate the loans and declare all amounts borrowed due and payable. If any of these events occur, our assets might not be sufficient to repay in full all of our outstanding indebtedness and we may be unable to find alternative financing. Even if we could obtain alternative financing, it might not be on terms that are favorable or acceptable to us. Additionally, we may not be able to amend our revolving credit facility or obtain needed waivers on satisfactory terms.

Our borrowings under our revolving credit facility expose us to interest rate risk.

Our earnings are exposed to interest rate risk associated with borrowings under our revolving credit facility, which bear interest at a rate elected by us that is based on the prime, LIBOR or federal funds rate plus margins ranging from 1.25% to 3.50% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. As of March 31, 2012, the weighted average interest rate on outstanding borrowings under our revolving credit facility was 3.3%. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.

 

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Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

Under our revolving credit facility, which currently provides for a $100.0 million borrowing base, we are subject to semi-annual and other elective collateral borrowing base redeterminations based on our oil and natural gas reserves. Our revolving credit facility currently provides that the borrowing base will remain at $100.0 million through July 15, 2013 or, if earlier, the closing date of this offering, at which time the borrowing base will be reduced to $90.0 million, subject to the periodic and elective borrowing base redeterminations discussed above, and without consideration of the impact of the Gulfport transaction and the Windsor UT properties. Any significant reduction in our borrowing base as a result of such borrowing base redeterminations or otherwise may negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial position, results of operation and cash flow.

Loss of our information and computer systems could adversely affect our business.

We are heavily dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Risks Related to this Offering and Our Common Stock

Our two largest stockholders control a significant percentage of our common stock, and their interests may conflict with those of our other stockholders.

Upon completion of this offering, Wexford and Gulfport will beneficially own approximately     % and     %, respectively, of our common stock, or     % and     %, respectively, if the underwriters exercise their option to purchase additional shares in full. See “Principal and Selling Stockholders” beginning on page 133 of this prospectus. In addition, individuals affiliated with Wexford and Gulfport serve on our Board of Directors, and Gulfport has the right to designate one individual as a nominee for election to our Board of Directors so long as it continues to beneficially own more than 10% of our outstanding common stock. As a result, Wexford and Gulfport, together, will be able to control, and Wexford alone will continue to be able to exercise significant influence over, matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our common stock will be able to affect the way we are managed or the direction of our business. The interests of Wexford and Gulfport with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders. This continued concentrated ownership will make it impossible for another company to acquire us and for you to receive any related takeover premium for your shares unless Wexford approves the acquisition.

 

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Since we are a “controlled company” for purposes of The NASDAQ Global Market’s corporate governance requirements, our stockholders will not have, and may never have, the protections that these corporate governance requirements are intended to provide.

Since we are a “controlled company” for purposes of The NASDAQ Global Market’s corporate governance requirements, we are not required to comply with the provisions requiring that a majority of our directors be independent, the compensation of our executives be determined by independent directors or nominees for election to our board of directors be selected by independent directors. If we choose to take advantage of any or all of these exemptions, our stockholders may not have the protections that these rules are intended to provide.

The corporate opportunity provisions in our certificate of incorporation could enable Wexford, our equity sponsor, or other affiliates of ours to benefit from corporate opportunities that might otherwise be available to us.

Subject to the limitations of applicable law, our certificate of incorporation, among other things:

 

•

permits us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested;

 

•

permits any of our stockholders, officers or directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and

 

•

provides that if any director or officer of one of our affiliates who is also one of our officers or directors becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as our director or officer), that director or officer will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer that opportunity to such affiliates and that director or officer will not be deemed to have (i) acted in a manner inconsistent with his or her fiduciary or other duties to us regarding the opportunity or (ii) acted in bad faith or in a manner inconsistent with our best interests.

These provisions create the possibility that a corporate opportunity that would otherwise be available to us may be used for the benefit of one of our affiliates.

We have engaged in transactions with our affiliates and expect to do so in the future. The terms of such transactions and the resolution of any conflicts that may arise may not always be in our or our stockholders’ best interests.

We have engaged in transactions and expect to continue to engage in transactions with affiliated companies. As described under the caption “Related Party Transactions” beginning on page 128 of this prospectus, these include, among others, drilling services provided to us to Bison Drilling and Field Services, LLC, real property leased by us from Fasken Midland, LLC and certain administrative services provided to us by Everest Operations Management LLC. Each of these entites is either controlled by or affiliated with Wexford, and the resolution of any conflicts that may arise in connection with such related party transactions, including pricing, duration or other terms of service, may not always be in our or our stockholders’ best interests because Wexford may have the ability to influence the outcome of these conflicts. For a discussion of potential conflicts, see “—Risks Related to this Offering and our Common Stock – Our two largest stockholders control a significant percentage of our common stock, and their interests may conflict with those of our other stockholders” on page 37 of this prospectus.

We will incur increased costs as a result of being a public company, which may significantly affect our financial condition.

As a public company, we will incur significant legal, accounting and other expenses that we did not incur as a private company. We will incur costs associated with our public company reporting requirements. We also anticipate that we will incur costs associated with corporate governance requirements, including requirements

 

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under the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the Financial Industry Regulatory Authority. We expect these rules and regulations to increase our legal and financial compliance costs and to make some activities more time-consuming and costly, particularly after we are no longer an “emerging growth company.” We also expect these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

However, for as long as we remain an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012, we intend to take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not “emerging growth companies” including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. We intend to take advantage of these reporting exemptions until we are no longer an “emerging growth company.”

We will remain an “emerging growth company” for up to five years, although if the market value of our common stock that is held by non-affiliates exceeds $700 million as of any June 30 before that time, we would cease to be an “emerging growth company” as of the following December 31.

After we are no longer an “emerging growth company,” we expect to incur significant additional expenses and devote substantial management effort toward ensuring compliance with those requirements applicable to companies that are not “emerging growth companies,” including Section 404 of the Sarbanes-Oxley Act. See “—Risks Related to the Oil and Natural Gas Industry and Our Business—We will be subject to certain requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our profitability, stock price and results of operations and financial condition could be materially adversely affected” on page 34 of this prospectus.

We are an “emerging growth company” and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies will make our common stock less attractive to investors.

We are an “emerging growth company,” as defined in the Jumpstart our Business Startups Act of 2012, and we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies, including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. We cannot predict if investors will find our common stock less attractive because we will rely on these exemptions. If some investors find our common stock less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.

Under the Jumpstart Our Business Startups Act, “emerging growth companies” can delay adopting new or revised accounting standards until such time as those standards apply to private companies. We have irrevocably elected not to avail ourselves to this exemption from new or revised accounting standards and, therefore, we will be subject to the same new or revised accounting standards as other public companies that are not “emerging growth companies.”

 

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There has been no public market for our common stock and if the price of our common stock fluctuates significantly, your investment could lose value.

Prior to this offering, there has been no public market for our common stock. Although we have applied to have our common stock listed on The NASDAQ Global Market, we cannot assure you that an active public market will develop for our common stock or that our common stock will trade in the public market subsequent to this offering at or above the initial public offering price. If an active public market for our common stock does not develop, the trading price and liquidity of our common stock will be materially and adversely affected. If there is a thin trading market or “float” for our stock, the market price for our common stock may fluctuate significantly more than the stock market as a whole. Without a large float, our common stock is less liquid than the stock of companies with broader public ownership and, as a result, the trading prices of our common stock may be more volatile. In addition, in the absence of an active public trading market, investors may be unable to liquidate their investment in us. The initial offering price, which will be negotiated between us and the underwriters, may not be indicative of the trading price for our common stock after this offering. In addition, the stock market is subject to significant price and volume fluctuations, and the price of our common stock could fluctuate widely in response to several factors, including:

 

•

our quarterly or annual operating results;

 

•

changes in our earnings estimates;

 

•

investment recommendations by securities analysts following our business or our industry;

 

•

additions or departures of key personnel;

 

•

changes in the business, earnings estimates or market perceptions of our competitors;

 

•

our failure to achieve operating results consistent with securities analysts’ projections;

 

•

changes in industry, general market or economic conditions; and

 

•

announcements of legislative or regulatory change.

The stock market has experienced extreme price and volume fluctuations in recent years that have significantly affected the quoted prices of the securities of many companies, including companies in our industry. The changes often appear to occur without regard to specific operating performance. The price of our common stock could fluctuate based upon factors that have little or nothing to do with our company and these fluctuations could materially reduce our stock price.

Future sales of our common stock, or the perception that such future sales may occur, may cause our stock price to decline.

Sales of substantial amounts of our common stock in the public market after this offering, or the perception that these sales may occur, could cause the market price of our common stock to decline. See “Shares Eligible for Future Sale” on page 138 of this prospectus. In addition, the sale of these shares could impair our ability to raise capital through the sale of additional common or preferred stock. After this offering, we will have              shares of common stock outstanding, excluding stock options. All of the shares sold in this offering, except for any shares purchased by our affiliates, will be freely tradable.

DB Holdings, Gulfport and our directors and executive officers will be subject to agreements that limit their ability to sell our common stock held by them. These holders cannot sell or otherwise dispose of any shares of our common stock for a period of at least 180 days after the date of this prospectus, which period may be extended under limited circumstances, without the prior written approval of Credit Suisse Securities (USA) LLC. However, these lock-up agreements are subject to certain specific exceptions, including transfers of common stock as a bona fide gift or by will or intestate succession and transfers to such person’s immediate family or to a trust or to an entity controlled by such holder, provided that the recipient of the shares agrees to be bound by the same restrictions on sales. In the event that one or more of our stockholders sells a substantial amount of our common stock in the public market, or the market perceives that such sales may occur, the price of our stock could decline.

 

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If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our stock or if our operating results do not meet their expectations, our stock price could decline.

The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our stock or if our operating results do not meet their expectations, our stock price could decline.

Purchasers in this offering will experience immediate dilution and will experience further dilution with the future exercise of stock options granted to certain of our executive officers under their respective employment agreements.

The initial public offering price is substantially higher than the pro forma net tangible book value per share of our outstanding common stock. As a result, you will experience immediate and substantial dilution of approximately $         per share, representing the difference between our net tangible book value per share as of          after giving effect to this offering and an assumed initial public offering price of $         (which is the midpoint of the range set forth on the cover of the prospectus). A $1.00 increase (decrease) in the assumed initial public offering price of $         per share (which is the midpoint of the range set forth on the cover page of this prospectus) would increase (decrease) our net tangible book value per share after giving effect to this offering by $        , and increase (decrease) the dilution to new investors by $        , assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offered expenses payable by us. If the options granted to certain of our executive officers under their respective employment agreements are exercised in full, the investors in this offering will experience further dilution. See “Dilution” beginning on page 46 of this prospectus for a description of dilution.

We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.

Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of the company, which could adversely affect the price of our common stock.

The existence of some provisions in our certificate of incorporation and bylaws and Delaware corporate law could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company difficult, including:

 

•

provisions regulating the ability of our stockholders to nominate directors for election or to bring matters for action at annual meetings of our stockholders;

 

•

limitations on the ability of our stockholders to call a special meeting and act by written consent;

 

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•

the ability of our board of directors to adopt, amend or repeal bylaws, and the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained for stockholders to amend our bylaws;

 

•

the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained to remove directors;

 

•

the requirement that the affirmative vote of holders representing at least 66 2/3% of the voting power of all outstanding shares of capital stock be obtained to amend our certificate of incorporation; and

 

•

the authorization given to our board of directors to issue and set the terms of preferred stock without the approval of our stockholders.

These provisions also could discourage proxy contests and make it more difficult for you and other stockholders to elect directors and take other corporate actions. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, which may limit the price that investors are willing to pay in the future for shares of our common stock.

We do not intend to pay cash dividends on our common stock in the foreseeable future, and therefore only appreciation of the price of our common stock will provide a return to our stockholders.

We currently anticipate that we will retain all future earnings, if any, to finance the growth and development of our business. We do not intend to pay cash dividends in the foreseeable future. Any future determination as to the declaration and payment of cash dividends will be at the discretion of our board of directors and will depend upon our financial condition, results of operations, contractual restrictions capital requirements, business prospects and other factors deemed relevant by our board of directors. In addition, the terms of our credit facilities prohibit us from paying dividends and making other distributions. As a result, only appreciation of the price of our common stock, which may not occur, will provide a return to our stockholders.

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

 

•

business strategy;

 

•

exploration and development drilling prospects, inventories, projects and programs;

 

•

oil and natural gas reserves;

 

•

identified drilling locations;

 

•

ability to obtain permits and governmental approvals;

 

•

technology;

 

•

financial strategy;

 

•

realized oil and natural gas prices;

 

•

production;

 

•

lease operating expenses, general and administrative costs and finding and development costs;

 

•

future operating results; and

 

•

plans, objectives, expectations and intentions.

All of these types of statements, other than statements of historical fact included in this prospectus, are forward-looking statements. These forward-looking statements may be found in the “Prospectus Summary,” “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business” beginning on pages 1, 16, 57 and 85, respectively, and other sections of this prospectus. In some cases, you can identify forward-looking statements by terminology such as “may,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “seek,” “objective” or “continue,” the negative of such terms or other comparable terminology.

The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, our management’s assumptions about future events may prove to be inaccurate. Our management cautions all readers that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the many factors including those described in the “Risk Factors” section and elsewhere in this prospectus. All forward-looking statements speak only as of the date of this prospectus. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

 

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USE OF PROCEEDS

Our net proceeds from the sale of              shares of common stock in this offering, assuming a public offering price of $         per share (which is the midpoint of the range set forth on the cover of this prospectus), are estimated to be $         million, after deducting underwriting discounts and commissions and estimated offering expenses. The net proceeds would be $         million if the underwriters’ option to purchase additional shares is exercised in full. At the closing of this offering, we intend to use approximately $         million of the net proceeds to repay outstanding borrowings under our revolving credit facility, $63.6 million to repay the Gulfport transaction note and $         million to repay outstanding borrowings under our subordinated note with an affiliate of Wexford and, thereafter, we intend to use the balance of the proceeds from this offering to fund a portion of our exploration and development activities and for general corporate purposes, which may include leasehold interest and property acquisitions, working capital and the settlement of crude oil swaps. Upon repayment of the outstanding borrowings under our revolving credit facility, we will have $         million of borrowing capacity under that facility to further fund our exploration and development activities and for general corporate purposes.

All borrowings under our revolving credit facility are due and payable on October 15, 2014. As of June 30, 2012, $100.0 million was outstanding under our revolving credit facility and bore interest at a weighted average rate of 3.74% per annum. The amounts initially borrowed under our revolving credit facility were used to repay in full the outstanding indebtedness under our prior credit facility and for general corporate purposes. The Gulfport transaction note, which will be issued immediately prior to the closing of this offering in connection with the Gulfport transaction, does not bear interest and is due upon completion of this offering.

All borrowings under our subordinated note are due and payable on January 31, 2015 or the earlier completion of this offering. On May 14, 2012, we received an initial advance of $8.1 million under this note which provides for aggregate outstanding borrowings of up to $25.0 million. On June 30, 2012, $14.1 million was outstanding under this note. The note bears interest at a rate equal to LIBOR plus 0.28% or 8% per annum, whichever is lower. Our borrowings under the subordinated note were used to fund our 2012 drilling program and for general corporate purposes.

We will not receive any proceeds from the sale of shares by the selling stockholders, including any sale the selling stockholders may make upon exercise of the underwriters’ option to purchase additional shares.

An increase or decrease in the initial public offering price of $1.00 per share would cause the net proceeds that we will receive in this offering to increase or decrease by approximately $             million. If our net proceeds are reduced, we will have less proceeds to fund our exploration and development activities and may not have sufficient funds to repay our revolving credit facility in full. Any reduction in net proceeds may cause us to need to borrow additional funds under our revolving credit facility to fund our operations, which would increase our interest expense and decrease our net income.

DIVIDEND POLICY

We have never declared or paid any cash dividends on our capital stock. We currently intend to retain all available funds and any future earnings for use in the operation and expansion of our business and do not anticipate declaring or paying any cash dividends in the foreseeable future. Any future determination as to the declaration and payment of dividends will be at the discretion of our board of directors and will depend on then-existing conditions, including our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors that our board of directors considers relevant. In addition, the terms of our revolving credit facility restrict the payment of dividends to the holders of our common stock and any other equity holders.

 

 

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CAPITALIZATION

The following table sets forth our cash and cash equivalents and capitalization as of March 31, 2012:

 

•

on an actual basis;

 

•

on a pro forma basis to give effect to the issuance of (a)              shares of our common stock to an affiliate of Wexford in exchange for its contribution to us of all the outstanding equity interests in Windsor Permian, (b)              shares of our common stock and the Gulfport transaction note to Gulfport in connection with the Gulfport transaction and (c) the distribution by Windsor Permian to its equity holders of its minority equity interests in Bison and Muskie; and

 

•

on a pro forma basis described above as adjusted to give effect to the sale of shares of our common stock in this offering at an assumed initial public offering price of $         per share (which is the midpoint of the range set forth on the cover of this prospectus), our receipt of an estimated $ million of net proceeds from this offering after deducting underwriting discounts and commissions and estimated offering expenses and the use of a portion of those proceeds to repay outstanding borrowings as described under the caption “Use of Proceeds” on page 44 of this prospectus.

You should read the following table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 57 and our consolidated financial statements and related notes appearing elsewhere in this prospectus.

 

		As of March 31, 2012
		Actual(1)				Pro Forma				Pro Forma As  Adjusted(2)
		(in thousands)
Cash and cash equivalents		$	9,043			$				$		(4)
Long term debt (including current maturities)(3)		$	97,450			$				$
Member’s equity			120,505				—				—
Stockholders’ equity:
Common stock, par value $0.01; 100 shares authorized and              shares issued and outstanding actual;              shares authorized and              shares issued and outstanding as adjusted for the offering			—
Additional paid-in capital			—
Accumulated deficit(5)			—
Total stockholders’ equity
Total capitalization		$	217,955			$				$

 

(1)

Diamondback Energy, Inc. was incorporated on December 30, 2011 in Delaware as a holding company and will not conduct any material business operations prior to the completion of the offering. The data in this table has been derived from the historical consolidated financial statements and other financial information included in this prospectus which pertain to the assets, liabilities, revenues and expenses of Windsor Permian LLC. Immediately prior to the completion of this offering, Windsor Permian LLC will become our wholly-owned subsidiary.

(2)

A $1.00 increase (decrease) in the assumed initial public offering price of $         per share (which is the midpoint of the range set forth on the cover of this prospectus) would increase (decrease) each of cash and cash equivalents, additional paid-in-capital and total capitalization by $        , assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

(3)	At June 30, 2012, long term debt was $114.1 million, which includes $14.1 million in borrowings under our subordinated note with an affiliate of Wexford and $2.6 million in additional borrowings under our revolving credit facility.

(4)

Does not reflect the repayment of $2.6 million in additional borrowings under our revolving credit facility or $14.1 million in borrowings under our subordinated note with an affiliate of Wexford, in each case borrowed subsequent to March 31, 2012, which repayment will reduce cash and cash equivalents by an aggregate of $16.7 million. See “Use of Proceeds.”

(5)

Upon completion of this offering, we will recognize deferred tax liabilities and assets for temporary differences between the historical cost basis and tax basis of our assets and liabilities. Based on estimates of those temporary differences as of March 31, 2012, a net deferred tax liability of approximately $27.1 million will be recognized with a corresponding charge to earnings.

 

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DILUTION

Our reported net tangible book value as of March 31, 2012 was $         million, or $         per share, based upon shares outstanding as of that date after giving pro forma effect to (a) the contribution to us of all of the outstanding equity interests in Windsor Permian, (b) the Gulfport transaction and (c) the distribution by Windsor Permian to its equity holders of its minority equity interests in Bison and Muskie. Net tangible book value per share is determined by dividing such number of outstanding shares of common stock into our net tangible book value, which is our total tangible assets less total liabilities. Assuming the sale by us of              shares of common stock offered in this offering at an estimated initial public offering price of $         per share (which is the midpoint of the range set forth on the cover of this prospectus) and after deducting the underwriting discounts and commissions and estimated offering expenses payable by us, our net tangible book value as of March 31, 2012 would have been approximately $         million, or $         per share, after giving pro forma effect to (a) the contribution to us of all of the outstanding equity interests in Windsor Permian, (b) to the Gulfport transaction and (c) the distribution by Windsor Permian to its equity holders of its minority equity interests in Bison and Muskie. This represents an immediate increase in net tangible book value of $         per share to our existing stockholders and an immediate dilution of $         per share to new investors purchasing shares at the initial public offering price.

The following table illustrates the per share dilution:

 

Assumed initial public offering price per share						$
Pro forma net tangible book value per share as of March 31, 2012		$
Increase per share attributable to new investors		$
As adjusted net tangible book value per share after the offering						$
Dilution per share to new investors						$

A $1.00 increase (decrease) in the assumed initial public offering price of $         per share (which is the midpoint of the range set forth in the cover of this prospectus) would increase (decrease) our net tangible book value after the offering by $        , and increase (decrease) the dilution to new investors by $        , assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

The following table sets forth, as of March 31, 2012, after giving pro forma effect to the contribution to us by DB Holdings of all of the outstanding equity interests in Windsor Permian and to the Transactions, the number of shares of common stock to be issued by us to DB Holdings and Gulfport, which will be our existing stockholders immediately prior to this offering, and by the new investors at the assumed initial public offering price of $         per share, together with the total consideration paid and average price per share paid by each of these groups, before deducting underwriting discounts and commissions and estimated offering expenses.

 

		Shares Purchased						Total Consideration								Average Price
		Number		Percent				Amount				Percent				Per Share
Existing stockholders						%		$						%		$
New investors						%								%
Total					100.0	%		$					100.0	%		$

If the underwriters’ option to purchase additional shares is exercised in full, the number of shares held by new investors will be increased to             , or approximately     % of the total number of shares of common stock.

The data in the table excludes              shares of common stock reserved for issuance under our equity incentive plan.

 

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SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

The following selected historical consolidated financial data as of December 31, 2011 and 2010 and for each of the years in the three-year period ended December 31, 2011 are derived from our audited consolidated financial statements included elsewhere in this prospectus. The selected consolidated balance sheet data as of December 31, 2009 and 2008 and the selected historical consolidated financial data for 2008 and the period from inception on October 23, 2007 to December 31, 2007 are derived from our audited financial statements not included in this prospectus. The balance sheet data as of December 31, 2007 is derived from our unaudited financial statements not included in this prospectus. The summary consolidated financial data as of March 31, 2012 and for the three months ended March 31, 2012 and 2011 are derived from our historical unaudited consolidated financial statements included elsewhere in this prospectus. The summary consolidated balance sheet data as of March 31, 2011 are derived from our unaudited consolidated balance sheet as of such date, which is not included in this prospectus. The unaudited pro forma data presented gives effect to income taxes assuming that the Company operated as a taxable corporation throughout the periods presented. Operating results for the periods ended December 31, 2011, 2010, 2009, 2008 and 2007 and the three months ended March 31, 2012 and 2011 are not necessarily indicative of results that may be expected for any future periods. You should review this information together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 57 and our historical consolidated financial statements and related notes included elsewhere in this prospectus.

 

		Three Months Ended March 31,								Year Ended December 31,																Period from Inception (October 23, 2007) to December 31, 2007
		2012				2011				2011				2010				2009				2008
Statement of Operations Data:
Oil and natural gas revenues		$	16,004,507			$	10,583,902			$	47,180,802			$	26,441,927			$	12,716,011			$	18,238,692			$	578,336
Other revenues			—				1,490,910				1,490,910				811,247				—				—				—
Expenses:
Lease operating expense			2,681,850				2,196,959				10,345,355				4,588,559				2,366,623				3,375,419				25,684
Production taxes			780,574				523,415				2,333,853				1,346,879				663,068				1,008,991				136,077
Gathering and transportation			67,232				35,482				201,828				105,870				42,091				53,407				2,637
Oil and natural gas services			—				1,732,892				1,732,892				811,247				—				—				—
Depreciation, depletion and amortization			4,664,942				3,616,694				15,402,826				8,145,143				3,215,891				10,199,581				138,066
Impairment of oil and gas properties			—				—				—				—				—				83,164,230				—
General and administrative			1,191,402				601,048				3,603,479				3,051,627				5,062,618				5,459,874				6,609
Asset retirement obligation accretion expense			19,855				13,691				63,259				37,856				27,934				23,569				514
Total expenses			9,405,855				8,720,181				33,683,492				18,087,181				11,378,225				103,285,071				309,587
Income (loss) from operations			6,598,652				3,354,631				14,988,220				9,165,993				1,337,786				(85,046,379	)			268,749
Other income (expense):
Interest income			1,310				4,212				11,197				34,474				35,075				625,086				23,581
Interest expense			(881,469	)			(495,768	)			(2,528,058	)			(836,265	)			(10,938	)			—				—
Other income			445,360				—				—				—				—				—				—
Loss on derivative contracts			(4,792,104	)			(12,144	)			(13,009,393	)			(147,983	)			(4,068,005	)			(9,528,220	)			(4,791,587	)
Loss from equity investment			(12,618	)			—				(7,017	)			—				—				—				—
Total other income (expense), net			(5,239,521	)			(503,670	)			(15,533,271	)			(949,774	)			(4,043,868	)			(8,903,134	)			(4,768,006	)
Net income (loss)		$	1,359,131			$	2,850,961			$	(545,051	)		$	8,216,219			$	(2,706,082	)		$	(93,949,513	)		$	(4,499,257	)
Pro Forma C Corporation Data:(1)
Net income (loss) before income taxes		$	1,359,131			$	2,850,961			$	(545,051	)		$	8,216,219			$	(2,706,082	)		$	(93,949,513	)		$	(4,499,257	)
Pro forma for income taxes			—				—				—				—				—				—				—
Pro forma net income (loss)		$	1,359,131			$	2,850,961			$	(545,051	)		$	8,216,219			$	(2,706,082	)		$	(93,949,513	)		$	(4,499,257	)
Pro forma income (loss) per common share — basic and diluted(2)		$								$
Weighted average pro forma shares outstanding — basic and diluted(2)

 

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		Three Months Ended March 31,								Year Ended December 31,																Period from Inception (October 23, 2007) to December 31, 2007
		2012				2011				2011				2010				2009				2008
Selected Cash Flow and Other Financial Data:
Net income (loss)		$	1,359,131			$	2,850,961			$	(545,051	)		$	8,216,219			$	(2,706,082	)		$	(93,949,513	)		$	(4,499,257	)
Depreciation, depletion and amortization			4,664,942				4,119,183				15,905,315				8,145,143				3,215,891				10,199,581				138,066
Other non-cash items			5,219,203				79,017				13,844,010				344,461				4,108,464				92,716,019				4,792,101
Change in operating assets and liabilities			7,913,176				(1,481,267	)			1,179,920				(11,529,999	)			(1,916,707	)			3,076,317				(2,448,557	)
Net cash provided by (used in) operating activities		$	19,156,452			$	5,567,894			$	30,384,194			$	5,175,824			$	2,701,566			$	12,042,404			$	(2,017,647	)
Net cash used in investing activities		$	(33,170,446	)		$	(21,956,058	)		$	(76,314,042	)		$	(53,134,641	)		$	(32,149,617	)		$	(84,196,562	)		$	(86,863,149	)
Net cash provided by financing activities		$	16,254,970			$	13,383,313			$	48,642,492			$	49,618,254			$	23,849,250			$	80,182,600			$	88,881,463
		As of March 31,								As of December 31,
		2012				2011				2011				2010				2009				2008				2007
Balance sheet data:
Cash and cash equivalents		$	9,043,365			$	1,084,894			$	6,802,389			$	4,089,745			$	2,430,308			$	8,029,109			$	667
Other current assets			18,538,686				22,528,411				24,130,450				20,947,659				2,263,097				1,389,810				2,489,231
Oil and gas properties, net — using full cost method of accounting			226,666,696				149,981,335				206,342,604				135,782,510				89,777,517				73,786,284				83,375,502
Well equipment to be used in development of oil and gas properties			—				—				—				—				5,413,310				8,503,178				—
Other property and equipment, net			803,624				3,425,849				684,015				11,059,220				105,564				161,103				—
Other assets			11,988,435				12,117,548				11,524,427				637,562				82,813				—				—
Total assets		$	267,040,806			$	189,138,037			$	249,483,885			$	172,516,696			$	100,072,609			$	91,869,484			$	85,865,400
Current liabilities		$	53,473,247			$	20,753,627			$	42,418,305			$	20,010,276			$	13,972,080			$	18,011,452			$	126,757
Note payable credit facility-long term			85,000,000				58,300,000				85,000,000				44,766,687				—				—				—
Derivative contracts-long term			6,926,100				767,301				6,138,573				1,373,864				1,416,431				2,868,452				1,141,587
Asset retirement obligations			1,136,123				828,105				1,079,725				727,826				481,887				374,287				214,850
Members’ equity			120,505,336				108,489,004				114,847,282				105,638,043				84,202,211				70,615,293				84,382,206
Total liabilities and members’ equity		$	267,040,806			$	189,138,037			$	249,483,885			$	172,516,696			$	100,072,609			$	91,869,484			$	85,865,400
		Three Months Ended March 31,								Year Ended December 31,																Period from Inception (October 23, 2007) to December 31, 2007
		2012				2011				2011				2010				2009				2008
Other financial data:
Adjusted EBITDA(3)		$	12,008,611			$	7,491,717			$	31,505,264			$	17,383,466			$	4,616,686			$	8,966,087			$	430,910

 

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Index to Financial Statements

 

(1)

Diamondback Energy, Inc. was incorporated on December 30, 2011 in Delaware as a holding company and will not conduct any material business operations prior to the transaction described below. Our historical consolidated financial statements and other financial information included in this prospectus pertain to assets, liabilities, revenues and expenses of Windsor Permian LLC, which is an entity controlled by our equity sponsor, Wexford. Windsor Permian LLC was treated as a partnership for federal income tax purposes. As a result, essentially all of Windsor Permian LLC’s taxable earnings and losses were passed through to Wexford, and Windsor Permian LLC did not pay federal income taxes at the entity level. Prior to the completion of this offering, Windsor Permian LLC will become our wholly-owned subsidiary and, because we are a subchapter C corporation under the Internal Revenue Code, the earnings at Windsor Permian LLC will become subject to federal income tax. For comparative purposes, we have included pro forma financial data to give effect to income taxes assuming the earnings of Windsor Permian LLC had been subject to federal income tax as a subchapter C corporation in all periods presented in the accompanying table. If the earnings of Windsor Permian LLC had been subject to federal income tax as a subchapter C corporation during the periods presented herein, we would have incurred net operating losses for income tax purposes in each period presented. We would have been in a net deferred tax asset, or DTA, position as a result of such tax losses and would have recorded a valuation allowance to reduce each period’s DTA balance to zero. A valuation allowance to reduce each period’s DTA would have resulted in an equal and offsetting credit for the respective expenses or an equal and offsetting debit for the respective benefits for income taxes, with the resulting tax expenses for each of the above periods of zero. The unaudited pro forma data is presented for informational purposes only, and does not purport to project our results of operations for any future period or our financial position as of any future date.

(2)

Unaudited pro forma basic and diluted income (loss) per share will be presented for the latest fiscal year and interim period on the basis of the aggregate number of shares to be issued to DB Holdings in connection with its contribution to us of all of the outstanding equity interests in Windsor Permian LLC to us, upon determination of the number of those shares.

(3)

Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDA as net income (loss) before loss on derivative contracts, interest expense, depreciation, depletion and amortization, impairment of oil and gas properties, non-cash equity based compensation and asset retirement obligation accretion expense. Adjusted EBITDA is not a measure of net income (loss) as determined by United States’ generally accepted accounting principles, or GAAP. Management believes Adjusted EBITDA is useful because it allows it to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measure of other companies or to such measure in our credit facility.

The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income (loss).

 

		Three Months Ended March 31,								Year Ended December 31,																Period from Inception (October 23, 2007) to December 31, 2007
		2012				2011				2011				2010				2009				2008
Reconciliation of Adjusted EBITDA to net income (loss):
Net income (loss)		$	1,359,131			$	2,850,961			$	(545,051	)		$	8,216,219			$	(2,706,082	)		$	(93,949,513	)		$	(4,499,257	)
Loss on derivative contracts			4,792,104				12,114				13,009,393				147,983				4,068,005				9,528,220				4,791,587
Interest expense			881,469				495,768				2,528,058				836,265				10,938				—				—
Depreciation, depletion and amortization			4,664,942				4,119,183				15,905,315				8,145,143				3,215,891				10,199,581				138,066
Impairment of oil and gas properties			—				—				—				—				—				83,164,230				—
Equity-based compensation expense			291,110				—				544,290				—				—				—				—
Asset retirement obligation accretion expense			19,855				13,691				63,259				37,856				27,934				23,569				514
Adjusted EBITDA		$	12,008,611			$	7,491,717			$	31,505,264			$	17,383,466			$	4,616,686			$	8,966,087			$	430,910

 

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UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Diamondback Energy, Inc.

Unaudited Pro Forma Condensed Consolidated Financial Statements

Introduction

The following unaudited pro forma condensed consolidated financial statements and related notes of the Company have been prepared to show the effect of the Transactions and the distribution by Windsor Permian to its equity holders of its minority equity interests in Bison and Muskie. The unaudited pro forma condensed consolidated financial statements should be read together with the historical financial statements of Windsor Permian and Windsor UT and the historical Statements of Revenues and Direct Operating Expenses of certain property interests of Gulfport Energy Corporation included in this prospectus. The accompanying unaudited pro forma condensed consolidated financial statements are based on assumptions and include adjustments as explained in the accompanying notes.

The acquisition of certain property interests of Gulfport Energy Corporation (the Gulfport properties) will be treated as a business combination accounted for under the acquisition method of accounting with the identifiable assets recognized at fair value on the date of transfer.

The Windsor UT contribution is treated as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in the accounts of the transferring entity at the date of transfer.

The pro forma data presented reflect events directly attributable to the Transactions and other described transactions and certain assumptions the Company believes are reasonable. The pro forma data are not necessarily indicative of financial results that would have been attained had the described transactions occurred on the dates indicated below. The pro forma data also necessarily exclude various operation expenses related to the Gulfport properties and the financial statements should not be viewed as indicative of operations in future periods. As the current operator of the properties to be acquired by the Company upon completion of the Gulfport transaction and the Windsor UT contribution, the Company does not expect any material impact from these transactions on its existing employees or infrastructure.

The Transactions will be completed immediately prior to the effectiveness of the registration statement of which this prospectus is a part and the distribution of the equity interests in Bison and Muskie occurred in June 2012.

The unaudited pro forma condensed consolidated balance sheet assumes that the Transactions and other described transactions occurred on March 31, 2012. The unaudited pro forma condensed consolidated statement of operations for the year ended December 31, 2011 and for the three months ended March 31, 2012 assumes that the Transactions and other described transactions occurred on January 1, 2011.

 

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Diamondback Energy, Inc.

Unaudited Pro Forma Condensed Consolidated Balance Sheet

March 31, 2012

 

		Windsor Permian Historical				Windsor UT Historical				Pro Forma Adjustments				Pro Forma
Assets
Cash and cash equivalents		$	9,043,365			$	199,390			$				$
Other current assets			18,538,686				123,673
Total current assets			27,582,051				323,063
Oil and natural gas properties, net using full cost method of accounting			226,666,696				14,122,101					(a)
Other property and equipment			803,624				—
Other assets			11,988,435				—					(b)
Total assets		$	267,040,806			$	14,445,164
Liabilities and Members’ Equity
Current liabilities		$	53,473,247			$	112,820					(a)
Note payable credit facility-long term			85,000,000				—
Derivative contracts-long term			6,926,100				—
Asset retirement obligations			1,136,123				24,716					(c)
Deferred income taxes			—				—					(e)
Members’ equity			120,505,336				14,307,628					(a)(c)(e)
Total liabilities and members’ equity		$	267,040,806			$	14,445,164			$				$

 

The accompanying notes are an integral part of these unaudited pro forma condensed consolidated financial statements.

 

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Diamondback Energy, Inc.

Unaudited Pro Forma Condensed Consolidated Statement of Operations

Year ended December 31, 2011

 

		Windsor Permian Historical				Gulfport Transaction Historical				Windsor UT Historical				Pro Forma Adjustments				Pro Forma
Revenues:
Oil and natural gas revenues		$	47,180,802			$	23,052,000			$	694,666			$				$
Oil and natural gas services			1,490,910				—				—				(b	)
Total revenues			48,671,712				23,052,000				694,666
Costs and expenses:
Lease operating expenses			10,345,355				5,484,000				251,824
Production taxes			2,333,853				1,276,000				32,016
Gathering and transportation			201,828				—				—
Oil and natural gas services			1,732,892				—				—					(b)
Depreciation, depletion and amortization			15,402,826				—				198,712					(d)
General and administrative expenses			3,603,479				—				37,044
Asset retirement obligation accretion expense			63,259				—				1,255					(c)
Total costs and expenses			33,683,492				6,760,000				520,851
Income from operations			14,988,220				16,292,000				173,815
Other income (expense)
Interest income			11,197				—				—
Interest expense			(2,528,058	)			—				—
Loss on derivative contracts			(13,009,393	)			—				—
Loss from equity investment			(7,017	)			—				—
Total other expense, net			(15,533,271	)			—				—
Net income (loss)		$	(545,051	)		$	16,292,000			$	173,815
Pro forma income (loss) before income taxes
Pro forma for income taxes(f)
Pro forma net income (loss)														$				$
Pro forma income (loss) per common share — basic and diluted(g)														$				$
Weighted average pro forma shares outstanding — basic and diluted(g)

 

The accompanying notes are an integral part of these unaudited pro forma condensed consolidated financial statements.

 

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Diamondback Energy, Inc.

Unaudited Pro Forma Condensed Consolidated Statement of Operations

Three Months ended March 31, 2012

 

		Windsor Permian Historical				Gulfport Transaction Historical				Windsor UT Historical				Pro Forma Adjustments				Pro Forma
Revenues:
Oil and natural gas revenues		$	16,004,507			$	7,270,000			$	346,900			$				$
Costs and expenses:
Lease operating expenses			2,681,850				2,052,000				107,284
Production taxes			780,574				376,000				15,986
Gathering and transportation			67,232				—				—
Oil and natural gas services			—				—				—					(b)
Depreciation, depletion and amortization			4,664,942				—				92,148					(d)
General and administrative expenses			1,191,402				—				12,753
Asset retirement obligation accretion expense			19,855				—				449					(c)
Total costs and expenses			9,405,855				2,428,000				228,620
Income from operations			6,598,652				4,842,000				118,280
Other income (expense)
Interest income			1,310				—				—
Interest expense			(881,469	)			—				—
Other income			445,360				—				—
Loss on derivative contracts			(4,792,104	)			—				—
Loss from equity investment			(12,618	)			—				—
Total other expense, net			(5,239,521	)			—				—
Net income (loss)		$	1,359,131			$	4,842,000			$	118,280
Pro forma income (loss) before income taxes
Pro forma for income taxes(f)
Pro forma net income (loss)														$				$
Pro forma income (loss) per common share—basic and diluted(g)														$				$
Weighted average pro forma shares outstanding—basic and diluted(g)

 

The accompanying notes are an integral part of these unaudited pro forma condensed consolidated financial statements.

 

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Diamondback Energy, Inc.

Notes to Unaudited Pro Forma Condensed Consolidated

Financial Statements

1. Basis of Presentation

The historical financial information is derived from the historical financial statements of Windsor Permian and Windsor UT and the historical statements of revenues and direct operating expenses of certain property interests of Gulfport. The unaudited pro forma condensed consolidated balance sheet as of March 31, 2012 has been prepared as if the Transactions and other described transactions had taken place on March 31, 2012. The unaudited pro forma condensed consolidated statement of operations for the year ended December 31, 2011 and the three months ended March 31, 2012 assumes that the Transactions and other described transactions had occurred on January 1, 2011.

2. Pro Forma Assumptions and Adjustments

We made the following adjustments in the preparation of the unaudited pro forma condensed consolidated financial statements.

 

(a)

To record the acquisition of the Gulfport properties at fair value for              shares of our common stock, which will represent 35% of our outstanding common stock immediately prior to the closing of this offering, and $63,590,050 in the form of a non-interest bearing promissory note that will be repaid in full upon the closing of this offering. The allocation of the purchase price to the assets acquired is preliminary and, therefore, subject to change.

 

(b)	To record the distribution of minority equity interests in Bison and Muskie to Windsor Permian’s sole member prior to the contribution of Windsor Permian to us.

 

(c)	To record incremental accretion of discount on asset retirement obligation associated with the Gulfport transaction.

 

(d)	To record incremental depletion, depreciation, and amortization of oil and natural gas properties associated with the Transactions, amortized on a unit-of-production basis over the remaining life of total proved reserves, as applicable, due to the following:

 

Purchase accounting basis adjustment for Gulfport properties		$
Using a larger quantity of reserves in the units of production computation
Total incremental depletion, depreciation and amortization		$

 

(e)

To record estimated net deferred tax liabilities for temporary differences between the historical cost basis and tax basis of our assets and liabilities as the result of our change in tax status to a subchapter C corporation. A corresponding charge to earnings has not been reflected in the pro forma Statement of Operations, as the charge is considered non-recurring.

 

(f)

To record the effect of income taxes assuming earnings had been subject to federal income tax as a subchapter C corporation in all periods presented. If the earnings had been subject to federal income tax as a subchapter C corporation during the periods presented, we would have incurred net operating losses for income tax purposes in each period presented. Additionally, we would have been in a net deferred tax asset, or DTA, position as a result of such tax losses and would have recorded a valuation allowance to reduce each period’s DTA balance to zero. A valuation allowance to reduce each period’s DTA would have resulted in an equal and offsetting credit for the respective expenses or an equal and offsetting debit for the respective benefits for income taxes, with the resulting tax expenses for each period of zero.

 

(g)	To report basic and diluted income (loss) per share on the basis of the aggregate number of shares to be issued in connection with the Gulfport transaction and to DB Holdings in connection with the contribution to us of all of the outstanding equity interests in Windsor Permian LLC.

 

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Diamondback Energy, Inc.

Notes to Unaudited Pro Forma Condensed Consolidated

Financial Statements

 

3. Oil and Natural Gas Producing Activities

The following table presents estimated unaudited pro forma volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2011 and changes in proved reserves during the year, assuming continuation of economic conditions prevailing at the end of the year. The weighted average prices at December 31, 2011 used for reserve report purposes are $93.09 per Bbl of oil, $56.62 per Bbl of natural gas liquids and $3.96 per Mcf of natural gas, respectively.

The Company emphasizes that the volumes of reserves shown below are estimates which, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data.

 

		Year Ended December 31, 2011
		Windsor Permian Historical												Gulfport Transaction Historical												Windsor UT Historical												Total Pro Forma
		Oil (MBbls)				Natural Gas Liquids (MBbls)				Natural Gas (MMcf)				Oil (MBbls)				Natural Gas Liquids (MBbls)				Natural Gas (MMcf)				Oil (MBbls)				Natural Gas Liquids (MBbls)				Natural Gas (MMcf)				Oil (MBbls)				Natural Gas Liquids (MBbls)				Natural Gas (MMcf)
Proved Developed and Undeveloped Reserves:
As of January 1, 2011			18,819				5,564				21,662				9,358				3,107				11,926				811				269				1,033				28,988				8,940				34,621
Extensions, discoveries and other additions			1,706				448				1,824				764				217				992				94				18				60				2,564				683				2,876
Revisions of prior reserve estimates			(3,366	)			(1,162	)			(3,454	)			(1,828	)			(474	)			(599	)			487				(1	)			(160	)			(4,707	)			(1,637	)			(4,213	)
Production			(442	)			(87	)			(413	)			(208	)			(59	)			(273	)			(8	)			—				—				(658	)			(146	)			(686	)
As of December 31, 2011			16,717				4,763				19,619				8,086				2,791				12,046				1,384				286				933				26,187				7,840				32,598
Proved Developed Reserves:
January 1, 2011			3,308				1,105				4,255				1,840				794				3,048				64				21				82				5,212				1,920				7,385
December 31, 2011			3,805				1,233				5,187				2,097				706				3,050				144				30				99				6,046				1,969				8,336
Proved Undeveloped Reserves:
January 1, 2011			15,511				4,459				17,407				7,518				2,313				8,878				747				248				951				23,776				7,020				27,236
December 31, 2011			12,912				3,530				14,432				5,989				2,085				8,996				1,240				256				834				20,141				5,871				24,262

 

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Diamondback Energy, Inc.

Notes to Unaudited Pro Forma Condensed Consolidated

Financial Statements

The following pro forma standardized measure of discounted estimated future net cash flows and changes therein relating to the combined proved oil and natural gas reserves of Windsor Permian and the Transactions as of and for the year ended December 31, 2011 were made in accordance with the provisions of the FASB ASU 2010-03, “Extractive Activities—Oil and Gas (Topic 932).”

 

		Year Ended December 31, 2011
		Windsor Permian Historical				Gulfport Transaction Historical				Windsor UT Historical				Pro Forma Adjustments				Total Pro Forma
Future cash flows		$	1,900,958,750			$	960,918,000			$	148,561,281			$	—			$	3,010,438,031
Future development costs			(373,750,281	)			(236,336,000	)			(36,600,000	)			—				(646,686,281	)
Future production costs			(458,936,062	)			(166,899,000	)			(38,872,202	)			—				(664,707,264	)
Future production taxes			(97,444,617	)			(50,235,000	)			(7,410,910	)			—				(155,090,527	)
Future income taxes			—				—				—				(500,721,253	)			(500,721,253	)
Future net cash flows			970,827,790				507,448,000				65,678,169				(500,721,253	)			1,043,232,706
10% discount to reflect timing of cash flows			(623,808,665	)			(305,160,000	)			(48,085,065	)			316,869,273				(660,184,457	)
Standardized measure of discounted future net cash flows		$	347,019,125			$	202,288,000			$	17,593,104			$	(183,851,980	)		$	383,048,249

The primary changes in the pro forma standardized measure of discounted estimated future net cash flows were as follows for 2011:

 

		Year Ended December 31, 2011
		Windsor Permian Historical				Gulfport Transaction Historical				Windsor UT Historical				Pro Forma Adjustments				Total Pro Forma
Sales and transfers of oil and gas produced, net of production costs		$	(34,299,766	)		$	(16,292,000	)		$	(410,826	)		$	—			$	(51,002,592	)
Net changes in prices and production costs and development costs			86,655,407				48,089,000				383,765				—				135,128,172
Extension and discoveries			69,375,680				29,432,000				4,195,434				—				103,003,114
Revisions of previous quantity estimates, less related production costs			(100,433,225	)			(71,088,000	)			1,899,993				—				(169,621,232	)
Accretion of discount			33,035,782				16,211,000				864,314				—				50,111,096
Change in production rates and other			(37,672,573	)			33,830,000				2,017,284				—				(1,825,289	)
Acquisition of Gulfport properties			—				—				—				162,106,000				162,106,000
Contribution of Windsor UT			—				—				—				8,643,140				8,643,140
Net change in income taxes			—				—				—				(70,742,868	)			(70,742,868	)
Total change in standardized measure of discounted future net cash flows		$	16,661,305			$	40,182,000			$	8,949,964			$	100,006,272			$	165,799,541

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the “Selected Historical Consolidated Financial Data” and the combined financial statements and related notes included elsewhere in this prospectus. This discussion contains forward-looking statements reflecting our current expectations and estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” appearing elsewhere in this prospectus.

Overview

We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, long-life, onshore oil and natural gas reserves in the Permian Basin in West Texas. We intend to grow our reserves and production through development drilling, exploitation and exploration activities on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves.

We intend to increase stockholder value by profitably growing reserves and production, primarily through drilling operations. We seek high quality exploration and development projects with potential for providing long-term drilling inventories that generate high returns. Substantially all of our revenues are generated through the sale of oil, natural gas liquids and natural gas production. Our production was approximately 74% oil, 15% natural gas liquids and 11% natural gas for both the year ended December 31, 2011 and the three months ended March 31, 2012.

We began operations in December 2007 with our acquisition of certain strategic oil and gas properties located in the Permian Basin of West Texas from ExL Petroleum, LP, Ambrose Energy I, Ltd. and certain other sellers for approximately $85.0 million. Through this transaction, we acquired 4,134 net acres with production at the time of acquisition of approximately 800 net barrels of oil equivalent, or BOE/d, from 34 gross (16.8 net) wells. Subsequently, we acquired approximately 26,875 additional net acres, which brought our total net acreage position in the Permian Basin to approximately 31,009 net acres at June 30, 2012 and, after giving effect to the Transactions, we had 51,623 net acres in the Permian Basin. Since our initial acquisition in the Permian Basin through June 30, 2012, we drilled or participated in the drilling of 169 gross (101 net) wells (or 174 gross (153 net) wells after giving effect to the Transactions) on our acreage in this area, primarily targeting the Wolfberry play. We are the operator of approximately 99% of our Permian Basin acreage.

We have increased our initial leasehold position through acquisitions in the Wolfberry play for an aggregate net cost of $42.5 million. These acquisitions include the following:

 

•

In 2008, we acquired 6,247 net acres at the Spanish Trail and Munn prospects in Midland County, Texas through 11 leases and one mineral deed, with 5,146 net acres attributable to one lease;

 

•

Commencing in 2008 and ending in 2010, we acquired leases at the Barron prospect in Midland County, Texas covering 225 net acres;

 

•

Commencing in 2008 and ending in 2011, we acquired leases at the Gist prospect in Ector County, Texas covering 1,452 net acres;

 

•

Commencing in 2008 and ending in 2012, we acquired 37 leases at the UL prospect in Andrews, Upton and Reagan Counties, Texas covering a total of 10,006 net acres;

 

•

Beginning in 2008, we acquired 17 leases at the Hurt/WHL prospect in Ector County, Texas covering 2,779 net acres;

 

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•

In 2009, we acquired one lease at the Cumberland prospect located in Midland County, Texas covering 207 net acres;

 

•

In 2010, we acquired leases at the North Howard prospect located in Howard County, Texas that currently cover 131 net acres;

 

•

In 2010 and 2011, we acquired leases at the Big Max prospect located in Andrews County, Texas covering 848 net acres; and

 

•

In 2012, we acquired leases in the Clete and Hume prospects in Crockett County, Texas that currently cover 4,979 net acres.

Diamondback Energy, Inc. was incorporated in Delaware on December 30, 2011 as a holding company and will not conduct any material business operations prior to the transaction described below. Our historical financial information included in this prospectus pertains to assets, liabilities, revenues and expenses of Windsor Permian LLC, which is an entity controlled by our equity sponsor, Wexford. Prior to the closing of this offering, Wexford will cause DB Holdings, an entity controlled by Wexford, to contribute all of the outstanding equity interests in Windsor Permian LLC to us in exchange for shares of our common stock, and Windsor Permian LLC will become our wholly-owned subsidiary. In addition, Wexford has agreed to cause all the outstanding equity interests in Windsor UT to be contributed to Windsor Permian prior to the time Windsor Permian is contributed to us. Contemporaneously with the contribution of Windsor Permian to us, Gulfport will complete the Gulfport transaction in exchange for shares of our common stock.

In June 2012, Windsor Permian distributed to its sole member its minority equity interests in Bison Drilling and Field Services LLC, or Bison, and Muskie Holdings LLC, or Muskie. Bison was formed in November 2010 as a wholly-owned subsidiary of Windsor Permian. Between March 2011 and April 2012, Gulfport and various entities controlled by Wexford acquired interests in Bison, which reduced Windsor Permian’s interest to approximately 22%. Bison owns and operates four drilling rigs and various oil and natural gas well servicing equipment and has performed drilling and field services for us. Muskie was formed in October 2011 when Windsor Permian contributed certain assets, real estate and rights in a lease covering land in Wisconsin to Muskie in exchange for a 48.6% equity interest. The contributed lease is prospective for oil and natural gas fracture grade sand. At the time of the contribution, the remaining interests in Muskie were held by Gulfport and entities controlled by Wexford. Through additional contributions from the Wexford-controlled entities, Windsor Permian’s equity interest in Muskie decreased to approximately 33%. Windsor Permian’s interests in Bison and Muskie were distributed to Windsor Permian’s sole member in June 2012 so we may focus our activities on our oil and natural gas exploration and development activities. We recorded revenues attributable to Bison in our consolidated statements of operations of $0.8 million during 2010 and $1.5 million during the first quarter of 2011, at which time Bison was deconsolidated for financial reporting purposes. Muskie was formed in 2011, and we recorded a loss from equity method investments of $7,107 million for 2011. The interests in Bison and Muskie are reflected in “Investments-equity method” on our consolidated balance sheets. For additional information regarding Bison and Muskie, see “Unaudited Pro Forma Condensed Consolidated Financial Statements” and “Related Party Transactions” beginning on pages 50 and 128, respectively, of this prospectus and Note 5 to our consolidated financial statements appearing elsewhere in this prospectus.

Since we began operations, we have increased our drilling activity, evaluated potential acquisitions and added to our acreage portfolio. Because of our growth through acquisitions and development of our properties, our historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful or indicative of future results.

Like all oil and natural gas exploration and production companies, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well

 

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naturally decreases. Thus, an oil and natural gas exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on managing costs associated with drilling and the development and production of reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. We expect the permitting and approval process to become more difficult with increased activism from environmental and other groups which may extend the time it takes us to receive permits. Because of our relatively small size and concentrated property base, we can be disproportionately disadvantaged by delays in obtaining or failing to obtain drilling approvals compared to companies with larger or more dispersed property bases. As a result, we are less able to shift drilling activities to areas where permitting may be easier and we have fewer properties over which to spread the costs related to complying with these regulations and the costs or foregone opportunities resulting from delays.

Reserves and pricing

In December 2008, the SEC released the final rule for Modernization of Oil and Gas Reporting. Among other changes, the final rule requires us to report oil and natural gas reserves and calculate the full cost ceiling value using the unweighted arithmetic average first-day-of-the-month oil and natural gas prices during the 12-month period ending in the reporting period. The prior SEC rule required using prices at period end. The requirements of this standard became effective for the year ended December 31, 2009. These revisions and requirements affect the comparability between reporting periods prior to and after the year ended December 31, 2009 for reserve volume and value estimates, full cost pool write-down calculations and the calculations of depletion of oil and gas assets.

In the table below, Ryder Scott estimated all of our proved reserves at December 31, 2011 and Pinnacle estimated all of our proved reserves at December 31, 2010 and 2009. The prices used to estimate proved reserves for all periods did not give effect to derivative transactions, were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

 

		2011				2010				2009
Estimated Net Proved Reserves:
Oil (Bbls)			16,716,869				18,819,050				29,230,940
Natural gas (Mcf)			19,618,867				21,662,720				27,481,820
Natural gas liquids (Bbls)			4,763,273				5,563,978				7,522,225
Total (BOE)			24,749,953				27,993,481				41,333,468

 

		2011				2010				2009
		Unweighted Arithmetic Average First-Day-of-the-Month Prices
Oil (Bbls)		$	93.09			$	77.61			$	58.84
Natural gas (Mcf)		$	3.91			$	4.14			$	3.64
Natural gas liquids (Bbls)		$	56.33			$	40.74			$	29.37

Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas activities, commodity prices have experienced significant fluctuations, and additional changes in commodity prices may significantly affect the economic viability of drilling projects, as well as the economic valuation and economic recovery of oil and gas reserves.

 

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Sources of our revenue

Our revenues are derived from the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from our natural gas during processing. Our oil and natural gas revenues do not include the effects of derivatives. For the three months ended March 31, 2012 and the year ended December 31, 2011, our revenues were derived 89% and 84%, respectively, from oil sales, 9% and 10%, respectively, from natural gas liquids sales, 2% and 3%, respectively, from natural gas sales and none and 3%, respectively, from oil and natural gas services. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Oil, natural gas liquids and natural gas prices have historically been volatile. For example, during the past five years, the West Texas Intermediate posted price for crude oil has ranged from a low of $30.28 per Bbl in December 2008 to a high of $145.31 per Bbl in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $1.82 per MMBtu in April 2012 to a high of $13.31 per MMBtu in July 2008. During 2011, West Texas Intermediate prices ranged from $75.40 to $113.39 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.84 to $4.92 per MMBtu. On March 31, 2012, the West Texas Intermediate posted price for crude oil was $103.03 per Bbl and the Henry Hub spot market price of natural gas was $2.02 per MMBtu.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in commodity prices, from time-to-time we enter into derivative arrangements for our crude oil and natural gas production. We utilize commodity derivatives to reduce our exposure to fluctuations in NYMEX WTI benchmark prices. While these derivative contracts stabilize our cash flows when market prices are below our contract prices, they also prevent us from realizing increases in our cash flow when market prices are higher than our contract prices. We will sustain realized and unrealized losses to the extent our derivatives contract prices are lower than market prices and, conversely, we will sustain realized and unrealized gains to the extent our derivatives contract prices are higher than market prices. Our derivatives contracts are not designated as accounting hedges and, as a result, gains or losses on derivatives contracts are recorded as other income (expense) in our statements of operations.

Principal components of our cost structure

Lease operating and natural gas transportation and treating expenses. These are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workover expenses related to our oil and natural gas properties.

Production taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and gas properties.

General and administrative. These are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other fees for professional services and legal compliance.

Depreciation, depletion and amortization. Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units of production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unproved properties and major development projects for which proved reserves cannot yet be assigned, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated dismantlement and abandonment costs, net of estimated salvage values. We calculate depreciation on the cost of fixed assets related to other fixed assets.

Impairment expense. This is the cost to reduce proved oil and gas properties to the calculated full cost ceiling value.

 

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Other income (expense)

Interest income. This represents the interest received on our cash and cash equivalents.

Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our credit facility. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to our lender in interest expense. In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees in interest expense.

Loss on derivative contracts. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the price of crude oil. This amount represents (i) the recognition of unrealized gains and losses associated with our open derivative contracts as commodity prices change and commodity derivative contracts expire or new ones are entered into, and (ii) our realized gains and losses on the settlement of these commodity derivative instruments.

Loss from equity investment. This line item represents our proportionate share of the earnings and losses from our investment in the membership interests of Muskie, an equity method investment.

Income tax expense. As of March 31, 2012, we were a limited liability company treated as a disregarded entity for federal income tax purposes. Accordingly, no provision for federal or state corporate income taxes has been provided for the three months ended March 31, 2012 or prior fiscal years because taxable income is allocated directly to our equity holders. Prior to the completion of this offering, Windsor Permian will become our wholly-owned subsidiary and, because we are a subchapter C corporation under the Internal Revenue Code, the earnings at Windsor Permian will become subject to federal and state entity-level taxation. We will establish a net deferred tax liability for differences between the tax and book basis of our assets and liabilities, and we will record a corresponding “first day” tax expense to net income from continuing operations. On a pro forma basis, at March 31, 2012 the amount of this charge would have been $27.1 million. It is anticipated that the company will be subject to a future, total combined federal and state income tax rate of 34% to 36%.

 

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Results of Operations

The following table sets forth selected historical operating data for the periods indicated.

 

		Three Months Ended March 31,								Year Ended December 31,
		2012				2011				2011				2010				2009
		(unaudited)
Operating Results:
Revenues
Oil and natural gas revenues		$	16,004,507			$	10,583,902			$	47,180,802			$	26,441,927			$	12,716,011
Other revenue			—				1,490,910				1,490,910				811,247				—
Operating expenses
Lease operating expense			2,681,850				2,196,959				10,345,355				4,588,559				2,366,623
Production taxes			780,574				523,415				2,333,853				1,346,879				663,068
Gathering and transportation expense			67,232				35,482				201,828				105,870				42,091
Oil and natural gas services			—				1,732,892				1,732,892				811,247				—
Depreciation, depletion and amortization			4,664,942				3,616,694				15,402,826				8,145,143				3,215,891
General and administrative			1,191,402				601,048				3,603,479				3,051,627				5,062,618
Asset retirement obligation accretion expense			19,855				13,691				63,259				37,856				27,934
Total expenses			9,405,855				8,720,181				33,683,492				18,087,181				11,378,225
Income from operations			6,598,652				3,354,631				14,988,220				9,165,993				1,337,786
Net interest income (expense)			(880,159	)			(491,556	)			(2,516,861	)			(801,791	)			24,137
Other income			445,360				—				—				—				—
Loss on derivative contracts			(4,792,104	)			(12,114	)			(13,009,393	)			(147,983	)			(4,068,005	)
Loss from equity investment			(12,618	)			—				(7,017	)			—				—
Total other income (expense)			(5,239,521	)			(503,670	)			(15,533,271	)			(949,774	)			(4,043,868	)
Net income (loss)		$	1,359,131			$	2,850,961			$	(545,051	)		$	8,216,219			$	(2,706,082	)
Production Data:
Oil (Bbls)			147,992				101,404				441,822				280,721				168,741
Natural gas (Mcf)			132,336				82,301				413,640				323,847				253,321
Natural gas liquids (Bbl)			29,510				19,742				86,815				79,978				70,384
Combined volumes (BOE)			199,558				134,863				597,577				414,674				281,345
Daily combined volumes (BOE/d)			2,193				1,498				1,637				1,136				771
Average Prices(1):
Oil (per Bbl)		$	96.62			$	91.79			$	92.26			$	76.51			$	58.01
Natural gas (per Mcf)			2.62				3.88				3.98				4.32				3.64
Natural gas liquids (per Bbl)			46.01				48.48				54.98				44.56				28.49
Combined (per BOE)			80.20				78.48				78.95				63.77				45.20
Average Costs (per BOE):
Lease operating expense		$	13.44			$	16.29			$	17.31			$	11.07			$	8.41
Gathering and transportation expense			0.34				0.26				0.34				0.26				0.15
Production taxes			3.91				3.88				3.91				3.25				2.36
Production taxes as a % of sales			4.9	%			4.9	%			4.9	%			5.1	%			5.2	%
Depreciation, depletion and amortization			23.38				26.82				25.78				19.64				11.43
General and administrative			5.97				4.46				6.03				7.36				17.99

 

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(1)

After giving effect to our hedging arrangements in effect during the three months ended March 31, 2012 and 2011, respectively, the average prices per Bbl of oil and per BOE were $87.40 and $73.36, respectively, during the first quarter of 2012 and $91.67 and $78.39, respectively, during the first quarter of 2011. After giving effect to our hedging arrangements in effect during 2009, the average prices per Bbl of oil and per BOE (on a combined basis) were $41.59 and $35.35, respectively, during that year. Average prices for our hydrocarbons were not impacted by our hedging arrangements during 2011 or 2010.

Three Months ended March 31, 2012 Compared to Three Months ended March 31, 2011

Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $5.4 million, or 51%, to $16.0 million for the three months ended March 31, 2012 from $10.6 million for the three months ended March 31, 2011. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 695 BOE/d during the three months ended March 31, 2012 as compared to the same period in 2011. The total increase in revenue of approximately $5.4 million is largely attributable to higher oil, natural gas liquids and natural gas production volumes and an increase in the price of oil realized for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. Production increased by 46,588 Bbls of oil, 9,768 Bbls of natural gas liquids and 50,035 Mcf of natural gas for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. The net dollar effect of the increase in prices of approximately $0.5 million (calculated as the change in year-to-year average prices times current year production volumes of oil, natural gas liquids and natural gas) and the net dollar effect of the increase in production of approximately $4.9 million (calculated as the increase in year-to-year volumes for oil, natural gas liquids and natural gas times the prior year average prices) are shown below.

 

		Change in prices				Production volumes at March 31, 2012(1)				Total net dollar effect of change (in thousands)
Effect of changes in price:
Oil		$	4.83				147,992			$	716
Natural gas liquids		$	(2.47	)			29,510			$	(73	)
Natural gas		$	(1.25	)			132,336			$	(166	)
Total revenues due to change in price											477
		Change in production volumes(1)				Prices at March 31, 2011				Total net dollar effect of change (in thousands)
Effect of changes in volumes:
Oil			46,588			$	91.79			$	4,276
Natural gas liquids			9,768			$	48.48			$	474
Natural gas			50,035			$	3.88			$	194
Total revenues due to change in volumes										$	4,944
Total change in revenues										$	5,421

 

(1)	Production volumes are presented in Bbls for oil and natural gas liquids and in Mcf for natural gas.

Lease Operating Expense. Lease operating expense was $2.7 million ($13.44 per BOE) for the three months ended March 31, 2012, an increase of $0.5 million, or 23%, from $2.2 million ($16.29 per BOE) for the three months ended March 31, 2011. The increase is due to increased drilling activity, which resulted in additional producing wells for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. On a per-BOE basis, our lease operating expenses decreased $2.85, or 17%, as our well failure

 

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rate decreased period-to-period under the leadership of our new executive team, resulting in reduced costs for the repair and replacement of downhole equipment and the associated downtime and loss of production as these failures were remediated. Our lease operating expense during both periods was also adversely impacted by the cost of processing and treating non-hydrocarbon gases from certain of our wells that came on-line in 2011. The processing cost of approximately $200,000 per month has been necessary to meet pipeline specifications. During the second quarter of 2012, we intend to complete both oil and water gathering systems that will transport this gas stream to a sour gas pipeline, thereby eliminating the monthly processing and treating expense, and reducing water trucking, respectively. We believe that our reduced well failure rate and the completion of the gathering systems will help reduce our lease operating expense on a per-BOE basis in future periods.

Production Tax Expense. Production taxes as a percentage of oil and natural gas sales were 4.9% for the three months ended March 31, 2012 and 2011. Production taxes are primarily based on the market value of our production at the wellhead and may vary across the different counties in which we operate. Total production taxes increased $0.3 million, from $0.5 million during the three months ended March 31, 2011 to $0.8 million during the three months ended March 31, 2012 as a result of higher production and an increase in the market value of our production.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $1.1 million, or 31%, from $3.6 million for the three months ended March 31, 2011 to $4.7 million for the three months ended March 31, 2012. The weighted average depletion rate was $23.00 per BOE for the three months ended March 31, 2012 and $26.42 per BOE for the three months ended March 31, 2011. The decrease in depletion rate was due primarily to an increase in proved reserves at March 31, 2012.

General and Administrative Expense. General and administrative expense increased $0.6 million from $0.6 million for the three months ended March 31, 2011 to $1.2 million for the three months ended March 31, 2012. A $1.3 million increase primarily attributable to salary and equity based compensation expense for our new executive team was partially offset by the capitalization of $0.7 million of such salary and equity based compensation expense.

Interest Expense. Interest expense for the three months ended March 31, 2012 was $0.9 million, as compared to $0.5 million for the three months ended March 31, 2011, an increase of $0.4 million. Our weighted average outstanding principal under our credit agreement was $92.4 million for the three months ended March 31, 2012 as compared to $51.2 million for the same period in 2011 with increased borrowings primarily used to fund our increased drilling activity.

Hedging Activities. We have used price swap derivatives to reduce price volatility associated with certain of our oil sales. In these swaps, we received the fixed price per the contract and paid a floating market price to the counterparty based on New York Mercantile Exchange Light Sweet Crude Oil pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty.

On October 4, 2011, in an effort to lock-in prices on our anticipated base level of production, while at the same time providing downside protection for our borrowing base, we entered into West Texas Intermediate light sweet crude oil swaps on the NYMEX with BNP for the calendar years 2012 and 2013 of 1,000 barrels per day priced at $78.50 and $80.55, respectively. The counterparties to our derivative contracts as of March 31, 2012 are Hess Corporation, or Hess, and BNP Paribas, or BNP, which we believe are acceptable credit risks.

All derivative financial instruments are recorded on our consolidated balance sheets at fair value. The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity.

Set forth below are the summarized amounts, terms and fair values of outstanding instruments held as of March 31, 2012 and December 31, 2011. As of March 31, 2012, we had unrealized losses under all of our crude oil swaps. We may seek to settle some or all of these swaps after the closing of this offering with a portion of the net proceeds depending upon our assessment of market conditions.

 

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Description and Production Period		Volume (Bbls)				Original Strike Price (per Bbl)				March 31, 2012				December 31, 2011
										Fair Value Liability				Fair Value Liability
Crude Oil Swaps:
January – February 2012			60,000			$	78.50			$	—			$	1,228,289
March – November 2012			275,000			$	78.50				7,190,009				5,604,976
December 2012			31,000			$	78.50				831,348				594,223
January – December 2013			365,000			$	80.55				8,377,554				5,544,350

We enter into counter-swaps from time to time for the purpose of locking-in the value of a swap. Under the counter-swap, we receive a floating price for the hedged commodity and pay a fixed price to the counterparty. The counter-swap is effective in locking-in the value of a swap since subsequent changes in the market value of the swap are entirely offset by subsequent changes in the market value of the counter-swap.

In December 2007, we entered into a swap contract covering 1,680,000 Bbls of crude oil for the period from January 2008 to December 2012 at various fixed prices. In April 2008, we entered into a series of counter-swaps to lock-in the value of certain of these swaps settling 1,188,000 Bbls of crude oil swaps. In June 2009, we entered into an additional series of counter-swaps to lock-in the value of the remaining swaps settling 324,000 Bbls of crude oil swaps. Hess is the counterparty to this swap and each counter-swap.

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the April 2008 settlements as of March 31, 2012 and December 31, 2011, respectively.

 

Description and Production Period		Volume (Bbls)				Original Strike Price (per Bbl)				Lock-in Price (per Bbl)				March 31, 2012				December 31, 2011
														Fair Value Liability				Fair Value Liability
Crude Oil Swaps:
December 2011			22,500			$	82.90			$	98.50 – $102.20			$	—			$	378,750
January – February 2012			45,000			$	85.07			$	98.25 – $101.80				—				646,338
March – December 2012			225,000			$	85.07			$	98.25 – $101.80				3,230,066				3,230,621

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the June 2009 settlements as of March 31, 2012 and December 31, 2011, respectively.

 

Description and Production Period		Volume (Bbls)				Original Strike Price (per Bbl)				Lock-in  Price (per Bbl)				March 31, 2012				December 31, 2011
														Fair Value Asset				Fair Value Asset
Crude Oil Swaps:
December 2011			7,500			$	82.90			$	78.42			$	—			$	33,600
January – February 2012			15,000			$	85.07			$	80.52				—				68,249
March – December 2012			75,000			$	85.07			$	80.52				341,072				341,131

None of our derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following summarizes the loss on derivative contracts included in the consolidated statements of operations:

 

		Three Months Ended March 31,
		2012						2011
Unrealized loss on open non-hedge derivative instruments		$	3,427,073					$	—
Loss on settlement of non-hedge derivative instruments			1,365,031						12,114
Loss on derivative contracts		$	4,792,104					$	12,114

 

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We are required to provide margin deposits whenever our unrealized losses with Hess exceed predetermined credit limits. We had a margin deposit held by Hess of $1.4 million and $2.3 million as of March 31, 2012 and December 31, 2011, respectively which earns interest that is remitted to us. Under our master netting agreement with Hess, we have offset this margin deposit against its derivative positions.

Year ended December 31, 2011 Compared to Year ended December 31, 2010

Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $20.8 million, or 78%, to $47.2 million for the year ended December 31, 2011 from $26.4 million for the year ended December 31, 2010. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 501 BOE/d during the year ended December 31, 2011 as compared to the same period in 2010. The total increase in revenue of approximately $20.8 million is largely attributable to higher oil, natural gas liquids and natural gas production volumes and an increase in the prices of oil and natural gas liquids realized for the year ended December 31, 2011 as compared to the year ended December 31, 2010. Production increased by 161,101 Bbls of oil, 6,837 Bbls of natural gas liquids and 89,793 Mcf of natural gas for the year ended 2011 as compared to the year ended 2010. The net dollar effect of the increase in prices of approximately $7.7 million (calculated as the change in year-to-year average prices times current year production volumes of oil, natural gas liquids and natural gas) and the net dollar effect of the increase in production of approximately $13.0 million (calculated as the increase in year-to-year volumes for oil, natural gas liquids and natural gas times the prior year average prices) are shown below.

 

		Change in prices				Production volumes at December 31, 2011(1)				Total net dollar effect of change (in thousands)
Effect of changes in price:
Oil		$	15.75				441,822			$	6,959
Natural gas liquids		$	10.42				86,815			$	905
Natural gas		$	(0.34	)			413,640			$	(141	)
Total revenues due to change in price										$	7,723
		Change in production volumes(1)				Prices at December  31, 2010(2)				Total net dollar effect of change (in thousands)
Effect of changes in volumes:
Oil			161,101			$	76.51			$	12,326
Natural gas liquids			6,837			$	44.56			$	305
Natural gas			89,793			$	4.32			$	388
Total revenues due to change in volumes										$	13,019
Total change in revenues										$	20,742

 

(1)	Production volumes are presented in Bbls for oil and natural gas liquids and in Mcf for natural gas.

(2)	Prices represent the unweighted arithmetic average first-day-of-the-month oil and natural gas prices during the 12-month period ended December 31, 2010.

Lease Operating Expense. Lease operating expense was $10.3 million ($17.31 per BOE) for the year ended December 31, 2011, an increase of $5.7 million, or 125%, from $4.6 million ($11.07 per BOE) for the year ended December 31, 2010. The increase is due to increased drilling activity, which resulted in additional producing wells for the year ended December 31, 2011 as compared to the year ended December 31, 2010. On a per-BOE basis, the increase is due to cost increases in services and supplies (primarily as a result of higher demand for such services and supplies in the Permian Basin and higher commodity prices), the cost of repairing and replacing downhole equipment due to rod and tubing configurations and pumping practices that resulted in a higher rate of well failures during 2011 and the associated downtime and loss of production as these failures were

 

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remediated. Our lease operating expense for the year ended December 31, 2011 was also adversely impacted by the cost of processing and treating non-hydrocarbon gases from certain of our wells that came on line in 2011. The processing cost of approximately $200,000 per month has been necessary to meet pipeline specifications.

During the second quarter of 2012, we intend to complete both oil and water gathering systems that will transport this gas stream to a sour gas pipeline, thereby eliminating the monthly processing and treating expense, and reduce water trucking, respectively. We believe that our reduced well failure rate and the completion of the gathering systems will help reduce our lease operating expense on a per-BOE basis in future periods.

Production Tax Expense. Production taxes as a percentage of oil and natural gas sales were 4.9% for the year ended December 31, 2011 as compared to 5.1% for the year ended December 31, 2010. Production taxes are primarily based on the market value of our production at the wellhead and vary across the different counties in which we operate. Total production taxes increased $1.0 million, or 73.3%, from $1.3 million during the year ended December 31, 2010 to $2.3 million during the year ended December 31, 2011 as a result of higher production and an increase in the market value of our production.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $7.3 million, or 89.1%, from $8.1 million for the year ended December 31, 2010 to $15.4 million for the year ended December 31, 2011. The weighted average depletion rate was $25.40 per BOE for the year ended December 31, 2011 and $17.78 per BOE for the year ended December 31, 2010. The depletion rate increase was due primarily to an increase in costs and a decrease in proved reserves at December 31, 2011 for the reasons described in “Business—Oil and Gas Data” beginning on page 92 of this prospectus.

General and Administrative Expense. General and administrative expense increased $0.5 million from $3.1 million for the year ended December 31, 2010 to $3.6 million for the year ended December 31, 2011. A $1.9 million increase primarily attributable to salary and equity based compensation expense for our new executive team was partially offset by the capitalization of $0.9 million of such expense and a $0.5 million increase in COPAS overhead payments due to increased drilling activity.

Interest Expense. Interest expense for the year ended December 31, 2011 was $2.5 million, as compared to $0.8 million for the year ended December 31, 2010, an increase of $1.7 million. Our weighted average outstanding principal under our credit agreement was $69.0 million for the year ended December 31, 2011 as compared to $24.3 million for 2010 due to our increased drilling activity.

Hedging Activities. We have used price swap derivatives to reduce price volatility associated with certain of our oil sales. In these swaps, we received the fixed price per the contract and paid a floating market price to the counterparty based on New York Mercantile Exchange Light Sweet Crude Oil pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty.

On October 4, 2011, in an effort to lock-in prices on our anticipated base level of production, while at the same time providing downside protection for our borrowing base, we entered into West Texas Intermediate light sweet crude oil swaps on the NYMEX with BNP for the calendar years 2012 and 2013 of 1,000 barrels per day priced at $78.50 and $80.55, respectively. The counterparties to our derivative contracts as of December 31, 2011 are Hess and BNP, which we believe are acceptable credit risks.

All derivative financial instruments are recorded on our consolidated balance sheets at fair value. The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity.

 

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Set forth below are the summarized amounts, terms and fair values of outstanding instruments held as of December 31, 2011. As of December 31, 2011, we had unrealized losses under all of our crude oil swaps. We may seek to settle some or all of these swaps after the closing of this offering with a portion of the net proceeds depending upon our assessment of market conditions.

 

Description and Production Period		Volume (Bbls)				Original Strike Price (per Bbl)				December 31, 2011
										Fair Value Liability
Crude Oil Swaps:
January — November 2012			335,000			$	78.50			$	6,833,265
December 2012			31,000				78.50				594,223
January — December 2013			365,000				80.55				5,544,350

We enter into counter-swaps from time to time for the purpose of locking-in the value of a swap. Under the counter-swap, we receive a floating price for the hedged commodity and pay a fixed price to the counterparty. The counter-swap is effective in locking-in the value of a swap since subsequent changes in the market value of the swap are entirely offset by subsequent changes in the market value of the counter-swap.

In December 2007, we entered into a swap contract covering 1,680,000 Bbls of oil for the period from January 2008 through December 2012 at various fixed prices. In April 2008, we entered into a series of counter-swaps to lock-in the value of certain of these swaps settling 1,188,000 Bbls of oil swaps. In June 2009, we entered into an additional series of counter-swaps to lock-in the value of the remaining swaps settling 324,000 Bbls of oil swaps.

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the April 2008 settlements as of December 31, 2011 and December 31, 2010.

 

Description and Production Period		Volume (Bbls)				Original Strike Price (per Bbl)				Lock-in Price (per Bbl)				December 31,
														2011				2010
														Fair Value Liability				Fair Value Liability
Oil Swaps:
December 2010			22,000			$	82.80			$	99.45 – 103.20			$	—			$	392,462
January — November 2011			180,000				82.90				98.50 – 102.20				—				4,159,695
December 2011			90,000				82.90				98.50 – 102.20				378,750				377,314
January — December 2012			270,000				85.07				98.25 – 101.80				3,876,959				3,844,101

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the June 2009 settlements as of December 31, 2011 and December 31, 2010.

 

Description and Production Period		Volume (Bbls)				Original Strike Price (per Bbl)				Lock-in Price (per Bbl)				December 31,
														2011				2010
														Fair Value Asset				Fair Value Asset
Oil Swaps:
December 2010			8,000			$	82.80				75.00			$	—			$	62,400
January — November 2011			82,500				82.90				78.42				—				369,205
December 2011			7,500				82.90				78.42				33,600				33,503
January — December 2012			90,000				85.07				80.52				409,380				406,489

 

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None of our derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following table summarizes the loss on derivative contracts included in our consolidated statements of operations:

 

		Years Ended December 31,
		2011				2010				2009
Unrealized loss on open non-hedge derivative instruments		$	12,971,838			$	—			$	—
Unrealized loss on locked-in non-hedge derivative instruments			—				—				1,297,979
Loss on settlement of non-hedge derivative instruments			37,555				147,983				2,770,026
Loss on derivative contracts		$	13,009,393			$	147,983			$	4,068,005

We are required to provide margin deposits whenever our unrealized losses with Hess exceed predetermined credit limits. We had a margin deposit held by Hess of $2.3 million and $6.5 million as of December 31, 2011 and 2010, respectively, which earns interest that is remitted to us. Under our master netting agreement with Hess, we have offset this margin deposit against its derivative positions.

Year ended December 31, 2010 Compared to Year ended December 31, 2009

Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $13.7 million, or 108%, to $26.4 million during the year ended December 31, 2010 from $12.7 million for the year ended December 31, 2009. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 365 BOE/d during the year ended December 31, 2010 as compared to the year ended December 31, 2009. The total increase in revenue of approximately $13.7 million is largely attributable to higher oil, natural gas liquid and natural gas production volumes as well as an increase in oil, natural gas liquid and natural gas prices realized for the year ended December 31, 2010 as compared to year ended December 31, 2009. Production increased by 111,980 Bbls of oil, 9,594 Bbls of natural gas liquids and 70,526 Mcf of natural gas during 2010 as compared to 2009. The net dollar effect of the increase in prices of approximately $6.7 million (calculated as the change in year-to-year average prices times current year production volumes for oil, natural gas liquids and natural gas) and the net dollar effect of the change in production of approximately $7.0 million (calculated as the increase in year-to-year volumes for oil, natural gas liquids and natural gas times the prior year average prices) are shown below.

 

		Change in prices				Production volumes at December 31, 2010(1)				Total net dollar effect of change (in thousands)
Effect of changes in price:
Oil		$	18.50				280,721			$	5,193
Natural gas liquids		$	16.07				79,978			$	1,285
Natural gas		$	0.68				323,847			$	220
Total revenues due to change in price										$	6,698
		Change in production volumes(1)				Prices at December 31, 2009
Effect of changes in volumes:
Oil			111,980			$	58.01			$	6,496
Natural gas liquids			9,594			$	28.49			$	273
Natural gas			70,526			$	3.64			$	257
Total revenues due to change in volumes										$	7,026
Total change in revenues										$	13,724

 

(1)	Production volumes are presented in Bbls for oil and natural gas liquids and in Mcf for natural gas.

 

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Lease Operating Expense. Lease operating expense was $4.6 million ($11.07 per BOE) for the year ended December 31, 2010, an increase of $2.2 million, or 92%, from $2.4 million ($8.41 per BOE) for the year ended December 31, 2009. The increase is due to increased drilling activity, which resulted in additional producing wells in 2010 as compared to 2009. On a per-BOE basis, the increase is due to cost increases in services and supplies, primarily as a result of the increased demand for such services and supplies in the Permian Basin, and increased commodity prices as well as additional well failure repairs coupled with downtime associated with the failures impacting production.

Production Tax Expense. Production taxes as a percentage of oil and natural gas sales were 5.1% for the year ended December 31, 2010 as compared to 5.2% for the year ended December 31, 2009. Production taxes are primarily based on the market value of our production at the wellhead and vary across the different counties in which we operate. Total production taxes increased $0.6 million, or 86%, from $0.7 million for the year ended December 31, 2009 to $1.3 million for the year ended December 31, 2010 as a result of higher production and an increase in the market value of our production.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $4.9 million, or 153%, from $3.2 million for the year ended December 31, 2009 to $8.1 million for the year ended December 31, 2010. The weighted average depletion rate was $11.21 per BOE in 2009 and $17.78 per BOE in 2010. The higher depletion rate in 2010 was due primarily to downward reserve revisions due to undeveloped locations being scheduled for development beyond five years and thus being excluded from proved reserves.

On December 31, 2009, we adopted the new SEC rules related to disclosures of oil and natural gas reserves. As a result of these new SEC rules, we recorded additional proved reserves and utilized the additional proved reserves in our depletion computation for 2009. Our 2009 depletion expense rate was $11.21 per BOE, which is lower in part due to these additional proved reserves.

General and Administrative Expense. General and administrative expense decreased $2.0 million, or 39%, from $5.1 million for the year ended December 31, 2009 to $3.1 million for the year ended December 31, 2010. This decrease was primarily due to a reduction in our labor force. As our capital expenditure programs result in increased production levels, we expect that general and administrative expense per unit of production will continue to decrease.

Interest Expense. Interest expense for 2010 was $0.8 million as compared to an interest expense of $0.01 million for 2009. During the year ended December 31, 2010, $0.2 million of our interest was capitalized and our weighted average outstanding principal under our credit agreement was $24.3 million, which was used primarily to fund our increased drilling program. During the year ended December 31, 2009, most of the interest was capitalized and our weighted average outstanding principal was $6.7 million.

Hedging Activities. We have used price swap derivatives to reduce price volatility associated with certain of our oil sales. In these swaps, we received the fixed price per the contract and paid a floating market price to the counterparty based on New York Mercantile Exchange Light Sweet Crude Oil pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. The counterparty to all of our derivative contracts is Hess, which we believe is an acceptable credit risk.

All derivative financial instruments are recorded on our consolidated balance sheets at fair value. The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity.

We enter into counter-swaps from time to time for the purpose of locking-in the value of a swap. Under the counter-swap, we receive a floating price for the hedged commodity and pay a fixed price to the counterparty. The counter-swap is effective in locking-in the value of a swap since subsequent changes in the market value of the swap are entirely offset by subsequent changes in the market value of the counter-swap.

 

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In December 2007, we entered into a swap contract covering 1,680,000 Bbls of oil for the period from January 2008 through December 2012 at various fixed prices. In April 2008, we entered into a series of counter-swaps to lock-in the value of certain of these swaps settling 1,188,000 Bbls of oil swaps. In June 2009, we entered into an additional series of counter-swaps to lock-in the value of the remaining swaps settling 324,000 Bbls of oil swaps. We have not entered into any new swap contracts since the initial contract in December 2007. As of December 31, 2010 and 2009, all swap contracts were locked-in with counter swaps.

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the April 2008 settlements as of December 31, 2010 and 2009.

 

		Volume (Bbls)				Original Strike Price (per Bbl)				Lock-in Price (per Bbl)				December 31,
														2010				2009
Description and Production Period														Fair Value Liability				Fair Value Liability
Oil Swaps:
December 2009			22,000			$	83.75			$	102.25 – 105.90			$	—			$	432,550
January — November 2010			242,000				82.80				99.45 – 103.20				—				4,312,111
December 2010			22,000				82.80				99.45 – 103.20				392,462				390,714
January — December 2011			270,000				82.90				98.50 – 102.20				4,537,009				4,485,047
January — December 2012			270,000				85.07				98.25 – 101.80				3,844,101				3,737,855

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the June 2009 settlements as of December 31, 2010 and 2009.

 

		Volume (Bbls)				Original Strike Price (per Bbl)				Lock-in Price (per Bbl)				December 31,
														2010				2009
Description and Production Period														Fair Value Asset				Fair Value Asset
Oil Swaps:
December 2009			8,000			$	83.75			$	71.03			$	—			$	101,757
January — November 2010			88,000				82.80				75.00				—				685,405
December 2010			8,000				82.80				75.00				62,400				62,108
January — December 2011			90,000				82.90				78.42				402,708				397,880
January — December 2012			90,000				85.07				80.52				406,489				394,696

None of our derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following summarizes the loss on derivative contracts included in the consolidated statements of operations as follows:

 

		Years ended December 31,
		2010				2009
Unrealized loss on locked-in non-hedge derivative instruments		$	—			$	1,297,979
Loss on settlement of non-hedge derivative instruments			147,983				2,770,026
Loss on derivative contracts		$	147,983			$	4,068,005

We are required to provide margin deposits whenever our unrealized losses with Hess exceed predetermined credit limits. We had a margin deposit held by Hess of $6.5 million and $10.3 million as of December 31, 2010 and 2009, respectively. Interest earned on the deposit is remitted to us. As we have a master netting agreement with Hess, we have offset this margin deposit against derivative positions.

 

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Liquidity and Capital Resources

Historically, our primary sources of liquidity to date have been capital contributions and loans from our equity sponsor, borrowings under our credit facility and cash flows from operations. Our primary use of capital has been for the acquisition, development and exploration of oil and natural gas properties. We regularly evaluate potential capital sources, including equity and debt financings, in an effort to meet our planned capital expenditures and liquidity requirements. Our future success in growing proved reserves and production will be highly dependent on our ability to access outside sources of capital.

Liquidity and cash flow

Our cash flows for the three months ended March 31, 2012 and 2011 and the years ended December 31, 2011, 2010 and 2009 are presented below:

 

		Three Months Ended March 31,								Year Ended December 31,
		2012				2011				2011				2010				2009
Net cash provided by operating activities		$	19,156,452			$	5,567,894			$	30,384,194			$	5,175,824			$	2,701,566
Net cash used in investing activities			(33,170,446	)			(21,956,058	)			(76,314,042	)			(53,134,641	)			(32,149,617	)
Net cash provided by financing activities		$	16,254,970			$	13,383,313				48,642,492				49,618,254				23,849,250
Net change in cash		$	2,240,976			$	(3,004,851	)		$	2,712,644			$	1,659,437			$	(5,598,801	)

Operating Activities

On a historical basis, net cash provided by operating activities was $19.2 million for the three months ended March 31, 2012 as compared to $5.6 million for the three months ended March 31, 2011. The increase in operating cash flows is due to an overall increase in production revenues, partially offset by increased expenses, as discussed above in “—Results of Operations” beginning on page 62. The increase in production is largely a result of our increased drilling activities throughout 2012 and 2011.

Net cash provided by operating activities was $30.4 million for the year ended December 31, 2011 as compared to $5.2 million for the year ended December 31, 2010. The increase in operating cash flows is due to an overall increase in production revenues, partially offset by increased expenses, as discussed above in “—Results of Operations” on page 62. The increase in production is largely a result of our increased drilling activities throughout 2011.

Net cash provided by operating activities was $5.2 million for the year ended December 31, 2010 as compared to $2.7 million for the year ended December 31, 2009. The increase in operating cash flows is due to an overall increase in production revenues, partially offset by increased expenses, as discussed above in “—Results of Operations” on page 62. The increase in production volumes is largely a result of our increased drilling program in 2010. The increase in operating activities was partially offset by changes in our working capital components in 2010 which consisted primarily of the purchase of inventory of tubular goods for our drilling program and increased accounts receivables due to the increase in our drilling activities in 2010.

Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas we produce. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict.

 

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Investing Activities

On a historical basis, we used cash for investing activities of $33.2 million and $22.0 million during the three months ended March 31, 2012 and 2011, respectively.

During the first three months ended 2012, we spent $26.8 million on capital expenditures in conjunction with our drilling program in which we participated in the drilling of 11 gross (7 net) wells. We spent an additional $4.8 on leasehold costs, $0.2 million for the purchase of other property and equipment and $1.4 million, net, on the settlement of our derivative transactions.

The purchase and development of oil and natural gas properties accounted for the majority of our cash outlays for investing activities. We used cash for investing activities of $76.3 million, $53.1 million and $32.1 million during the years ended December 31, 2011, 2010 and 2009, respectively.

During 2011, we spent $72.2 million on capital expenditures in conjunction with our drilling program in which we participated in the drilling of 54 gross (31 net) wells. We spent an additional $3.2 million on leasehold costs, $0.4 million for the purchase of other property and equipment, $4.2 million for the purchase of certain assets, real estate and leasehold interests which were subsequently contributed to Muskie and $2.5 million for the purchase of drilling rigs and other equipment which were subsequently contributed to Bison. These amounts were partially offset by proceeds of $6.0 million from a partial sale of our equity investment, $0.05 million from the sale of property and equipment and $0.08 million from the settlement of non-hedge derivative investments and margin deposits.

During 2010, we spent $39.0 million on capital expenditures in conjunction with our drilling program in which we participated in the drilling of 40 gross (25 net) wells. We spent an additional $3.5 million for the purchase and development of leasehold interests, $11.7 million for the purchase of drilling rigs, well servicing equipment and other equipment which were subsequently contributed to Bison and $0.2 million for the settlement of non-hedge derivative instruments and margin deposits. These amounts were partially offset by the $1.3 million we received from the sale of approximately 10,946 net acres of non producing acreage in the Permian Basin.

During 2009, we spent $24.0 million on capital expenditures in conjunction with our drilling program in which we participated in the drilling of 12 gross (nine net) wells. We spent an additional $2.7 million for the purchase and development of leasehold interests in the Permian Basin and $5.5 million for the net amount of the settlement of non-hedge derivative instruments and margin deposits.

 

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Our investment activities for the three months ended March 31, 2012 and 2011 and the years ended December 31, 2011, 2010 and 2009 are summarized in the following table:

 

		Three months Ended March 31,								Year Ended December 31,
		2012				2011				2011				2010				2009
Drilling and completion of wells		$	(26,839,722	)		$	(15,565,469	)		$	(72,165,677	)		$	(38,979,629	)		$	(23,955,667	)
Purchase of leasehold acquisitions			(4,778,863	)			(308,318	)			(3,213,932	)			(3,493,464	)			(2,667,068	)
Purchase of other property and equipment			(194,037	)			(5,466,193	)			(7,064,972	)			(11,741,073	)			(8,856	)
Proceeds from sale of property and equipment			1,525				12,135				54,909				1,270,075				2,000
Settlement of non-hedge derivative instruments			(2,288,766	)			(1,020,450	)			(4,126,800	)			(3,962,440	)			(2,770,026	)
Receipt (payment) on derivative margins			929,417				401,773				4,202,467				3,771,890				(2,750,000	)
Proceeds from equity investment, net			—				(9,536	)			5,999,963				—				—
Net cash used in investing activities			(33,170,446	)			(21,956,058	)		$	(76,314,042	)		$	(53,134,641	)		$	(32,149,617	)

Financing Activities

Net cash provided by financing activities for the first three months of 2012 was $16.3 million as compared to $13.4 million for the first three months of 2011. During the first three months of 2012 and 2011, we borrowed $12.5 million and $13.5 million, respectively, under our revolving credit facility and received capital contributions from entities controlled by Wexford, our equity sponsor, of $4.0 million and zero, respectively. These proceeds were used primarily to fund our drilling costs and purchase property and equipment. During the three months ended March 31, 2012, we paid $0.2 million for costs associated with this offering.

Net cash provided by financing activities for 2011 was $48.6 million as compared to $49.6 million for 2010. During 2011, we borrowed $40.2 million under our revolving credit facility and received capital contributions from entities controlled by Wexford, our equity sponsor, of $9.2 million. These proceeds were used primarily to fund our drilling costs and purchase property and equipment.

Net cash provided by financing activities for 2010 was $49.6 million as compared to $23.8 million for 2009. The net cash provided by financing activities in 2010 is primarily attributable to borrowings of $61.1 million under our revolving credit facility, partially offset by principal payments of $24.0 million under our prior credit facility with the Bank of Oklahoma, N.A. During 2010, we received capital contributions from entities controlled by Wexford, our equity sponsor, of $18.8 million which were partially offset by distributions to Wexford of $5.6 million. We paid $0.7 million in debt issuance costs in 2010. We used the net proceeds from our financing activities during 2010 to fund our drilling costs, the purchase of property and equipment, the purchase of tubular goods inventory and the acquisition and development of leasehold.

Net cash provided by financing activities for 2009 was $23.8 million as compared to $80.2 million for 2008. The net cash provided by financing activities in 2009 is attributable to borrowings of $7.7 million under our revolving credit facility and $16.9 million of capital contributions from entities controlled by Wexford, our equity sponsor, which amounts were partially offset by distributions to Wexford of $0.6 million. We paid $0.1 million for debt issuance costs and costs relating to the preparation for the initial public offering. We used

 

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the net proceeds from our financing activities to fund our drilling program, the purchase of property and equipment, the acquisition and development of leasehold and the settlement of our non-hedge derivative instruments.

Existing Revolving Credit Facility

On October 15, 2010, we entered into a senior secured revolving credit agreement with BNP Paribas, or BNP, as administrative agent for the several lenders, as amended, providing for a $100.0 million revolving credit facility, subject to scheduled semi-annual and other elective collateral borrowing base redeterminations based on our oil and natural gas reserves. The outstanding borrowings bear interest at a rate elected by us that is currently based on the prime, LIBOR or federal funds rate plus margins ranging from 1.25% to 3.50% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base.

Principal may be optionally repaid from time to time and is required to be paid (a) if the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise, and (b) at the maturity date of October 15, 2014. We are obligated to pay a quarterly commitment fee equal to 0.5% per year of the unused portion of the borrowing base. The loan is secured by substantially all of our assets. The borrowing base is re-determined semi-annually with effective dates of April 1st and October 1st. In addition, we may request up to three additional redeterminations of the borrowing base during any 12-month period. The borrowing base was $45.0 million at December 31, 2010. The borrowing base was increased several times during 2011 as a result of redeterminations and at December 31, 2011 the borrowing base was $100.0 million. Under the terms of the revolving credit agreement as currently in effect, the borrowing base will remain at $100.0 million through July 15, 2013 or, if earlier, the closing date of this offering, at which time the borrowing base will be reduced to $90.0 million, subject to the periodic and elective borrowing base redeterminations described above. However, we expect that our borrowing base will be increased above the $90.0 million borrowing base level as a result of our acquisition of the oil and gas properties subject to the Gulfport transaction and those properties owned by Windsor UT. As of June 30, 2012, March 31, 2012 and December 31, 2011, we had outstanding borrowings of $100.0 million, $97.5 million and $85.0 million, respectively. Borrowings under the revolving credit agreement bore interest at a weighted average rate of 3.74% at June 30, 2012 and 3.3% at each of March 31, 2012 and December 31, 2011. We intend to repay the outstanding borrowings under our revolving credit facility with a portion of the net proceeds of this offering.

Our revolving credit agreement contains various affirmative and restrictive covenants. These covenants, among other things, prohibit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of various financial ratios described below.

 

Financial Covenant		Required Ratio
Ratio of EBITDAX to interest expense(1)		Not less than 2.5 to 1.0
Ratio of total debt to EBITDAX		Not greater than 3.5 to 1.0
Ratio of current assets to liabilities		Not less than 1.0 to 1.0

 

(1)

Our revolving credit agreement defines EBITDAX, for any period, as the sum of our consolidated net income for such period plus the following expenses or charges to the extent deducted from our consolidated net income in such period: interest, income taxes, depreciation, depletion, amortization, exploration expenses, extraordinary items and other similar noncash charges, minus all noncash income added to our consolidated net income.

On May 10, 2012, our revolving credit agreement was further amended to provide for the resignation of BNP, and the appointment of Wells Fargo Bank, National Association, as administrative agent for the lenders. The amendment also permitted certain restricted payments and subordinated debt in an initial principal amount not to exceed $30.0 million, including any such indebtedness evidenced by our subordinated note with an affiliate of Wexford described in more detail under “—Subordinated Note” below.

 

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As of March 31, 2012, we were in compliance with all financial covenants under our revolving credit facility. The lenders may accelerate all of the indebtedness under our revolving credit facility upon the occurrence of any event of default unless we cure any such default within any applicable cure period. For payments of interest under our revolving credit facility, we have a three business day grace period, and a 30-day cure period for most covenant defaults, except for defaults of certain covenants, including the financial covenants and negative covenants under our revolving credit facility.

Subordinated Note

Effective May 14, 2012, we issued a subordinated note to an affiliate of Wexford pursuant to which the Wexford affiliate may, from time to time, advance up to an aggregate $25.0 million. These advances are solely at the lender’s discretion and neither Wexford nor any of its affiliates has any commitment or obligation to provide further capital support to us. The note bears interest at a rate equal to LIBOR plus 0.28% or 8% per annum, whichever is lower. Interest is due quarterly in arrears beginning on July 1, 2012. Interest payments are payable in kind by adding such amounts to the principal balance of the note. The unpaid principal balance and all accrued interest on the note are due and payable in full on January 31, 2015 or the earlier completion of this offering. Any indebtedness evidenced by this note is subordinate in the right of payment to any indebtedness outstanding under our revolving credit facility. As of June 30, 2012, there was $14.1 million in aggregate principal amount outstanding under this note. We will repay the outstanding borrowings under this note with a portion of the net proceeds of this offering.

Prior Revolving Credit Facility

On September 17, 2009, we entered into a revolving credit facility with the Bank of Oklahoma, N.A., or BOK. The BOK revolving credit facility had a maximum principal amount of $50.0 million, subject to a collateral borrowing base calculation which was based on the underlying reserve value of the oil and natural gas properties securing the credit facility and outstanding letters of credit. The BOK revolving credit facility was repaid in full in October 2010 with borrowings under the BNP revolving credit facility and then terminated.

Borrowings under the BOK revolving credit facility bore interest at our election of either BOK’s listed national prime rate plus an interest rate spread ranging from 1.0% to 2.5% (based on borrowing levels) payable monthly or at LIBOR rates plus an interest rate spread ranging from 2.5% to 4.0% (based on borrowing levels) payable at the end of the applicable interest period. The credit facility agreement allowed BOK to charge a 0.25% commitment fee on the unused available borrowing.

The BOK revolving credit facility was collateralized by oil and natural gas properties and contained certain financial and non-financial covenants, which included: providing quarterly financial statements and annual audited financial statements; providing semi-annual reserve engineering reports; restrictions on distributions to members; restrictions on incurring additional debt; restrictions on financial derivative contracts; maintaining a funded debt to earnings before hedge gains or losses, asset gains or losses, depreciation, depletion, amortization and interest expense of no greater than 3.0 to 1.0.

Capital Requirements and Sources of Liquidity

We currently anticipate our 2012 capital budget for drilling and infrastructure will be approximately $180.0 million to $190.0 million after giving effect to the Transactions. We intend to allocate these expenditures as follows:

 

•

$158.0 million for the drilling and completion of operated wells;

 

•

$10.5 million for our participation in the drilling and completion of non-operated wells;

 

•

$8.0 million for leasehold acquisitions; and

 

•

$6.0 million for the construction of infrastructure to support production, including investments in water disposal infrastructure and gathering line projects.

 

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During the five months ended May 31, 2012, aggregate capital expenditures for drilling and infrastructure after giving effect to the Transactions were $66.4 million while our capital expenditures without giving effect to the Transactions were $43.2 million.

However, the amount and timing of these capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned 2012 capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners.

Based upon current oil and natural gas price expectations for 2012, we believe that our cash flow from operations, proceeds of this offering and borrowings under our revolving credit facility will be sufficient to fund our operations for at least the next 12 months. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. We cannot assure you that operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our capital expenditure budget for 2012 allocates $8.0 million to leasehold interest and property acquisitions. In the event we make additional acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures and/or seek additional capital. If we require additional capital for that or other reasons, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financings, asset sales, offerings of debt and equity securities or other means. We cannot assure you that needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our current drilling programs, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves.

Contractual and Commercial Commitments

The following table summarizes our contractual obligations and commercial commitments as of December 31, 2011:

 

		Payments Due By Year
		Less Than 1 Year				1-3 Years				3-5 Years				More Than 5 Years				Total
		(in thousands)
Long term debt(1)		$	—			$	85,000			$	—			$	—			$	85,000
Derivative contracts			8,320				6,139				—				—				14,459
Asset retirement obligation(2)			—				—				—				1,080				1,080
Operating leases			219				690				358				—				1,267
Total		$	8,539			$	91,829			$	358			$	1,080			$	101,806

 

(1)

Consists of the outstanding principal amount at December 31, 2011 under our revolving credit facility. This table does not include future commitment fees, interest expense or other fees payable under this floating rate facility as we cannot predict the timing of future borrowings and repayments or interest rates to be charged. All borrowings under our revolving credit facility are due on October 15, 2014.

(2)

Amounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. Please read Note 4 to our audited financial statements.

 

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Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. See Note 2 of the notes to our consolidated financial statements appearing elsewhere in this prospectus for a discussion of additional accounting policies and estimates made by management.

Use of Estimates

Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated by our management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates.

We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved reserve quantities and related estimates of the present value of future net revenues, the carrying value of oil and gas properties and asset retirement obligations.

Method of accounting for oil and natural gas properties

We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment. General and administrative costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Income from services provided to working interest owners of properties in which we also own an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves.

Costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. We assess all items classified as unevaluated property on a quarterly basis for possible impairment. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. The inclusion of our unevaluated costs into the amortization base is expected to be completed within three years.

 

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Oil and natural gas reserve quantities and standardized measure of future net revenue

Our independent engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. The SEC has defined proved reserves as the estimated quantities of oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating oil and gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Revenue recognition

Oil and natural gas revenues are recorded when title passes to the purchaser, net of royalty interests, discounts and allowances, as applicable. We account for oil and natural gas production imbalances using the sales method, whereby a liability is recorded when our volumes exceed our estimated remaining recoverable reserves. No receivables are recorded for those wells where we have taken less than our ownership share of production. We did not have any gas imbalances as of December 31, 2011, 2010 and 2009 or as of March 31, 2012. Revenues from oil and natural gas services are recognized as services are provided.

Impairment

The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization, impairment and deferred income taxes exceed the discounted future net revenues of proved oil and natural gas reserves, less any related income tax effects, the excess capitalized costs are charged to expense. In calculating future net revenues, effective December 31, 2009, prices are calculated as the average oil and gas prices during the preceding 12-month period prior to the end of the current reporting period, determined as the unweighted arithmetic average first-day-of-the-month prices for the prior 12-month period and costs used are those as of the end of the appropriate quarterly period.

Asset retirement obligations

ASC Topic 410 requires companies to record a liability relating to the retirement and removal of assets used in their businesses. ASC Topic 410 requires that the fair value of a liability for an asset’s retirement obligation be recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and that the corresponding cost be capitalized as part of the carrying amount of the related long-lived asset. For oil and gas properties, this is the period in which the well is drilled or acquired. The asset retirement obligation represents the estimated amount we will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period and the capitalized cost is depreciated on the unit-of-production method.

 

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We determine the asset retirement obligation by calculating the present value of estimated cash flows related to the liability. Estimating the future asset retirement obligation requires management to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, a corresponding adjustment is made to the related asset.

Derivatives

From time to time, we have used energy derivatives for the purpose of mitigating the risk resulting from fluctuations in the market price of crude oil. We recognize all of our derivative instruments as either assets or liabilities at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and further on the type of hedging relationship. We enter into counter-swaps from time to time for the purpose of locking-in the value of a swap. Under the counter-swap, we receive a floating price for the hedged commodity and pay a fixed price to the counterparty. The counter-swap is effective in locking-in the value of a swap since subsequent changes in the market value of the swap are entirely offset by subsequent changes in the market value of the counter-swap. For those derivative instruments that are designated and qualify as hedging instruments, we designate the hedging instrument, based on the exposure being hedged, as either a fair value hedge or a cash flow hedge. Changes in the fair value of instruments designated as a fair value hedge offset changes in the fair value of the hedge item and changes in the fair value of instruments designated as cash flow hedges are shown in accumulated other comprehensive income until the hedged item is recognized in earnings. For derivative instruments not designated as hedging instruments, the unrealized gain or loss on the change in fair value of these instruments are recognized in earnings during the period of change. None of our derivatives were designated as hedging instruments during the years ended December 31, 2011, 2010 and 2009 or for the three months ended March 31, 2012.

Equity-Based Compensation

During the year ended December 31, 2011, we granted to our executive officers options to acquire membership interests in our Company. Such options vest in four equal annual installments commencing on the first anniversary of the date of grant and are exercisable for five years from the date of grant. Generally, in the event more than 50% of the combined voting power of our Company is not owned by Wexford or its affiliates and there is a material change in the terms of the option holder’s employment, the options will vest immediately. Summarized below are the grant dates with the total exercise prices and total fair values of the underlying options:

 

Months Ended		Membership Interests Granted				Exercise Price				Fair Value at Date of Grant
April 2011			1.00	%		$	3,600,000			$	1,452,851
August 2011			1.20	%			6,000,000				1,383,976
September 2011			1.25	%			5,900,000				1,532,612
November 2011			0.25	%			1,250,000				288,328
			3.70	%		$	16,750,000			$	4,657,767

At March 31, 2012, for outstanding options, the intrinsic value was $112,500 and the weighted-average remaining contractual terms were 4.3 years. Also, at March 31, 2012, no options were exercisable.

We account for such options issued using a fair-value-based method calculated on the grant-date of the award. The resulting cost is recognized on a straight-line basis over the vesting period of the entire option.

The fair value of the options issued was estimated using the Black-Scholes option-pricing model. One of the inputs to this model is the estimate of the fair value of the underlying membership interest on the date of grant.

 

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The other inputs include an estimate of the expected volatility of the membership interest, an option’s expected term, the risk-free interest rate over the option’s expected term, the option’s exercise price and our expectations regarding dividends.

We do not have a history of market prices for our membership interests because such interests are not publicly traded. We utilized the observable data for a group of peer companies that grant options to assist in developing our volatility assumption. The expected volatility was determined using the historical volatility for a peer group of companies. The expected term for options issued was determined based on the contractual terms of the awards. The weighted-average risk-free interest rate was based on the daily U.S. treasury yield curve rate whose term was consistent with the expected life of the options. We do not anticipate paying cash dividends; therefore, the expected dividend yield was assumed to be zero.

A summary of the significant assumptions used to estimate the fair value of the options to acquire membership interests during the year ended December 31, 2011 is as follows:

		Three Months Ended March 31, 2012
Expected term			5 years
Risk-free interest rate			0.96	%
Expected volatility			45.50	%
Expected dividend yield			0.00	%

We assumed no annual forfeiture rate because of our lack of turnover and lack of history for this type of award. We will continue to evaluate the appropriateness of the forfeiture rate based on actual forfeiture experience, analysis of employee turnover behavior and other factors. Changes in the estimated forfeiture rate can have a significant effect on reported equity-based compensation expense, because the cumulative effect of adjusting the rate for all expense amortization is recognized in the period the forfeiture estimate is changed.

We perform annual valuations to estimate our enterprise value. Our valuations consider a number of objective and subjective factors that we believe market participants would consider, including: (a) our business, financial condition, and results of operations, including related industry trends affecting our operations; (b) our forecasted operating performance and projected future cash flows; (c) the liquid or illiquid nature of our membership interest; (d) liquidation preferences, redemption rights and other rights and privileges of our membership interest; (e) market multiples of our most comparable public peers; and (f) market conditions affecting our industry.

We used the income approach to estimate our enterprise value. The income approach involves applying an appropriate risk-adjusted discount rate to projected cash flows based on forecasted revenue and costs. The valuations were based primarily on our independent engineering oil and gas reserve reports which are generally a cash flow model of the Company. There were no significant events during the year that caused us to adjust these values at the various grant dates.

There is inherent uncertainty in our forecasts and projections and, if we had made different assumptions and estimates than those described previously, the amount of our equity-based compensation expense could have been materially different.

Equity-based compensation expense recorded for the three months ended March 31, 2012 was $291,110. The unrecognized equity-based compensation expense as of March 31, 2012 was $3,822,366 related to these awards which is expected to be recognized over a weight-average period of 3.3 years. No equity-based compensation expense was recorded for the three months ended March 31, 2011 or for the years ended December 31, 2010 and 2009 as we had not historically issued equity-based compensation awards.

 

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Recent accounting pronouncements

Fair Value

In May 2011, the FASB issued authoritative guidance which provides a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between GAAP and International Financial Reporting Standards. This new guidance changes some fair value measurement principles and disclosure requirements, but does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. The update is effective for annual periods beginning after December 15, 2011. The adoption of this update will not have a significant impact on our financial statements.

Comprehensive Income

In June 2011, the FASB issued Accounting Standards Update No. 2011-05, “Comprehensive Income: Presentation of Comprehensive Income,” which provides amendments to FASB ASC Topic 220, “Comprehensive Income.” The purpose of the amendments in this update is to provide a more consistent method of presenting non-owner transactions that affect an entity’s equity. The amendments eliminate the option to report other comprehensive income and its components in the statement of changes in stockholders’ equity and require an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. In December 2011, the FASB issued Accounting Standards Update 2011-12 which defers the requirement in Accounting Standards Update 2011-05 that companies present reclassification adjustments for each component of accumulated other comprehensive income in both net income and other comprehensive income on the face of the financial statements. Both amendments are effective for interim and annual periods beginning after December 15, 2011 and should be applied retrospectively. The adoption of this guidance will not have a significant impact on our financial position, results of operations or cash flow.

Emerging Growth Company

The JOBS Act permits an “emerging growth company” like us to take advantage of an extended transition period to comply with new or revised accounting standards applicable to public companies. We are choosing to “opt out” of this provision and, as a result, we will comply with new or revised accounting standards as required when they are adopted. This decision to opt out of the extended transition period is irrevocable.

Internal Controls and Procedures

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting under Section 404 until the year following our first annual report required to be filed with the SEC.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended 2009, 2010 and 2011. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations.

 

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Quantitative and Qualitative Disclosure about Market Risks

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control.

We use price swap derivatives to reduce price volatility associated with certain of our oil sales. Under these swap contracts, we receive a fixed price per barrel of oil and pay a floating market price per barrel of oil to the counterparty based on New York Mercantile Exchange Light Sweet Crude Oil pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. For the purpose of locking-in the value of a swap, we enter into counter-swaps from time to time. Under the counter-swap, we receive a floating price for the hedged commodity and pay a fixed price to the counterparty. The counter-swap is effective in locking-in the value of a swap since subsequent changes in the market value of the swap are entirely offset by subsequent changes in the market value of the counter-swap.

In December 2007, we placed a swap contract covering 1,680,000 Bbls of crude oil for the period from January 2008 to December 2012 at various fixed prices. In April 2008, we entered into a series of counter-swaps to lock-in the value of certain of these swaps settling 1,188,000 Bbls of crude oil swaps. In June 2009, we entered into an additional series of counter-swaps to lock-in the value of the remaining swaps settling 324,000 Bbls of crude oil swaps. In October 2011 we placed a swap contract covering 730,000 Bbls of crude oil for the period from January 2012 to December 2013 at a fixed price of $78.50 for 2012 and $80.55 for 2013. Such contracts and any future hedging arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in the price of oil.

At March 31, 2012, we had a net liability derivative position of $17.9 million related to our price swap derivatives.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from joint interest receivables (approximately $5.3 million at March 31, 2012) and receivables from the sale of our oil and natural gas production (approximately $5.7 million at March 31, 2012).

We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. For the three months ended March 31, 2012, three purchasers accounted for more than 10% of our revenue: Plains Marketing, L.P. (64%); Andrews Oil Buyers Inc. (14%); and Occidental Energy Marketing, Inc. (13%). For the years ended December 31, 2011 and 2010, one purchaser, Windsor Midstream LLC, an entity controlled by Wexford, our equity sponsor, accounted for approximately 78% and 81% of our revenue, respectively. For the year ended December 31, 2009, two purchasers accounted for more than 10% of our revenue: Windsor Midstream LLC (68.3%) and DCP Midstream, LP (14.8%). No other customer accounted for more than 10% of our revenue during these periods.

Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells. At March 31, 2012, we had two customers that represented approximately 88% of our total joint operations receivables. At each of

 

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December 31, 2011 and 2010, we had one customer that represented approximately 68% and 62%, respectively, of our total joint operations receivables. Prior to 2010, we did not operate the wells and, therefore, did not have joint operations receivables.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facility with BNP. The terms of our revolving credit facility with BNP provide for interest on borrowings at a floating rate equal to prime, LIBOR or federal funds rate plus margins ranging from 1.25% to 3.50% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. Borrowings under the credit facility bore interest at a weighted average rate of 3.3% as of March 31, 2012. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our net income (loss) of approximately $974,900 annually, based on the $97.5 million outstanding in the aggregate under our revolving credit facility with BNP as of March 31, 2012, and assuming no interest is capitalized. Pending use of the net proceeds from this offering to fund our exploration and development activities and for general corporate purposes, we intend to repay outstanding borrowings under our revolving credit facility with BNP.

Off-Balance Sheet Arrangements

We currently have no off-balance sheet arrangements. Please read Note 11 to our consolidated financial statements included elsewhere in this prospectus for a discussion of our commitments and contingencies, some of which are not recognized in the balance sheets under GAAP.

 

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BUSINESS

General

Overview

We are an independent oil and natural gas company currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. This basin, which is one of the major producing basins in the United States, is characterized by an extensive production history, a favorable operating environment, mature infrastructure, long reserve life, multiple producing horizons, enhanced recovery potential and a large number of operators.

We began operations in December 2007 with our acquisition of 4,134 net acres with production at the time of acquisition of approximately 800 BOE/d from 34 gross (16.8 net) wells in the Permian Basin. Subsequently, we acquired approximately 26,875 additional net acres, which brought our total net acreage position in the Permian Basin to 31,009 net acres at June 30, 2012 and, after giving effect to the Transactions, we had 51,623 net acres. We are the operator of approximately 99% of this acreage. As of June 30, 2012, after giving effect to the Transactions, we had drilled 159 gross (147 net) wells, and participated in an additional 15 gross (six net) non-operated wells, in the Permian Basin. Of these 174 gross wells, 160 were completed as producing wells and 14 were in various stages of completion. In the aggregate, as of June 30, 2012, we held interests in 194 gross (177 net) producing wells in the Permian Basin.

We built our current leasehold position through the following acquisitions and development activities in the Wolfberry play:

 

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In 2008, we acquired 6,247 net acres at the Spanish Trail and Munn prospects in Midland County, Texas through 11 leases and one mineral deed, with 5,146 net acres attributable to one lease;

 

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Commencing in 2008 and ending in 2010, we acquired leases at the Barron prospect in Midland County, Texas covering 225 net acres;

 

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Commencing in 2008 and ending in 2011, we acquired leases at the Gist prospect in Ector County, Texas covering 1,452 net acres;

 

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Commencing in 2008 and ending in 2012, we acquired 37 leases at the UL prospect in Andrews, Upton and Reagan Counties, Texas covering a total of 10,006 net acres;

 

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Beginning in 2008, we acquired 17 leases at the Hurt/WHL prospect in Ector County, Texas covering 2,779 net acres;

 

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In 2009, we acquired one lease at the Cumberland prospect located in Midland County, Texas covering 207 net acres;

 

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In 2010, we acquired leases at the North Howard prospect located in Howard County, Texas that currently cover 131 net acres;

 

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In 2010 and 2011, we acquired leases at the Big Max prospect located in Andrews County, Texas covering 848 net acres; and

 

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In 2012, we acquired leases in the Clete and Hume prospects in Crockett County, Texas that currently cover 4,979 net acres.

Our activities are primarily focused on the Clearfork, Spraberry, Wolfcamp, Cline, Strawn and Atoka formations, which we refer to collectively as the Wolfberry play. The Wolfberry play is characterized by high oil and liquids rich natural gas, multiple vertical and horizontal target horizons, extensive production history, long-lived reserves and high drilling success rates. The Wolfberry play is a modification and extension of the Spraberry play, the majority of which is designated in the Spraberry Trend area field. According to the U.S. Energy Information Administration, the Spraberry trend area ranks as the second largest oilfield in the United States, based on 2009 reserves.

 

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As of December 31, 2011, our estimated proved oil and natural gas reserves pro forma for the Transactions were 39,460 MBOE based on reserve reports prepared by Ryder Scott Company L.P., or Ryder Scott, our independent reserve engineers. Of these reserves, approximately 21.7% are classified as proved developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate are from 329 gross well locations on 40-acre spacing. As of December 31, 2011, these proved reserves were approximately 66% oil, 20% natural gas liquids and 14% natural gas.

We have 925 identified potential vertical drilling locations based on our evaluation of applicable geologic and engineering data, and we have an additional 1,122 identified potential vertical drilling locations based on 20-acre downspacing. These identified potential drilling locations do not include any potential horizontal drilling locations. We intend to grow our reserves and production through development drilling, exploitation and exploration activities on this multi-year project inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves. Our estimated ultimate recoveries, or EURs, from future PUD wells on 40-acre spacing, as estimated by Ryder Scott, range from 102 MBOE per well, consisting of 46 MBbls of oil, 143 MMcf of natural gas and 32 MBbls of natural gas liquids, to 158 MBOE per well, consisting of 112 MBbls of oil, 113 MMcf of natural gas and 27 MBbls of natural gas liquids, with an average EUR per well of 135 MBOE, consisting of 93 MBbls of oil, 102 MMcf of natural gas and 25 MBbls of natural gas liquids. We also intend to continue to refine our drilling pattern and completion techniques in an effort to increase our average EUR per well from vertical wells drilled on 40-acre spacing. We currently anticipate a reduction of approximately 20% in our EURs from vertical wells drilled on 20-acre spacing. Our 2012 drilling plan currently contemplates drilling 72 gross (65 net) vertical wells on 40-acre spacing and nine gross (eight net) horizontal wells in the Wolfberry play. As of June 30, 2012, we were using three drilling rigs and, upon completion of this offering, intend to increase our drilling program to six or seven rigs.

We believe the experience gained from our historical drilling programs and the information obtained from the results of extensive industry drilling activity in the Permian Basin have helped us reduce the risk and uncertainity associated with drilling vertical wells on our Permian Basin acreage. We intend to supplement our vertical development drilling activity with horizontal wells targeting various intervals in the Wolfberry play. Our horizontal drilling program is intended to further capture the upside potential that may exist on our properties and increase our well performance and recoveries as compared to drilling vertical wells alone.

During 2011, we assembled a new executive team and, beginning with the fourth quarter of 2011, this team assumed management control of our operations and development activities in the Permian Basin. With an average of approximately 24 years of industry experience per person, this team has extensive experience in the Permian Basin as well as other resource plays in North America, including significant experience in drilling and completing horizontal wells. Under the direction of our new executive team, the average drilling time required to reach total depth, or TD, was shortened by 25% to 15 days during the fourth quarter of 2011 from 20 days during the second quarter of 2011, and our average gross well cost (including drilling and completion cost) was reduced from $2.6 million during the second quarter of 2011 to $2.5 million during the first quarter of 2012. We also reduced the time from spud to production from an average of 68 days during the second quarter of 2011 to an average of 50 days during the first quarter of 2012. Also, during the three months ended March 31, 2012 our average daily production, pro forma for the Transactions, was 3,280 BOE/d, consisting of 2,413 Bbls/d of oil, 2,267 Mcf/d of natural gas and 489 Bbls/d of natural gas liquids, an increase of 11%, or 333 BOE/d, from 2,947 BOE/d, consisting of 2,191 Bbls/d of oil, 2,128 Mcf/d of natural gas and 401 Bbls/d of natural gas liquids, for the quarter ended December 31, 2011. This increase was due primarily to improved strategies and procedures introduced by our new executive team relating to wellbore configuration, completion, execution, fluid recovery and well pumping practices that significantly reduced the level of required well remediation and the associated loss of production. We anticipate further increases in efficiencies as our new executive team executes on our development strategies across our acreage base.

 

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The following table provides a summary of selected operating information of our properties, pro forma for the Transactions. The information is as of June 30, 2012 except as otherwise noted.

 

Basin		Net Acreage				Average Working Interest				Identified Potential Drilling Locations(1)								2012 Budget												Estimated Net Proved Reserves at December 31, 2011								Average Daily Production (BOE/d)(3)
										Gross				Net				Gross Wells(2)				Net Wells(2)				Capex (In millions)				MBOE				% Developed
Permian			51,623				86.9	%			925				855				90				75			$	180.0 - $190.0				39,460				23.9				3,603

 

(1)

Reflects identified potential vertical drilling locations on 40-acre spacing based on our evaluation of applicable geologic and engineering data. We have an additional 1,122 gross (1,025 net) identified potential vertical drilling locations based on 20-acre downspacing. These identified potential drilling locations do not include any potential horizontal drilling locations. The drilling locations on which we actually drill wells will ultimately depend on the availability of capital, regulatory approvals, oil and natural gas prices, costs, actual drilling results and other factors.

(2)	Includes 81 gross (72 net) wells for which we are the operator and nine gross (three net) non-operated wells.

(3)	During April 2012.

We currently anticipate our 2012 capital budget for drilling and infrastructure will be approximately $180.0 million to $190.0 million after giving effect to the Transactions. Of this amount, we plan to spend approximately $158.0 million on the drilling and completion of 72 gross (65 net) operated vertical wells and nine gross and eight net horizontal wells, $10.5 million for the drilling and completion of nine non-operated wells, $8.0 million for leasehold acquisitions and $6.0 million for the construction of infrastructure to support production, including investments in water disposal infrastructure and gathering line projects. During the five months ended May 31, 2012, our aggregate capital expenditures for drilling and infrastructure after giving effect to the Transactions were $66.4 million.

Our Business Strategy

Our business strategy is to increase stockholder value through the following:

 

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Grow production and reserves by developing our oil-rich resource base. We intend to actively drill and develop our acreage base in an effort to maximize its value and resource potential. Through the conversion of our undeveloped reserves to developed reserves, we will seek to increase our production, reserves and cash flow while generating favorable returns on invested capital. As of June 30, 2012, after giving effect to the Transactions, we had 925 identified potential vertical drilling locations on our acreage in the Permian Basin based on 40-acre spacing and an additional 1,122 such locations based on 20-acre downspacing. We believe the drilling of these locations will provide us with the critical subsurface data necessary to target potential horizontal horizons. Our 2012 drilling plan currently contemplates drilling 72 gross (65 net) vertical wells and nine gross (eight net) horizontal wells in the Wolfberry play. We ended 2011 with a two rig drilling program which we increased to four drilling rigs in 2012. As of June 30, 2012, we were using three drilling rigs. Upon completion of this offering, we intend to increase our drilling program to six or seven rigs. Subject to market conditions and rig availability, we expect to operate up to eight rigs in 2013, which we expect will allow us to significantly increase our drilling program in 2013.

 

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Focus on increasing hydrocarbon recovery through horizontal drilling and increased well density. We believe there are opportunities to target various intervals in the Wolfberry play with horizontal wells and we currently plan to drill nine gross (eight net) horizontal wells in 2012 to target these producing horizons. Our horizontal drilling program is designed to further capture the upside potential that may exist on our properties. We also believe our horizontal drilling program may significantly increase our recoveries per section as compared to drilling vertical wells alone. Horizontal drilling may also be economical in areas where vertical drilling is currently not economical or logistically viable. In addition, we believe increased well density opportunities may exist across our acreage base. We closely monitor industry trends with respect to higher well density, which could increase the recovery factor per section and enhance returns since infrastructure is typically in place.

 

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Leverage our experience operating in the Permian Basin. Our executive team, which has an average of approximately 24 years of industry experience per person and significant experience in the Permian Basin, intends to continue to seek ways to maximize hydrocarbon recovery by refining and enhancing our drilling and completion techniques. The time to reach TD for our vertical Wolfberry wells decreased from an average of 20 days during the second quarter of 2011 to an average of 15 days during the fourth quarter of 2011, resulting in a lower total well cost. Our focus on efficient drilling and completion techniques, and the resulting reduction in time to reach TD, is an important part of the continuous drilling program we have planned for our significant inventory of identified potential drilling locations. In addition, we believe that the experience of our new executive team in deviated and horizontal drilling and completions should help reduce the execution risk normally associated with these complex well paths. Additionally, our completion techniques are continually evolving as we evaluate hydraulic fracturing practices that may potentially increase recovery and reduce completion costs. Our executive team regularly evaluates our operating results against those of other operators in the area in an effort to benchmark our performance against the best performing operators and evaluate and adopt best practices.

 

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Enhance returns through our low cost development strategy of resource conversion, capital allocation and continued improvements in operational and cost efficiencies. In the current commodity price environment, our oil and liquids rich asset base provides attractive returns. Our acreage position in the Wolfberry play is generally in contiguous blocks which allows us to develop this acreage efficiently with a “manufacturing” strategy that takes advantage of economies of scale and uses centralized production and fluid handling facilities. We are the operator of approximately 99% of our acreage. This operational control allows us to more efficiently manage the pace of development activities and the gathering and marketing of our production and control operating costs and technical applications, including horizontal development. Our average 86.2% working interest in our acreage pro forma for the Transactions allows us to realize the majority of the benefits of these expected improvements and cost efficiencies.

 

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Pursue strategic acquisitions with exceptional resource potential. We have a proven history of acquiring leasehold positions in the Permian Basin that we believe have substantial oil-weighted resource potential and can achieve attractive returns on invested capital. Our executive team, with its extensive experience in the Permian Basin, has what we believe is a competitive advantage in identifying acquisition targets and a proven ability to evaluate resource potential. We intend to continue to pursue acquisitions that meet our strategic and financial targets.

 

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Maintain Financial flexibility. We seek to maintain a conservative financial position. As of June 30, 2012, on a pro forma basis after giving effect to this offering and the use of the net proceeds from this offering to repay borrowing under our revolving credit facility, we would have had approximately $90.0 million of available borrowing capacity under such facility. We expect that we will fund our capital development plans for 2012 from our operating cash flow and borrowings under our revolving credit facility. We intend to use the net proceeds from this offering to repay borrowings outstanding under our revolving credit facility pending their use to fund our capital expenditures.

Our Strengths

We believe that the following strengths will help us achieve our business goals:

 

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Oil rich resource base in one of North America’s leading resource plays. All of our leasehold acreage is located in one of the most prolific oil plays in North America, the Permian Basin in West Texas. As of June 15, 2012, the Baker Hughes Rig Count survey reported that there were 453 rigs drilling in the Permian Basin. The majority of our current properties are well positioned in the core of the Wolfberry play. We believe that our historical vertical development success will be complemented with horizontal drilling locations that could ultimately translate into an increased recovery factor on a per section basis. Our production was approximately 74% oil, 15% natural gas liquids and 11% natural gas for both the

 

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year ended December 31, 2011 and the three months ended March 31, 2012. As of December 31, 2011, after giving effect to the Transactions, our estimated net proved reserves were comprised of approximately 66% oil and 20% natural gas liquids. This oil and liquids exposure allows us to benefit from their currently more favorable prices as compared to natural gas.

 

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Multi-year drilling inventory in one of North America’s leading oil resource plays. We have identified a multi-year inventory of potential drilling locations for oil-weighted reserves that we believe provides attractive growth and return opportunities. As of June 30, 2012, after giving effect to the Transactions, we had 925 identified potential vertical drilling locations based on 40-acre spacing and an additional 1,122 identified potential vertical drilling locations based on 20-acre downspacing. In 2012, after giving effect to the Transactions, we anticipate drilling 72 gross (65 net) vertical operated wells, which represent only approximately 7.8% of our identified vertical potential drilling locations on 40-acre spacing at June 30, 2012. We also believe that there are a significant number of horizontal locations that could be drilled on our acreage. We expect to drill nine gross (eight net) horizontal operated wells during 2012 targeting three different producing horizons. Management currently estimates that EURs for our horizontal wells will be approximately 400 MBOE. In addition, the liquids rich natural gas component of our inventory adds value with Btu content ranging from 1,243 MMBtu to 1,578 MMBtu and our March 2012 natural gas liquids yield was 122 Bbls/MMcf. In addition, we have approximately 117 square miles of proprietary 3-D seismic data covering our acreage. This data facilitates the evaluation of our existing drilling inventory and provides insight into future development activity, including horizontal drilling opportunities and strategic leasehold acquisitions.

 

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Experienced, incentivized and proven management team. Our new executive team has an average of approximately 24 years of industry experience per person, most of which is focused on resource play development. This team has a proven track record of executing on multi-rig development drilling programs and extensive experience in the Permian Basin. In addition, our executive team has significant experience with both drilling and completing horizontal wells as well as horizontal well reservoir and geologic expertise, which will be of strategic importance as we expand our future development plans to include horizontal drilling. Prior to joining us, our Chief Executive Officer held management positions at Apache Corporation, Laredo Petroleum Holdings, Inc. and Burlington Resources.

 

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Favorable and stable operating environment. We have focused our drilling and development operations in the Permian Basin, one of the oldest hydrocarbon basins in the United States, with a long and well-established production history and developed infrastructure. With over 400,000 wells drilled in the Permian Basin since the 1940s, we believe that the geological and regulatory environment is more stable and predictable, and that we are faced with less operational risks, in the Permian Basin as compared to emerging hydrocarbon basins.

 

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High degree of operational control. We are the operator of approximately 99% of our Permian Basin acreage. This operating control allows us to better execute on our strategies of enhancing returns through operational and cost efficiencies and increasing ultimate hydrocarbon recovery by seeking to continually improve our drilling techniques, completion methodologies and reservoir evaluation processes. Additionally, as the operator of substantially all of our acreage, we retain the ability to adjust our capital expenditure program based on commodity price outlooks. This operating control also enables us to obtain data needed for efficient exploration of horizontal prospects.

 

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Financial flexibility to fund expansion. Upon the completion of this offering, we will have a conservative balance sheet. We will seek to maintain financial flexibility to allow us to actively develop our drilling, exploitation and exploration activities in the Wolfberry play and maximize the present value of our oil-weighted resource potential. As of June 30, 2012, on a pro forma basis after giving effect to this offering and the use of the net proceeds from this offering to repay borrowings under our revolving credit facility, we would have had approximately $90.0 million of available borrowing capacity under our revolving credit facility. We expect that our borrowing base will be increased as a result of the Transaction.

 

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Our Properties

Review of Exploration, Exploitation and Development Activities

The following table summarizes certain operating information of our properties, pro forma for the Transaction. The information is as of June 30, 2012 except as otherwise noted.

 

		Net Acreage				Average Working Interest				Identified Potential Drilling Locations(1)								2012 Budget												Estimated Net  Proved Reserves at December 31, 2011								Average Daily Production (BOE/d)(3)
Basin										Gross				Net				Gross Wells(2)				Net Wells(2)				Capex (In millions)				MBOE				% Developed
Permian			51,623				86.9	%			925				855				90				75			$	180.0 - $190.0				39,460				23.9				3,603

 

(1)

Reflects identified potential vertical drilling locations on 40-acre spacing based on our evaluation of applicable geologic and engineering data. We have an additional 1,122 gross (1,025 net) identified potential vertical drilling locations based on 20-acre downspacing. These identified potential drilling locations do not include any potential horizontal drilling locations. The drilling locations on which we actually drill wells will ultimately depend on the availability of capital, regulatory approvals, oil and natural gas prices, costs, actual drilling results and other factors.

(2)	Includes 81 gross (72 net) wells for which we are the operator and nine gross (three net) non-operated wells.

(3)	During April 2012.

Permian Basin

Location and Land

We acquired approximately 4,134 net acres in West Texas (near Midland) in the Permian Basin on December 20, 2007, with an effective date of November 1, 2007, from ExL Petroleum, LP, Ambrose Energy I, Ltd. and certain other sellers. Subsequently, we acquired approximately 26,875 additional net acres, which brought our total net acreage position in the Permian Basin to approximately 31,009 net acres at March 31, 2012 and, after giving effect to the Transactions, we had 51,623 net acres. Since our initial acquisition in the Permian Basin through June 30, 2012, we drilled or participated in the drilling of 169 gross (101 net) wells (or 174 gross (153 net) wells after giving effect to the Transactions) on our leasehold in this area, primarily targeting the Wolfberry play. We are the operator of approximately 99% of our Permian Basin acreage. The Permian Basin area covers a significant portion of western Texas and eastern New Mexico and is considered one of the major producing basins in the United States.

Area History

Our proved reserves are located in the Permian Basin of West Texas, in particular in the Clearfork, Spraberry, Wolfcamp, Cline, Strawn and Atoka formations. The Spraberry play was initiated with production from several new field discoveries in the late 1940s and early 1950s. It was eventually recognized that a regional productive trend was present, as fields were extended and coalesced over a broad area in the central Midland Basin. Development in the Spraberry play was sporadic over the next several decades due to typically low productive rate wells, with economics being dependent on oil prices and drilling costs.

The Wolfcamp formation is a long-established reservoir in West Texas, first found in the 1950s as wells aiming for deeper targets occasionally intersected slump blocks or debris flows with good reservoir properties. Exploration using 2-D seismic data located additional fields, but it was not until the use of 3-D seismic data in the 1990s that the greater extent of the Wolfcamp formation was revealed. The additional potential of the shales within this formation as reservoir rather than just source rocks was not recognized until very recently.

During the late 1990s, Atlantic Richfield Company, or Arco, began a drilling program targeting the base of the Spraberry formation at 10,000 feet, with an additional 200 to 300 feet drilled to produce from the upper

 

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portion of the Wolfcamp formation. Henry Petroleum, a private firm, owned interests in the Pegasus field in Midland and Upton counties. While drilling in the same area as the Arco project, Henry Petroleum decided to drill completely through the Wolfcamp section. Henry Petroleum mapped the trend and began acquiring acreage and drilling wells using multiple slick-water fracturing treatments across the entire Wolfcamp interval. In 2005, former members of Henry Petroleum’s Wolfcamp team formed their own private company, ExL Petroleum, and began replicating Henry Petroleum’s program. After ExL had drilled 32 productive Wolfcamp/Spraberry wells through late 2007, they monetized a portion of their acreage position, which led to the acquisition that enabled us to begin our participation in this play. Recent advancements in enhanced recovery techniques and horizontal drilling continue to make this play attractive to the oil and gas industry. By mid-2010, approximately half of the rigs active in the Permian Basin were drilling wells in the Wolfberry play. As of June 30, 2012, we held interests in 194 gross (177 net) producing wells.

Geology

The Permian Basin formed as an area of rapid Mississippian-Pennsylvanian subsidence in the foreland of the Ouachita fold belt. It is one of the largest sedimentary basins in the U.S., and has oil and gas production from several reservoirs from Permian through Ordovician in age. The term “Wolfberry” was coined initially to indicate commingled production from the Permian Spraberry, Dean and Wolfcamp formations. In this prospectus, we refer to the Clearfork, Spraberry, Wolfcamp, Cline, Strawn and Atoka formations collectively as the Wolfberry play. The Wolfberry play of the Midland Basin lies in the area where the historically productive Spraberry trend geographically overlaps the productive area of the emerging Wolfcamp play. The Spraberry was deposited as turbidites in a deep water submarine fan environment, while the Wolfcamp reservoirs consist of debris-flow and grain-flow sediments, which were also deposited in a submarine fan setting. The best carbonate reservoirs within the Wolfcamp are generally found in proximity to the Central Basin Platform, while the shale reservoirs within the Wolfcamp thicken basinward away from the Central Basin Platform. Both the Spraberry and Wolfcamp contain organic-rich mudstones and shales which, when buried to sufficient depth for maturation, became the source of the hydrocarbons found in the reservoirs.

The Wolfberry play can be generally characterized as a combination of low-permeability clastic, carbonate and shale reservoirs which are hydrocarbon-charged and are economic due to the overall thickness of the section (more than 3,000 feet) and application of enhanced stimulation (fracking) techniques. The Wolfberry is an unconventional “basin-centered oil” resource play, in the sense that there is no regional downdip oil/water contact.

Several shale intervals within the Wolfcamp formation are currently being evaluated for horizontal development potential, with initial drilling expected in 2012. The shales exhibit micro-darcy permeabilities, which result in relatively small drainage areas and recovery factors. Because of this, we believe the horizontal exploitation of these reservoirs will supplement, and not replace, the vertical development program.

There are also productive carbonate and shale intervals within the shallower Permian Clearfork formation. Two shale intervals within the Clearfork formation are currently being evaluated for potential horizontal development. Below the Wolfcamp formation lie the Pennsylvanian Strawn and Atoka formations. Although difficult to predict, there are conventional pay intervals that develop locally within these formations which, when present, can add significant reserves.

Debris flows within the Spraberry and Wolfcamp carbonates have been observed on 3-D seismic surveys. Initial tests have confirmed the presence of enhanced reservoir. Additionally, structural closures have been mapped and are being evaluated for drilling to test deeper targets. Our extensive geophysical database, which includes approximately 117 square miles of proprietary 3-D seismic data, will be used to highgrade future locations.

Ryder Scott, an independent petroleum engineering firm, has estimated that at December 31, 2011, proved reserves net to our interest in these assets were approximately 24,750 MBOE, of which 22.0% were classified as

 

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proved developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate were from 293 gross well locations on 40-acre spacing. The proved reserves are generally characterized as long-lived, with predictable production profiles.

Production Status

In April 2012, net production from our Permian Basin acreage, pro forma for the Transactions, was 108,090 BOE, or an average of 3,603 BOE/d, of which 72% was oil, 16% was natural gas liquids and 12% was natural gas. From January 1, 2011 through December 31, 2011, our average daily net production from our Permian Basin acreage, pro forma for the Transactions, was 2,514 BOE/d, of which 71% was from oil, 17% was from natural gas liquids and 12% was from natural gas.

Facilities

Our land oil and gas processing facilities are typical of those found in the Permian Basin. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units.

Recent and Future Activity

During 2011, 54 gross (31 net) wells were drilled on our Permian Basin acreage for an aggregate estimated net cost of $82.2 million. On a pro forma basis after giving effect to the Transactions, 56 gross (49 net) wells were drilled on our Permian acreage during 2011. As of June 30, 2012, we had 925 identified potential vertical drilling locations based on 40-acre spacing and an additional 1,122 identified potential vertical drilling locations based on 20-acre downspacing. We currently expect to drill an estimated 72 gross (65 net) vertical wells and nine gross (eight net) horizontal wells on our acreage in 2012. The wells are expected to be drilled to approximately 11,200 feet at an estimated average completed gross well cost of approximately $1.9 million to $2.4 million per vertical well and $6.0 million to $7.0 million per horizontal well. In this prospectus, we define identified potential drilling locations as locations specifically identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic and engineering data on 40-acre or 20-acre downspacing as indicated. The availability of local infrastructure, drilling support assets and other factors as management may deem relevant, such as easement restrictions and state and local regulations, are considered in determining such locations. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other factors.

Oil and Gas Data

Proved Reserves

SEC Rule-Making Activity

In December 2008, the SEC released its final rule for “Modernization of Oil and Gas Reporting.” These rules require disclosure of oil and gas proved reserves by significant geographic area, using the arithmetic 12-month average beginning-of-the-month price for the year, as opposed to year-end prices as had previously been required unless contractual arrangements designate the price to be used. Other significant amendments included the following:

 

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Disclosure of unproved reserves: probable and possible reserves may be disclosed separately on a voluntary basis.

 

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Proved undeveloped reserve guidelines: reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.

 

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Reserves estimation using new technologies: reserves may be estimated through the use of reliable technology in addition to flow tests and production history.

 

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Reserves personnel and estimation process: additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process. We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate.

 

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Non-traditional resources: the definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method of extraction.

We adopted the rules effective December 31, 2009, as required by the SEC.

Evaluation and Review of Reserves

Our historical reserve estimates were prepared by Ryder Scott as of December 31, 2011 and by Pinnacle as of December 31, 2010 and 2009, in each case with respect to our assets in the Permian Basin. Reserve estimates for properties attributable to Windsor UT and the properties subject to the Gulfport transaction were prepared, in each case, by Ryder Scott as of December 31, 2011.

Each of Ryder Scott and Pinnacle is an independent petroleum engineering firm. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Neither independent third-party engineering firm owns an interest in any of our properties or is employed by us on a contingent basis.

Under SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our 2011 proved reserves were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The proved reserves for our properties were estimated by performance methods, analogy or a combination of both methods. Approximately 85% of the proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of available historical production and pressure data. The remaining 15% of the proved reserves were estimated by analogy, or a combination of performance and analogy methods. The analogy method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate. All proved developed non-producing and undeveloped reserves were estimated by the analogy method.

To estimate economically recoverable proved reserves and related future net cash flows, Ryder Scott considered many factors and assumptions, including the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements and forecasts of future production rates. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our

 

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proved reserves included production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data and historical well cost and operating expense data.

We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets in the Permian Basin. Our internal technical team members met with our independent reserve engineers periodically during the period covered by the reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to the independent reserve engineers for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs. Our Vice President—Reservoir Engineering is primarily responsible for overseeing the preparation of all of our reserve estimates. Our Vice President—Reservoir Engineering is a petroleum engineer with over 30 years of reservoir and operations experience and our geoscience staff has an average of approximately 26 years of industry experience per person. Our technical staff uses historical information for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs.

The preparation of our proved reserve estimates are completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

 

•

review and verification of historical production data, which data is based on actual production as reported by us;

 

•

preparation of reserve estimates by our Vice President—Reservoir Engineering or under his direct supervision;

 

•

review by our Vice President—Reservoir Engineering of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;

 

•

direct reporting responsibilities by our Vice President—Reservoir Engineering to our Chief Executive Officer; and

 

•

verification of property ownership by our land department.

 

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The following table presents our estimated net proved oil and natural gas reserves and the present value of our reserves as of December 31, 2011, based on the reserve report prepared by Ryder Scott, and as of December 31, 2010 and 2009, based on the reserve reports prepared by Pinnacle, each an independent petroleum engineering firm, and such reserve reports have been prepared in accordance with the rules and regulations of the SEC. All our proved reserves included in the reserve reports are located in North America. Ryder Scott and Pinnacle prepared all our reserve estimates as of the periods covered by their respective reports. The following table also sets forth estimates of our net proved oil and natural gas reserves as of December 31, 2011 on a pro forma basis after giving effect to the contribution of Windsor UT to Windsor Permian and the Gulfport contribution as if they had occurred on December 31, 2011. The reserves attributable to the Windsor UT properties and the properties subject to the Gulfport transaction have been prepared by Ryder Scott. Copies of the reserve reports as of December 31, 2011 prepared by Ryder Scott with respect to our properties, the Windsor UT properties and the properties subject to the Gulfport transaction are attached to this prospectus as Appendices B, C and D. Our estimates of net proved reserves have not been filed with or included in reports to any federal authority or agency other than the SEC in connection with this offering.

 

		Pro Forma				Historical
		Year Ended December 31, 2011				Year Ended December 31,
						2011				2010				2009
Estimated proved developed reserves:
Oil (Bbls)			6,046,099				3,805,291				3,307,550				1,954,060
Natural gas (Mcf)			8,335,945				5,186,941				4,255,300				2,453,750
Natural gas liquids (Bbls)			1,969,710				1,233,318				1,105,216				591,532
Total (BOE)			9,405,133				5,903,099				5,121,983				2,954,550
Estimated proved undeveloped reserves:
Oil (Bbls)			20,140,377				12,911,578				15,511,500				27,276,880
Natural gas (Mcf)			24,261,522				14,431,926				17,407,420				25,028,070
Natural gas liquids (Bbls)			5,870,849				3,529,955				4,458,762				6,930,693
Total (BOE)			30,054,813				18,846,854				22,871,499				38,378,918
Estimated Net Proved Reserves:
Oil (Bbls)			26,186,476				16,716,869				18,819,050				29,230,940
Natural gas (Mcf)			32,597,467				19,618,867				21,662,720				27,481,820
Natural gas liquids (Bbls)			7,840,559				4,763,273				5,563,978				7,522,225
Total (BOE)(1)			39,459,946				24,749,952				27,993,481				41,333,468
Percent proved developed			23.8	%			23.9	%			18.3	%			7.1	%

 

(1)

Estimates of reserves as of December 31, 2011, 2010 and 2009 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods ended December 31, 2011, 2010 and 2009, respectively, in accordance with revised SEC guidelines applicable to reserves estimates as of the end of such periods. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

The foregoing reserves are all located within the continental United States. Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and

 

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assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See “Risk Factors” beginning on page 16 of this prospectus. We have not filed any estimates of total, proved net oil or natural gas reserves with any federal authority or agency other than the SEC.

Additional information regarding our proved reserves can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations” and “—Critical Accounting Policies and Estimates” beginning on pages 62 and 78, respectively, of this prospectus, the notes to our consolidated financial statements included elsewhere in this prospectus and the reserve reports as of December 31, 2011 included as Appendices B, C and D to this prospectus.

Proved Undeveloped Reserves (PUDs)

As of December 31, 2011, our proved undeveloped reserves totaled 12,912 MBbls of oil, 14,432 MMcf of natural gas and 3,530 MBbls of natural gas liquids, for a total of 18,847 MBOE. On a pro forma basis after giving effect to the Transactions, at December 31, 2011 our total proved undeveloped reserves would have totaled 20,140 MBbls of oil, 24,262 MMcf of natural gas and 5,871 MBbls of natural gas liquids for a total of 30,055 MBOE. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

Changes in PUDs that occurred during 2011 on a pro forma basis after giving effect to the Transactions were primarily due to:

 

•

Additions of 7,133 MBOE attributable to extensions resulting from strategic drilling of wells by us to delineate our acreage position;

 

•

Conversion of approximately 3,619 MBOE attributable to PUDs into proved developed reserves;

 

•

Negative revisions of approximately 1,639 MBOE in PUDs due to revisions related to offset well performance;

 

•

Exclusion of 1,447 MBOE attributable to PUD locations that were not scheduled to be drilled within the next five years; and

 

•

Movement of 6,116 MBOE from PUD to probable reserves due to changes in booking methodology used by our new independent petroleum engineers and well performance in one prospect area. The 2011 reserve report prepared by Ryder Scott assigned PUDs only in close proximity to seasoned production. The prior reports prepared by Pinnacle utilized a methodology consistent with large resource basins where geologic risk is minimal. The methodology utilized by Pinnacle typically results in a greater number of PUD locations than the “close proximity” method used by Ryder Scott. There was also a shift of 2,748 MBOE from proved to probable reserves in one prospect area where existing well performance declined more quickly than originally projected. Locations in this area were moved to the probable reserve category until more production history is obtained to confirm the economic viability of the area.

Costs incurred relating to the development of PUDs were approximately $52.8 million during 2011 and approximately $80.9 million on a pro forma basis after giving effect to the Transactions as if they had occurred on January 1, 2011. Estimated future development costs relating to the development of PUDs are projected to be approximately $106.9 million in 2012, $165.2 million in 2013, $151.3 million in 2014, $131.0 million in 2015 and $124.0 million in 2016 after giving effect to the Transactions. Since our new executive team assumed management control in 2011, our average drilling costs and drilling times have been reduced. As we continue to develop our properties and have more well production and completion data, we believe we will continue to realize cost savings and experience lower relative drilling and completion costs as we convert PUDs into proved developed reserves in upcoming years.

All of our PUD drilling locations are scheduled to be drilled prior to the end of 2016.

As of December 31, 2011, 2% of our total proved reserves were classified as proved developed non-producing.

 

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Oil and Gas Production Prices and Production Costs

Production and Price History

The following table sets forth information regarding net production of oil, natural gas and natural gas liquids, and certain price and cost information for each of the periods indicated:

 

		Pro Forma								Historical
		Three Months Ended March 31, 2012				Year Ended December 31, 2011				Three Months Ended March 31,								Year Ended December 31,
										2012				2011				2011				2010				2009
Production Data:
Oil (Bbls)							651,453				147,992				101,404				441,822				280,721				168,741
Natural gas (Mcf)							685,640				132,336				82,301				413,640				323,847				253,321
Natural gas liquids (Bbl)							151,815				29,510				19,742				86,815				79,978				70,384
Combined volumes (BOE)							917,521				199,558				134,863				597,577				414,674				281,345
Daily combined volumes (BOE/d)							2,514				2,193				1,498				1,637				1,136				771
Average Prices(1):
Oil (per Bbl)		$				$	92.14			$	96.62			$	91.79			$	92.26			$	76.51			$	58.01
Natural gas (per Mcf)							4.01				2.62				3.88				3.98				4.32				3.64
Natural gas liquids (per Bbl)							53.72				46.01				48.48				54.98				44.56				28.49
Combined (per BOE)							77.30				80.20				78.48				78.95				63.77				45.20
Average Costs (per BOE):
Lease operating expense		$				$	17.46			$	13.44			$	16.29			$	17.31			$	11.07			$	8.41
Gathering and transportation expense							0.22				0.34				0.26				0.34				0.26				0.15
Production taxes							3.97				3.91				3.88				3.91				3.25				2.36
Production taxes as a % of sales							5.1	%			4.9	%			4.9	%			4.9	%			5.1	%			5.2	%
Depreciation, depletion and amortization							29.10				23.38				26.82				25.78				19.64				11.43
General and administrative							3.97				5.97				4.46				6.03				7.36				17.99

 

(1)

After giving effect to our hedging arrangements in effect during the three months ended March 31, 2012 and 2011, respectively, the average prices per Bbl of oil and per BOE were $87.40 and $73.36, respectively, during the first quarter of 2012 and $91.67 and $78.39, respectively, during the first quarter of 2011. After giving effect to our hedging arrangements in effect during 2009, the average prices per Bbl of oil and per BOE (on a combined basis) were $41.59 and $35.35, respectively, during that year. Average prices for our hydrocarbons were not impacted by our hedging arrangements during 2011 or 2010.

Productive Wells

As of June 30, 2012, we owned an average 58.5% working interest in 190 gross (111 net) productive wells. On a pro forma basis after giving effect to the Transactions, at June 30, 2012 we would have owned an average 91.0% working interest in 194 gross (177 net) productive wells. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.

 

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Developed and Undeveloped Acreage

The following table sets forth information as of June 30, 2012 relating to our leasehold acreage:

 

Developed  Acreage(1)

Undeveloped  Acreage(2)

Total Acreage

Basin

Gross(3)

Net(4)

Gross(3)

Net(4)

Gross(3)

Net(4)

Permian

8,000

4,505

46,428

26,504

54,428

31,009

 

(1)	Developed acres are acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease.

(2)	Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

(3)	A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

(4)	A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

On a pro forma basis after giving effect to the Transactions, at June 30, 2012 our net developed, undeveloped and total acreage would have been 7,073, 44,550 and 51,623, respectively.

Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. The following table sets forth the gross and net undeveloped acreage (after giving effect to the Transactions) that will expire over the next five years unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates.

 

		Remaining 2012								2013								2014								2015								2016
Basin		Gross				Net				Gross				Net				Gross				Net				Gross				Net				Gross				Net
Permian			160				160				400				222				2,651				2,065				21,395				17,846				7,133				7,133

Drilling Results

The following table sets forth information with respect to the number of wells completed during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.

 

		Year ended December 31,
		2011								2010								2009
		Gross				Net				Gross				Net				Gross				Net
Development:
Productive			39				23				41				27				11				8
Dry			—				—				—				—				—				—
Exploratory:
Productive			7				4				—				—				—				—
Dry			—				—				—				—				—				—
Total:
Productive			46				27				41				27				11				8
Dry			—				—				—				—				—				—

 

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As of December 31, 2011, we had 12 gross (6.4 net) wells in the process of drilling, completing or dewatering or shut in awaiting infrastructure that are not reflected in the above table. Since our initial acquisition in the Permian Basin through June 30, 2012, we drilled or participated in the drilling of 169 gross (101 net) wells in the Permian Basin (or 174 gross (153 net) wells after giving effect to the Transactions), of which we operate 154 gross (95 net) wells (or 159 gross (147 net) net wells after giving effect to the Transactions). Of the 174 gross wells drilled, 160 were completed as producing wells and 14 are in various stages of completion.

Operations

General

We are the operator of approximately 99% of our Permian Basin acreage. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We employ petroleum engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.

Marketing and Customers

We market the majority of the oil and natural gas production from properties we operate for both our account and the account of the other working interest owners in these properties. We sell our natural gas production to purchasers at market prices. In March 2009, we entered into an agreement with Windsor Midstream LLC, or Midstream, an entity controlled by Wexford, our equity sponsor. During 2010 and 2011, Midstream purchased a significant portion of our oil volumes. For a description of this agreement, see “Related Party Transactions—Marketing Services” on page 130 of this prospectus. We sell all of our natural gas under contracts with terms of greater than twelve months and all of our oil under contracts with terms of twelve months or less.

We normally sell production to a relatively small number of customers, as is customary in the exploration, development and production business. For the three months ended March 31, 2012, three purchasers accounted for more than 10% of our revenue: Plains Marketing, L.P. (64%); Andrews Oil Buyers, Inc. (14%); and Occidental Energy Marketing, Inc. (13%). For the years ended December 31, 2011 and 2010, one purchaser, Midstream, accounted for approximately 78% and 81% of our revenue, respectively. For the year ended December 31, 2009, two purchasers accounted for more than 10% of our revenue: Windsor Midstream LLC (68.3%) and DCP Midstream, LP (14.8%). No other customer accounted for more than 10% of our revenue during these periods. If a major customer decided to stop purchasing oil and natural gas from us, revenue could decline and our operating results and financial condition could be harmed. However, based on the current demand for oil and natural gas, and the availability of other purchasers, we believe that the loss of any one or all of our major purchasers would not have a material adverse effect on our financial condition and results of operations, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

On May 24, 2012, we entered into an oil purchase agreement with Shell Trading (US) Company, or Shell Trading, in which we agreed to sell specified quantities of oil to Shell Trading. We are obligated to commence delivery of our oil to Shell Trading upon completion of the reversal of the Longhorn pipeline and its conversion for oil shipment, which we refer to as the completion date, which is currently anticipated to occur at the end of the first quarter of 2013. Our agreement with Shell Trading has an initial term of five years from the completion date. Each party has the right to terminate the agreement by written notice to the other party without any obligations to the other party in the event that the completion date does not occur by January 15, 2014. The agreement may also be terminated by Shell Trading by written notice to us in the event that Shell Trading’s contract for transportation on the pipeline is terminated.

Our delivery obligation under this agreement is 5,000 barrels per day from the service commencement date to March 31, 2013, 6,000 barrels per day from April 1, 2013 to September 30, 2013 and 8,000 barrels per day during the remainder of the term of the agreement. We have a one-time right to elect to decrease the contract

 

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quantity by not more than 20% of the then-current quantity, which decreased contract quantity will be effective for the remainder of the term of the agreement. Shell Trading has agreed to pay to us the price per barrel of oil based on the arithmetic average of the daily settlement price for “Light Sweet Crude Oil” Prompt Month future contracts reported by the New York Mercantile Exchange over the one-month period, as adjusted based on adjustment formulas specified in the agreement. If we fail to deliver the required quantities of oil under the agreement, we have agreed to pay Shell Trading certain deficiency payments.

Transportation

During the initial development of our fields we consider all gathering and delivery infrastructure in the areas of our production. Our oil is transported from the wellhead to our tank batteries by our gathering systems. The oil is then transported by the purchaser by truck to a tank farm where it is further transported by pipeline. Our natural gas is generally transported from the wellhead to the purchaser’s pipeline interconnection point through our gathering system.

Competition

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Title to Properties

As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties. At such time as we determine to conduct drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and gas industry. Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 18.75% to 25.00%, resulting in a net revenue interest to us generally ranging from 81.25% to 75.00%.

 

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Regulation

Environmental Matters and Regulation

Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, or EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future.

Waste Handling. The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions. However, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Remediation of Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as CERCLA or the “Superfund” law, and analogous state laws, generally imposes strict and joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment.

 

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These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released.

Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act,” the Safe Drinking Water Act, the Oil Pollution Act, or OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on October 20, 2011, the EPA announced a schedule to develop pre-treatment standards for wastewater discharges produced by natural gas extraction from underground coalbed and shale formations. The EPA stated that it will gather data, consult with stakeholders, including ongoing consultation with industry, and solicit public comment on a proposed rule for coalbed methane in 2013 and a proposed rule for shale gas in 2014. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.

The Oil Pollution Act is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.

Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws.

Air Emissions. The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For

 

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example, on April 17, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which regulations are discussed in more detail on page 104 in “—Regulation of Hydraulic Fracturing.” These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.

Climate Change. Many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas and refined petroleum products, are “greenhouse gases,” or GHGs, regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol at this time, several states or geographic regions have adopted legislation and regulations to reduce emissions of GHGs. Additionally, on April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts, et al. v. EPA, that the EPA has the authority to regulate the emission of carbon dioxide from automobiles as an “air pollutant” under the federal Clean Air Act. Thereafter, in December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Subsequently, the EPA adopted two sets of related rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule in April 2010 and it became effective January 2011, although it does not require immediate reductions in GHG emissions. The EPA adopted the stationary source rule, also known as the “Tailoring Rule,” in May 2010, and it also became effective January 2011, although it remains subject of several pending lawsuits filed by industry groups. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. More recently, in November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. In addition, the EPA has continued to adopt GHG regulations of other industries, such as the March 2012 proposed GHG rule restricting future development of coal-fired power plants. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances that correspond to their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of such allowances is expected to escalate significantly.

Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry. Currently, while we are subject to certain federal GHG monitoring and reporting requirements, our operations are not adversely impacted by existing federal, state and

 

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local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.

Regulation of Hydraulic Fracturing

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC, program. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. The EPA, however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. At the same time, the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. As part of these studies, both the EPA and the House committee have requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.

In March 2011, companion bills entitled the Fracturing Responsibility and Awareness of Chemicals (FRAC) Act, first introduced in 2009, were reintroduced in the United States Senate and House of Representatives. These bills, which are currently under consideration by Congress, would repeal the exemption for hydraulic fracturing from the SDWA, which would have the effect of allowing the EPA to promulgate regulations requiring permits and implementing potential new requirements on hydraulic fracturing under the SDWA. This development could, in turn, require state regulatory agencies in states with programs delegated under the SDWA to impose additional requirements on hydraulic fracturing operations. In addition, the bills would require persons using hydraulic fracturing, such as us, to disclose the chemical constituents, but not the proprietary formulas, of their fracturing fluids to a regulatory agency, which would make the information public via the internet. Additionally, fracturing companies would be required to disclose specific chemical contents of fluids, including proprietary chemical formulas, to state authorities or to a requesting physician or nurse if deemed necessary by the physician or nurse in connection with a medical emergency.

On April 17, 2012 the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds , or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule includes a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules will require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The federal government is currently undertaking several studies of hydraulic fracturing’s potential impacts, the results of which are expected between later in 2012 and 2014.

 

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These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities.

Several states, including Texas, and the Department of the Interior, in a May 4, 2012 proposed rule covering federal lands, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. On May 31, 2011, the Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process. It was signed into law on June 17, 2011, effective as of September 1, 2011. The Texas Railroad Commission has adopted rules and regulations implementing this legislation that will apply to all wells for which the Railroad Commission issues an initial drilling permit on or after February 1, 2012. The new law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (OSHA) for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission.

There has been increasing public controversy regarding hydraulic fracturing with regard to use of fracturing fluids, impacts on drinking water supplies, use of waters and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing, such as the FRAC Act, are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

 

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Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and oil and natural gas liquids are not currently regulated and are made at market prices.

Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following:

 

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the location of wells;

 

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the method of drilling and casing wells;

 

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the timing of construction or drilling activities, including seasonal wildlife closures;

 

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the rates of production or “allowables”;

 

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the surface use and restoration of properties upon which wells are drilled;

 

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the plugging and abandoning of wells; and

 

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notice to, and consultation with, surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of locations we can drill.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances, some state agencies and municipalities do have such requirements.

Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas

 

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that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations.

Oil Sales and Transportation. Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

 

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Operational Hazards and Insurance

The oil business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations.

In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We currently have insurance policies for property (including leased oil and gas properties), general liability, operational control of certain wells, pollution, commercial auto, umbrella liability, inland marine, workers compensation and other coverage. The limits for certain of our policies are as follows:

 

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oil and gas lease property: $21,888,656 with a deductible ranging from $5,000 to $20,000 based on property value;

 

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general liability: $1,000,000 per occurrence and $2,000,000 in the aggregate with a $25,000 deductible;

 

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pollution: $1,000,000 per occurrence and $2,000,000 in the aggregate with a $50,000 deductible;

 

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umbrella liability: $5,000,000 per occurrence with $5,000,000 aggregate coverage; and

 

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inland marine: limit varies on a per rig basis from $3,586,000 to $7,155,000 with a $250,000 deductible per accident.

As noted above, most of our insurance coverage includes deductibles that must be met prior to recovery. Additionally, our insurance is subject to exclusion and limitations, and there is no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these operational hazards could cause a significant disruption to our business. A loss not fully covered by insurance could have a material adverse affect on our financial position, results of operations and cash flows.

We reevaluate the purchase of insurance, policy terms and limits annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.

Generally, we also require our third party vendors to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider’s employees as well as contractors and subcontractors hired by the service provider.

Employees

We have approximately 54 full time employees, including three geologists, three engineers and three land professionals, all of whom are salaried administrative or supervisory employees. Of these 54 full time employees, 14 work in our office in Midland, Texas. None of our employees are represented by labor unions or covered by any collective bargaining agreements. We also hire independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist our full time employees.

 

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Facilities

Our corporate headquarters is located in Midland, Texas. We also lease additional office space in Midland and in Oklahoma City, Oklahoma. We believe that our facilities are adequate for our current operations.

Legal Proceedings

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment related disputes. In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.

 

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MANAGEMENT

Executive Officers and Directors

Set forth below is the name, age, position and a brief account of the business experience of each of our executive officers and directors as of July 1, 2012.

 

Name		Age				Position
Travis D. Stice			50			Chief Executive Officer
Teresa L. Dick			42			Chief Financial Officer, Senior Vice President
Russell Pantermuehl			52			Vice President — Reservoir Engineering
Paul Molnar			56			Vice President — Geoscience
Michael Hollis			36			Vice President — Drilling
William Franklin			57			Vice President — Land
Jeff White			56			Vice President — Operations
Randall J. Holder			58			Vice President, General Counsel
Steven E. West			52			Director
Michael P. Cross			61			Director Nominee
David L. Houston			59			Director Nominee
Mark L. Plaumann			56			Director Nominee

Travis D. Stice—Chief Executive Officer—Mr. Stice has served as our Chief Executive Officer since January 2012. Prior to his current position with us, he served as our President and Chief Operating Officer from April 2011 to January 2012. Mr. Stice has also served on the board of managers of MidMar Gas LLC, or MidMar, an entity that owns a gas gathering system and processing plant, since 2011 and as Vice President and Secretary of MidMar since April 2012. From November 2010 to April 2011, Mr. Stice served as a Production Manager of Apache Corporation, an oil and gas exploration company. Mr. Stice served as a Vice President of Laredo Petroleum Holdings, Inc, an oil and gas exploration company, from September 2008 to September 2010. From April 2006 until August 2008, Mr. Stice served as a Development Manager of ConocoPhillips/Burlington Resources Mid-Continent Business Unit, an oil and gas exploration company. Prior to that, Mr. Stice held a series of positions at Burlington Resources, an oil and gas exploration company, most recently as a General Manager, Engineering, Operations and Business Reporting of its Mid Continent Division from January 2001 until Burlington Resources’ acquisition by ConocoPhillips in March 2006. Mr. Stice has over 26 years of industry experience in production operations, reservoir engineering, production engineering and unconventional oil and gas exploration and over 18 years of management experience. Mr. Stice graduated from Texas A&M University with a Bachelor of Science degree in Petroleum Engineering. Mr. Stice is a registered engineer in the State of Texas, and is a 25-year member of the Society of Petroleum Engineers.

Teresa L. Dick—Chief Financial Officer, Senior Vice President—Ms. Dick has served as our Chief Financial Officer and Senior Vice President since November 2009. Prior to her current position with us, Ms. Dick served as our Corporate Controller from November 2007 until November 2009. From June 2006 to November 2007, Ms. Dick held a key management position as the Controller/Tax Director at Hiland Partners, a publicly-traded midstream energy master limited partnership. Ms. Dick has over 19 years of accounting experience, including over eight years of public company experience in both audit and tax areas. Ms. Dick received her Bachelor of Business Administration degree in Accounting from the University of Northern Colorado. Ms. Dick is a certified public accountant and a member of the American Institute of CPAs and the Council of Petroleum Accountants Societies.

 

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Russell Pantermuehl—Vice President—Reservoir Engineering—Mr. Pantermuehl joined us in August 2011 as Vice President—Reservoir Engineering. Prior to his current position with us, Mr. Pantermuehl served as a reservoir engineering supervisor for Concho Resources Inc., an oil and gas exploration company, from March 2010 to August 2011. Mr. Pantermuehl worked for ConocoPhillips Company as a reservoir engineering advisor from January 2005 to March 2010. Mr. Pantermuehl also worked as an independent consultant in the oil and gas industry from March 2000 to December 2004. Mr. Pantermuehl received a Bachelor of Science degree in Petroleum Engineering from Texas A&M University.

Paul Molnar—Vice President—Geoscience—Mr. Molnar joined us in August 2011 as Vice President—Geoscience. Prior to his current position with us, Mr. Molnar served as a Senior District Geologist for Samson Investment Company, an oil and gas exploration company, from March 2011 to August 2011. Mr. Molnar worked as an asset supervisor and geosciences supervisor for ConocoPhillips Company from April 2006 to February 2011. Mr. Molnar also worked as a geologic advisor for Burlington Resources, an oil and gas exploration company, from December 1996 to March 2006. Mr. Molnar has over 31 years of industry experience. Mr. Molnar received a Master of Science degree in Geology from The State University of New York at Buffalo, New York.

Michael Hollis—Vice President—Drilling—Mr. Hollis joined us in September 2011 as Vice President—Drilling. Prior to his current position with us, Mr. Hollis served in various roles, most recently as drilling manager at Chesapeake Energy Corporation, an oil and gas exploration company, from June 2006 to September 2011. Mr. Hollis worked for ConocoPhillips Company as a senior drilling engineer from January 2004 to June 2006 and as a process engineer from 2001 to 2003. Mr. Hollis also worked as a production engineer for Burlington Resources from 1998 to 2001 as well as from June 2003 to January 2004. Mr. Hollis received his Bachelor of Science degree in Chemical Engineering from Louisiana State University.

William Franklin—Vice President—Land—Mr. Franklin joined us in August 2011 as Vice President—Land. Prior to his current position with us, Mr. Franklin worked for ConocoPhillips Company in various land management roles from May 1983 until July 2011. Mr. Franklin received a Bachelor of Arts degree in History from Oklahoma City University.

Jeff White—Vice President—Operations—Mr. White joined us in September 2011 as Vice President—Operations. Prior to his current position with us, Mr. White worked for Laredo Petroleum Holdings, Inc. as a completion manager from May 2010 to September 2011. Mr. White also worked as a staff engineer for ConocoPhillips from February 2007 to May 2009. In addition, he worked in various engineering and management positions with Anadarko Petroleum from June 1988 to June 2005. Mr. White received a Bachelor of Science degree in Petroleum Engineering from Texas Tech University. He also received a Bachelor of Science degree in Fishery Biology from New Mexico State University.

Randall J. Holder—Vice President, General Counsel—Mr. Holder joined us in November 2011 as General Counsel and Vice President responsible for legal and human resources. Prior to his current position with us, Mr. Holder served as General Counsel and Vice President for Great White Energy Services LLC, an oilfield services company, from November 2008 to November 2011. Mr. Holder served as Executive Vice President and General Counsel for R.L. Hudson and Company, a supplier of molded rubber and plastic components, from February 2007 to October 2008. Mr. Holder was in private practice of law and a member of Holder Betz LLC from February 2005 to February 2007. Mr. Holder served as Vice President and Assistant General Counsel for Dollar Thrifty Automotive Group, a vehicle rental company, from January 2003 to February 2005 and, before that, as Vice President and General Counsel for Thrifty Rent-A-Car System, Inc., a vehicle rental company, from September 1996 to December 2002. He also served as Vice President and General Counsel for Pentastar Transportation Group, Inc. from November 1992 to September 1996, which was wholly-owned by Chrysler Corporation. Mr. Holder started his legal career with Tenneco Oil Company where he served as a Division Attorney providing legal services to the company’s mid-continent division for ten years. Mr. Holder received a Juris Doctorate degree from Oklahoma City University.

 

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Steven E. West—Director—Mr. West has served as a director of our company since December 2011. Mr. West served as our Chief Executive Officer from January 1, 2009 to December 31, 2011. Since January 2011, Mr. West has been a partner at Wexford, focusing on Wexford’s private equity energy investments. From August 2006 until December 2010, Mr. West served as senior portfolio advisor at Wexford. From August 2003 until August 2006, Mr. West was the chief financial officer of Sunterra Corporation, a former Wexford portfolio company. From December 1993 until July 2003, Mr. West held senior financial positions at Coast Asset Management and IndyMac Bank. Prior to that, Mr. West worked at First Nationwide Bank, Lehman Brothers and Peat Marwick Mitchell & Co., the predecessor of KPMG LLP. Mr. West holds a Bachelor of Science degree in Accounting from California State University, Chico. We believe Mr. West’s background in finance, accounting and private equity energy investments, as well as his executive management skills developed as part of his career with Wexford, its portfolio companies and other financial institutions qualify him to serve on our board of directors.

Michael P. Cross—Director Nominee—Mr. Cross has agreed to serve as a director of our company and is expected to join our board prior to the closing of this offering. Mr. Cross is President and owner of Michael P. Cross, Inc., an independent oil and natural gas producer, a position he has held since July 1994. Mr. Cross also currently serves as a director of Warren Equipment Company, a position he has held since 2002. Mr. Cross has also served as a member of the Oklahoma Energy Resources Board since February 2005 and has been a member of the Executive Committee since 2007. Mr. Cross also served as a member of the Board of Directors of the Oklahoma Independent Petroleum Association for over 15 years. Mr. Cross served on the Board of Directors for OGE Energy GP LLC from October 2007 to October 2008. Mr. Cross also served as CEO and President of Windsor Energy Resources, Inc. from December 2005 until December 2006. Mr. Cross served as President and Manager of Twister Gas Services, L.L.C., an oil and gas exploration, production and marketing company, from its inception in 1996 until June 2003 and served as President of its predecessor, Twister Transmission Company, from 1990 to 1996. Mr. Cross graduated from Oklahoma State University in 1973 with a BS in Business Administration. We believe that Mr. Cross’s strong oil and gas background and executive management experience qualify him for service on our board of directors.

David L. Houston—Director Nominee—Mr. Houston has agreed to serve as a director of our company and is expected to join our board prior to the closing of this offering. Since 1991, Mr. Houston has been the principal of Houston & Associates, a firm that offers life and disability insurance, compensation and benefits plans and estate planning. Prior to 1991, Mr. Houston was President and Chief Executive Officer of Equity Bank for Savings, F.A., an Oklahoma-based savings bank. Mr. Houston served on the board of directors and executive committee of Deaconess Hospital, Oklahoma City, Oklahoma, from January 1993 until December 2008 and is the former chair of the Oklahoma State Ethics Commission and the Oklahoma League of Savings Institutions. Mr. Houston has served as a director of Gulfport since July 1998 and is the chairman of its audit committee. He also served as a director of Bronco Drilling Company from May 2005 until December 2010 and was a member of its audit committee. Mr. Houston received a Bachelor of Science degree in business from Oklahoma State University and a graduate degree in banking from Louisiana State University. We believe that Mr. Houston’s financial background and his executive management experience qualify him for service on our board of directors.

Mark L. Plaumann—Director Nominee—Mr. Plaumann has agreed to serve as a director of our company and is expected to join our board prior to the closing of this offering. He is currently a Managing Member of Greyhawke Capital Advisors LLC, or Greyhawke, which he co-founded in 1998. Prior to founding Greyhawke, Mr. Plaumann was a Senior Vice President of Wexford. Mr. Plaumann was formerly a Managing Director of Alvarez & Marsal, Inc. and the President of American Healthcare Management, Inc. He also was Senior Manager at Ernst & Young LLP. Mr. Plaumann served as a director and audit committee chairman for ICx Technologies, Inc. until October 2010 and currently serves as a director and audit committee chairman of Republic Airways Holdings, Inc., and a director of one private company. Mr. Plaumann also has served as a director, an audit committee chairman and a member of the conflicts committee of the general partner of Rhino Resource Partners LP, a coal operating company, since October 2010. Mr. Plaumann holds an M.B.A. and a B.A. in Business from the University of Central Florida. We believe that Mr. Plaumann’s service on the boards of other public companies and his executive management experience, including previous experience as chairman of audit committees, qualifies him for service on our board of directors.

 

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Our Board of Directors and Committees

Upon completion of this offering, our board of directors will consist of seven directors, at least three of whom will satisfy the independence requirements of current SEC rules and The NASDAQ Global Market listing standards. Our certificate of incorporation provides that the terms of office of the directors are one year from the time of their election until the next annual meeting of stockholders or until their successors are duly elected and qualified.

Our certificate of incorporation provides that the authorized number of directors will generally be not less than five nor more than thirteen, and the exact number of directors will be fixed from time to time exclusively by the board of directors pursuant to a resolution adopted by a majority of the whole board. In addition, our certificate of incorporation and our bylaws provide that, in general, vacancies on the board may be filled by a majority of directors in office, although less than a quorum.

Our board of directors will establish an audit committee in connection with this offering whose functions include the following:

 

•

assist the board of directors in its oversight responsibilities regarding the integrity of our financial statements, our compliance with legal and regulatory requirements, the independent accountant’s qualifications and independence and our accounting and financial reporting processes of and the audits of our financial statements;

 

•

prepare the report required by the SEC for inclusion in our annual proxy or information statement;

 

•

appoint, retain, compensate, evaluate and terminate our independent accountants;

 

•

approve audit and non-audit services to be performed by the independent accountants;

 

•

review and approve related party transactions; and

 

•

perform such other functions as the board of directors may from time to time assign to the audit committee.

The specific functions and responsibilities of the audit committee will be set forth in the audit committee charter. Upon completion of this offering, our audit committee will include at least one director who satisfies the independence requirements of current SEC rules and The NASDAQ Global Market listing standards. Within one year after completion of the offering, we expect that our audit committee will be composed of three members that will satisfy the independence requirements of current SEC rules and The NASDAQ Global Market listing standards. We also expect that one of the members of the audit committee will qualify as an audit committee financial expert as defined under these rules and listing standards, and the other members of our audit committee will satisfy the financial literacy standards for audit committee members under these rules and listing standards.

Pursuant to our bylaws, our board of directors may, from time to time, establish other committees to facilitate the management of our business and operations. Because we are considered to be controlled by Wexford under The NASDAQ Global Market rules, we are eligible for exemptions from provisions of these rules requiring a majority of independent directors, nominating and corporate governance and compensation committees composed entirely of independent directors and written charters addressing specified matters. We do not intend to rely upon any of these exemptions, except for the exemption from the requirement to establish an independent nominating committee. In the event that we cease to be a controlled company within the meaning of these rules, we will be required to comply with these provisions after the specified transition periods.

Although we will be eligible for an exemption from the compensation committee requirements under The NASDAQ Global Market rules, we intend to establish a compensation committee composed of at least two independent directors in connection with this offering. See “—Executive Compensation—Compensation Discussion and Analysis—Compensation Policy” on page 115 of this prospectus.

 

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In connection with the Gulfport transaction, Gulfport will have the right to designate one individual as a nominee to serve on our board of directors for so long as Gulfport beneficially owns more than 10% of our outstanding common stock. Such nominee, if elected to our board, will also serve on each committee of the board so long as he or she satisfies the independence and other requirements for service on the applicable committee. So long as Gulfport has the right to designate a nominee to our board and there is no Gulfport nominee actually serving as a director, Gulfport shall have the right to appoint one individual as an advisor to the board who shall be entitled to attend board and committee meetings.

Director Compensation

To date, none of our directors has received compensation for services rendered as a board member. Members of our board of directors who are also officers or employees of our company will not receive compensation for their services as directors. It is anticipated that after the completion of this offering, we will pay our non-employee directors a monthly retainer of $             and a per meeting attendance fee of $             and reimburse all ordinary and necessary expenses incurred in the conduct of our business.

In connection with this offering, we intend to implement an equity incentive plan. Under the plan, certain non-employee directors will be granted              restricted stock units, which will vest in three equal annual installments beginning on the date of grant.

Compensation Committee Interlocks and Insider Participation

We do not currently have a compensation committee. None of our executive officers serves, or has served during the past year, as a member of the board of directors or compensation committee of any other company that has one or more executive officers serving as a member of our board of directors or compensation committee.

Executive Compensation

Compensation Discussion and Analysis

Compensation Practices

Historically, our equity sponsor, Wexford, determined our overall compensation philosophy and set the compensation of our named executive officers, after taking into consideration recommendations of our then serving chief executive officer. In the case of our named executives with employment agreements, the compensation of such individuals is determined in accordance with their respective employment agreements.

Prior to the completion of this offering, our board of directors intends to establish a compensation committee comprised of at least two independent, non-employee directors and adopt a written charter for the compensation committee setting forth the compensation committee’s purpose and responsibilities. The principal responsibilities of the compensation committee will be to review and approve corporate goals and objectives relevant to the compensation of our executive officers, evaluate their performance in light of these goals and, subject to the terms of the employment agreements with our named executive officers, determine and approve our executive officers’ compensation based on such evaluation and establish policies, including with respect to the following:

 

•

the determination of the elements of executive compensation and allocation among different types of executive compensation;

 

•

the determination as to when awards are granted, including awards of equity-based compensation such as restricted stock units, restricted stock and/or options;

 

•

stock ownership guidelines and any policies regarding hedging the economic risk of such ownership; and

 

•

the review of the risks and rewards associated with our compensation policies and programs.

 

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The compensation committee will seek to provide a total compensation package designed to drive performance and reward contributions in support of our business strategies and to attract, motivate and retain high quality talent with the skills and competencies required by us. It is possible that the compensation committee will examine the compensation practices of our peer companies and may also review compensation data from the oil and natural gas industry generally to the extent the competition for executive talent is broader than a group of selected peer companies, but any decisions regarding possible benchmarking will be made following the completion of this offering. In addition, the compensation committee may review and, in certain cases, participate in, various relevant compensation surveys and consult with compensation consultants with respect to determining any changes in the compensation for our named executive officers, subject to the terms of their respective employment agreements. We expect that our Chief Executive Officer will provide periodic recommendations to the compensation committee regarding such determinations. We expect that the compensation committee will design our compensation policies and programs to encourage and reward prudent business judgment and appropriate risk taking over the long term.

Compensation Policy

Our general compensation policy is guided by several key principles:

 

•

designing competitive total compensation programs to enhance our ability to attract and retain knowledgeable and experienced senior management level employees;

 

•

motivating employees to deliver outstanding financial performance and meet or exceed general and specific business, operational and individual objectives;

 

•

setting compensation and incentive levels relevant to the market in which the employee provides service; and

 

•

providing a meaningful portion of the total compensation to our named executive officers in equity, thus assuring an alignment of interests between our senior management level employees and our stockholders.

Upon completion of this offering, our compensation committee will determine, subject to the terms of the employment agreements with our named executive officers, the mix of compensation, both among short-term and long-term compensation and cash and non-cash compensation, to establish structures that it believes are appropriate for each of our named executive officers. In making compensation decisions with respect to each element of compensation, the compensation committee is expected to consider numerous factors, including:

 

•

the individual’s particular background and circumstances, including training and prior relevant work experience;

 

•

the individual’s role with us and the compensation paid to similar persons at comparable companies;

 

•

the demand for individuals with the individual’s specific expertise and experience at the time of hire;

 

•

achievement of individual and company performance goals and other expectations relating to the position;

 

•

comparison to other executives within our company having similar levels of expertise and experience and the uniqueness of the individual’s industry skills; and

 

•

aligning the compensation of our executives with the performance of our company on both a short-term and long-term basis.

Although we expect the compensation committee to follow these policies, it is possible that the compensation committee could develop a compensation philosophy different than that discussed here.

Historic Elements of Compensation

Historically the principal elements of compensation for our named executive officers have been:

 

•

base salary;

 

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•

bonus awards;

 

•

equity awards contained in their employment agreements; and

 

•

health insurance, life and disability insurance and 401(k) plan benefits available to all of our other employees.

We believe that our company does not utilize compensation policies and programs that create risks that are reasonably likely to have a material adverse impact on our company. Historically, certain management, administrative and treasury functions were provided to us by Everest, an entity controlled by Wexford, our equity sponsor. For purposes of presenting the consolidated financial statements, included elsewhere in this prospectus, allocations were made to determine the cost of general and administrative activities performed attributable to us. The allocations were made based upon underlying salary costs of employees performing Company related functions, payroll, revenue or headcount relative to other companies managed by Everest, or specifically identified invoices processed, depending on the nature of the cost. Currently, we employ all our named executive officers directly.

Components of Compensation Following the Completion of the Offering

We believe a material amount of executive compensation should be tied to our performance, and a significant portion of the total prospective compensation of each named executive officer should be tied to measurable financial and operational objectives. These objectives may include absolute performance or performance relative to a peer group. During periods when performance meets or exceeds established objectives, our named executive officers should be paid at or above targeted levels, respectively. When our performance does not meet key objectives, incentive award payments, if any, should be less than such targeted levels.

Following the completion of this offering, we anticipate that the compensation committee will seek to balance awards based on short-term annual results with awards intended to compensate our executives based on our long-term viability and success. Consequently, in addition to annual bonuses, in the future we may provide long-term incentives to our executives in the form of equity based awards to continue to align the interests of our named executive officers with those of our equity holders. These awards would be in addition to the equity awards contained in their employment agreements. In connection with this offering, our board of directors will adopt a long-term incentive plan, which we believe will further incentivize the executive officers to perform their duties in a way that will enhance our long-term success.

As discussed above, following the completion of this offering and subject to the terms of the employment agreements with our named executive officers, our compensation committee will determine the mix of compensation, both among short-term and long-term compensation and cash and non-cash compensation, to establish structures that it believes are appropriate for each of our named executive officers. We believe that the mix of base salary, performance-based incentive compensation, bonus awards, existing equity awards under their employment agreements, awards under the long-term incentive plan and the other benefits that are or will be available to our named executive officers will accomplish our overall compensation objectives. We believe that these elements of compensation create competitive compensation opportunities to align and drive employee performance in support of our business strategies and to attract, motivate and retain high quality talent with the skills and competencies required by us.

Base Salary

Our named executive officers’ base salaries are determined in accordance with their respective employment agreements. We have not retained compensation consultants to advise us on compensation matters. Subject to applicable employment agreements, the compensation committee may increase base salaries to align such salaries with market levels for comparable positions in other companies in our industry if we identify significant market changes. Additionally, the compensation committee may adjust base salaries as warranted throughout the

 

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year for promotions or other changes in the scope or breadth of an executive’s role or responsibilities. The compensation committee may also evaluate our named executive officers’ salaries together with other components of their compensation to ensure that the executive’s total compensation is in line with our overall compensation philosophy. Upon completion of this offering, our named executive officers will, initially, continue to be compensated at their current annual rates, as specified in the Summary Compensation Table below.

Discretionary Annual Performance Bonus

In accordance with our named executive officers’ employment agreements, the board of directors will have the authority to award annual cash bonuses to our named executive officers that have achieved their respective performance goals determined by the board of directors for the applicable year. Pursuant to the terms of their respective employment agreements, the amount of the annual cash bonus that each of our named executive officers (with the exception of Mr. Stice) is eligible to receive is equal to 50% of such officer’s annual base salary. Mr. Stice is entitled to receive an annual bonus of at least $200,000 and may receive an annual bonus of up to $400,000 upon the achievement of performance goals to be determined by the board of directors. We have not established any specific performance goals for our named executive officers. For 2011, the discretionary annual bonuses were paid to our named executive officers based on their respective performances and contribution to our company in 2011 and other factors generally, including our company’s performance in 2011, the value these executives bring to our company, market trends, economic climate, experience, leadership and employee retention. None of these factors was given materially greater weight than the other factors in determining the officers’ bonuses. The discretionary annual cash bonuses received by our named executive officers for 2011 are set forth in the table under the caption “Summary of Compensation of Our Named Executive Officers” included beginning on page 118 of this prospectus.

Long Term Equity Incentive Compensation

We will seek to promote an ownership culture among our executive officers in an effort to enhance our long-term performance. We believe the use of stock and stock-based awards offers the best approach to achieving our compensation goals. Each of our named executive officers has been awarded an option to purchase shares of our common stock in accordance with the terms of his or her employment agreement. See “—Employment Agreements” beginning on page 120 of this prospectus. To date, we have not adopted stock ownership guidelines for our executives. In connection with this offering, we intend to implement an equity incentive plan. The purpose of this plan will be to continue to enable us, and our affiliates, to attract and retain the services of the types of employees, consultants and directors who will contribute to our long term success and to provide incentives that will be linked directly to increases in share value that will inure to the benefit of our stockholders. The plan will provide a means by which eligible recipients of awards may be given an opportunity to benefit from increases in value of our common stock through the granting of equity awards. The terms of our equity incentive plan are described in more detail following the Summary Compensation Table.

Other Compensation and Perquisites

Consistent with our compensation philosophy, we anticipate that our compensation committee will continue to provide benefits to our executives that are substantially the same as those currently being offered to our other employees, including health insurance, life and disability insurance and a 401(k) plan. The benefits and perquisites that may be available to our executive officers in addition to those available to our other employees include a car allowance and club dues.

Tax Implications of Executive Compensation Policy

Under Section 162(m) of the Internal Revenue Code, a public company generally may not deduct compensation in excess of $1.0 million per year per person paid to its principal executive officer, principal financial officer and the three other most highly compensated executive officers whose compensation is disclosed in its proxy statement as a result of their total compensation, subject to certain exceptions. Qualifying performance-based compensation will not be subject to the deduction limit if certain requirements are met.

 

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Although our long-term and incentive compensation plans and agreements have provisions that are intended to satisfy the performance-based compensation exception to the Section 162(m) deduction limit, regulations under Section 162(m) also provide a transition reliance period in the case of a corporation that is not publicly held and becomes publicly held in connection with an initial public offering. During the reliance period, the deduction limit of Section 162(m) does not apply to any compensation paid pursuant to a plan or agreement that existed during the period that the corporation was not publicly held, provided the prospectus accompanying the initial public offering discloses information concerning the plans or agreements in accordance with applicable securities laws. The reliance period ends on the earliest of (1) the expiration of the plan or agreement; (2) the material modification of the plan or agreement; (3) the issuance of all employer stock or compensation reserved under the plan; or (4) the first meeting of stockholders at which directors are elected that occurs after the close of the third calendar year following the calendar year in which the initial public offering occurs.

We anticipate that our compensation committee will structure our long-term and incentive compensation programs to preserve the tax deductibility of compensation paid to our executive officers. However, our compensation committee will have the authority to award performance-based compensation that is not deductible and we cannot guarantee that it will only award deductible compensation to our executive officers. In addition, notwithstanding our compensation committee’s efforts, ambiguities and uncertainties regarding the application and interpretation of Section 162(m) make it impossible to provide assurance that any performance based compensation will, in fact, satisfy the requirements for deductibility under Section 162(m). Time vested restricted stock awards will not be treated as performance based compensation and, as a result, the deductibility of such awards could be limited. Also, base salaries and other non-performance based compensation as defined in Section 162(m) in excess of $1.0 million paid to these executive officers in any year would not qualify for deductibility under Section 162(m).

Summary of Compensation for Our Named Executive Officers

The following table shows the compensation of all individuals serving as our principal executive officer and principal financial officer during 2011 and of our next most highly compensated executive officer serving as of December 31, 2011, whose total compensation exceeded $100,000 for the fiscal year ended December 31, 2011.

 

		Year				Salary				Bonus(1)				Option Awards(2)				All Other Compensation(3)				Total
Steven E. West(4)			2011			$	—			$	—			$	—			$	—			$	—
Former Chief Executive Officer
Travis D. Stice(5)			2011			$	115,879			$	225,000			$	272,410			$	5,874			$	619,163
Current Chief Executive Officer; Former President and Chief Operating Officer
Teresa L. Dick			2011			$	98,517			$	112,631			$	31,608			$	3,558			$	246,314
Chief Financial Officer, Senior Vice President
Jeff White			2011			$	55,846			$	131,820			$	36,041			$	309			$	224,016
Vice President — Operations

 

(1)	Mr. Stice received a $225,000 annual incentive bonus, Ms. Dick received a $46,820 retention bonus and a $65,811 annual incentive bonus and Mr. White received an $85,000 signing bonus and a $27,500 annual incentive bonus.

(2)

Reflects the amount recognized for financial reporting purposes in 2011 under FASB ASC Topic 718 for the option award granted to each named executive officer under his or her employment agreement with us. The amount was calculated using certain assumptions set forth in Note 8 to our historical financial statements included in this prospectus. In connection with the closing of this offering, these options will be cancelled and replaced with the right to receive cash payments of $1,000,000, $300,000 and $350,000 for Mr. Stice, Ms. Dick and Mr. White, respectively, which, in the case of Mr. Stice, will be payable two-thirds at the time of the

 

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offering and one-third on the first anniversary of the offering, restricted stock units in an amount equal to $1,000,000, $300,000 and $600,000 divided by the initial price per share of our common stock to the public in this offering, or the IPO price per share, for Mr. Stice, Ms. Dick and Mr. White, respectively, and options to purchase 300,000, 50,000 and 100,000 shares of our common stock at the IPO price per share for Mr. Stice, Ms. Dick and Mr. White, respectively.

(3)

Amounts for Mr. Stice include our 401(k) plan contributions of $1,832, car allowance of $3,665 and life insurance premium payments of $377. Amounts for Ms. Dick include our 401(k) plan contributions of $2,735 and life insurance premium payments of $823. Amounts for Mr. White include life insurance premium payments of $309.

(4)	Mr. West resigned as our chief executive officer in December 2011. Mr. West did not receive any compensation from us in 2011.

(5)	Mr. Stice became our President and Chief Operating Officer in April 2011. On January 1, 2012, Mr. Stice resigned as President and Chief Operating Officer and became our Chief Executive Officer. Mr. Stice’s annual base salary remains at $300,000.

2011 Grants of Plan-Based Awards

The following table presents information regarding each grant of an award made to our named executive officers in 2011 under any Company plan.

 

Name		Grant Date				All Other Option Awards: Number of Securities Underlying Options (#)(1)				Exercise or Base Price of Option Awards ($/Sh)(2)				Grant Date Fair Value of Stock and Option Awards ($)(3)
Steve E. West			—				—				—				—
Travis D. Stice			4/18/2011				1.00	%		$	3,600,000				1,452,851
Teresa L. Dick			9/1/2011				0.25	%		$	900,000				379,299
Jeff White			9/30/2011				0.50	%		$	2,500,000				576,657

 

(1)

All option awards shown represent an option to acquire a membership interest percentage in Windsor Permian. In connection with the closing of this offering, these options will be cancelled and replaced with the right to receive cash payments of $1,000,000, $300,000 and $350,000 for Mr. Stice, Ms. Dick and Mr. White, respectively, which, in the case of Mr. Stice, will be payable two-thirds at the time of the offering and one-third on the first anniversary of the offering, restricted stock units in an amount equal to $1,000,000, $300,000 and $600,000 divided by the IPO price per share for Mr. Stice, Ms. Dick and Mr. White, respectively, and options to purchase 300,000, 50,000 and 100,000 shares of our common stock at the IPO price per share for Mr. Stice, Ms. Dick and Mr. White, respectively.

(2)	The exercise price shown represents the aggregate exercise price for the option to acquire the entire membership interest percentage in Windsor Permian.

(3)

Grant date fair value of the option award granted to each named executive officer in 2011 is computed in accordance with FASB ASC Topic 718 and reflects the total amount of the award to be spread over the applicable vesting period. Each named executive officer’s option award vests as described in such named executive officer’s employment agreement under “—Employment Agreements” below beginning on page 120.

 

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2011 Outstanding Equity Awards at Year-End Table

The following table presents, for each of the named executive officers, information regarding outstanding equity awards held as of December 31, 2011.

 

		Option Awards
Name		Number of Securities Underlying Unexercised Options (#) Exercisable				Number of Securities Underlying Unexercised Options (#) Unexercisable(1)				Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)				Option Exercise Price ($)(2)				Option Expiration Date
Steven E. West			—				—				—				—				—
Travis D. Stice			—				1.00	%			—			$	3,600,000				4/18/2016
Teresa L. Dick			—				0.25	%			—			$	900,000				9/1/2016
Jeff White			—				0.50	%			—			$	2,500,000				9/30/2016

 

(1)

All option awards shown represent an option to acquire a membership interest percentage in Windsor Permian. In connection with the closing of this offering, these options will be replaced with the right to receive cash payments of $1,000,000, $300,000 and $350,000 for Mr. Stice, Ms. Dick and Mr. White, respectively, which, in the case of Mr. Stice, will be payable two-thirds at the time of the offering and one-third on the first anniversary of the offering, restricted stock units in an amount equal to $1,000,000, $300,000 and $600,000 divided by the IPO price per share for Mr. Stice, Ms. Dick and Mr. White, respectively, and options to purchase 300,000, $50,000 and $100,000 shares of our common stock at the IPO price per share for Mr. Stice, Ms. Dick and Mr. White, respectively.

(2)	The exercise price shown represents the aggregate exercise price for the option to acquire the entire membership interest percentage in Windsor Permian.

Employment Agreements

The following summarizes the material terms of the employment agreements we have with our named executive officers.

Travis D. Stice. Effective April 2011, we entered into an employment agreement with Mr. Stice, our Chief Executive Officer. The employment agreement has a three-year term and provides for an annual base salary of $300,000. Mr. Stice is also entitled to receive an annual bonus of at least $200,000, which could be increased up to $400,000 depending upon his achievement of certain performance goals as determined by our board of directors. Mr. Stice is entitled to participate in such life and medical insurance plans and other similar plans that we establish from time to time for our executive employees, and is paid a $900 monthly vehicle allowance. Pursuant to the terms of his employment agreement, Mr. Stice has an option to acquire a 1.0% membership interest in our subsidiary Windsor Permian LLC for an aggregate exercise price of $3.6 million, subject to adjustment in the event of certain asset sales. Such option vests in four equal annual installments commencing on the first anniversary of the effective date of Mr. Stice’s employment agreement and will be exercisable for five years from the effective date of his employment agreement or until his earlier termination. In connection with this offering, this option will be cancelled and replaced with the right to receive $1,000,000 in cash, of which two-thirds will be payable at the time of the offering and one-third will be payable on the first anniversary if Mr. Stice is still employed by us or if he terminated by us prior to that date without “cause” as defined below, restricted stock units in an amount equal to $1,000,000 divided by the IPO price per share and options to purchase 300,000 shares of our common stock at the IPO price per share. The vesting schedule and exercise rights for these options and the restricted stock units will remain the same as the original option. Mr. Stice has agreed to certain restrictive covenants in his employment agreement, including, without limitation, his agreement not to compete with us, not to interfere with any of our employees, suppliers or regulators and not to solicit our customers or employees, in each case during Mr. Stice’s affiliation with us and for a period of six months

 

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thereafter. Mr. Stice’s continued employment with us is “at-will,” meaning that either we or Mr. Stice may terminate the employment relationship at any time and for any reason, with or without notice. However, if we terminate Mr. Stice’s employment without “cause,” we will be obligated to continue paying Mr. Stice’s annual base salary until the expiration of the term of his employment agreement and pay a prorated portion of Mr. Stice’s minimum annual bonus for the period prior to termination, subject to Mr. Stice’s compliance with the restrictive covenants discussed above and his execution of a full general release in our favor. If Mr. Stice’s employment is terminated due to death or disability, our sole obligation, subject to Mr. Stice’s compliance with the restrictive covenants discussed above, will be to pay any earned but unpaid base salary and a prorated portion of Mr. Stice’s minimum annual bonus for the period prior to termination. In the event Mr. Stice’s employment is terminated for “cause,” our obligations will terminate with respect to the payment of any base salary or bonuses and the option described above effective as of the termination date. For purposes of Mr. Stice’s employment agreement, “cause” is generally defined as Mr. Stice’s (a) willful and knowing refusal or failure to perform his duties in any material respect, (b) willful misconduct or gross negligence in performing his duties, (c) material breach of his employment agreement or any other agreement with us, (d) conviction of, or a plea of guilty or nolo contendere to, a criminal act that constitutes a felony or involves fraud, dishonesty or moral turpitude, (e) indictment for a felony involving embezzlement, theft or fraud, (f) filing of a voluntary, or consent to an involuntary, bankruptcy petition or (g) failure to comply with directives of our board of directors. In addition, in the event that more than 50% of the combined voting power of our then outstanding stock is controlled by one or more parties that is not Wexford or an affiliate of Wexford, the options described above will vest immediately. The benefits Mr. Stice is entitled to receive upon certain terminations, resignations and changes of control are summarized below in “Potential Payments Upon Termination, Resignation or Change of Control” on page 125 of this prospectus.

Teresa L. Dick. Effective September 2011, we entered into an employment agreement with Ms. Dick, our Senior Vice President and Chief Financial Officer. The employment agreement has a one-year term and provides for an annual base salary of $250,000. Subject to Ms. Dick’s achievement of certain performance goals as determined by our board of directors for each fiscal year, Ms. Dick is entitled to an annual bonus of 50% of her annual base salary. Ms. Dick is also entitled to participate in any life and medical insurance plans and other similar plans that we establish from time to time for our executive employees. Pursuant to the terms of her employment agreement, Ms. Dick has an option to acquire a 0.25% membership interest in our subsidiary Windsor Permian LLC for an aggregate exercise price of $900,000, subject to adjustment in the event of certain asset sales. Such option vests in four equal annual installments commencing on the first anniversary of the effective date of Ms. Dick’s employment agreement and will be exercisable for five years from the effective date of such employment agreement or until her earlier termination (except for termination upon death, disability or by us without cause). In connection with the closing of this offering, this option will be cancelled and replaced with the right to receive $300,000 in cash, restricted stock units in an amount equal to $300,000 divided by the IPO price per share and options to purchase 50,000 shares of our common stock at the IPO price per share. The vesting schedule and exercise rights for these options and the restricted stock units will remain the same as the original option. Ms. Dick has agreed to certain restrictive covenants in her employment agreement, including, without limitation, her agreement not to compete with us, not to interfere with any of our employees, suppliers or regulators and not to solicit our customers or employees, in each case during Ms. Dick’s affiliation with us and for a period of six months thereafter. Ms. Dick’s continued employment with us is “at-will,” meaning that either we or Ms. Dick may terminate the employment relationship at any time and for any reason, with or without notice. However, if (i) we terminate Ms. Dick’s employment without “cause,” (ii) Ms. Dick resigns for good reason, meaning such resignation follows a material uncured breach by us of the employment agreement or a material diminution in Ms. Dick’s position, duties or authority, or (iii) Ms. Dick’s employment is terminated due to death or disability, then we will be obligated to continue paying Ms. Dick’s base annual salary until the expiration of the term of her employment agreement and, in the case of termination without cause or upon death or disability, to honor our obligations with respect to the option described above; provided, in each case, that Ms. Dick continues to comply with the restrictive covenants described above and (except in the case of clause (iii) above) executes a full general release in our favor. In the event Ms. Dick’s employment is terminated for “cause,” our obligations will terminate with respect to the payment of any base salary or bonuses and the option

 

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described above effective as of the termination date. For purposes of Ms. Dick’s employment agreement, “cause” is generally defined as Ms. Dick’s (a) willful and knowing refusal or failure to perform her duties in any material respect, (b) willful misconduct or gross negligence in performing her duties, (c) material breach of her employment agreement or any other agreement with us, (d) conviction of, or a plea of guilty or nolo contendere to, a criminal act that constitutes a felony or involves fraud, dishonesty or moral turpitude, (e) indictment for a felony involving embezzlement, theft or fraud, (f) filing of a voluntary, or consent to an involuntary, bankruptcy petition, (g) dishonesty in connection with her responsibilities as an employee or (h) failure to comply with directives of our board of directors. In addition, (x) in the event that more than 50% of the combined voting power of our then outstanding stock is controlled by one or more parties that is not Wexford, an affiliate of Wexford or an underwriter temporarily holding securities pursuant to an offering of securities and there is a material change in Ms. Dick’s position, duties or authority or (y) upon termination without cause or due to death or disability, the options described above will vest immediately. The benefits Ms. Dick is entitled to receive upon certain terminations, resignations and changes of control are summarized below in “Potential Payments Upon Termination, Resignation or Change of Control” on page 125 of this prospectus.

Jeff White. Effective September 2011, we entered into an employment agreement with Mr. White, our Vice President—Operations. The employment agreement has a three-year term and provides for an annual base salary of $220,000. Subject to Mr. White’s achievement of certain performance goals as determined by our board of directors for each fiscal year, Mr. White is entitled to an annual bonus of 50% of his annual base salary. Upon entering into the employment agreement, Mr. White received an $85,000 signing bonus and, if this offering is completed within one year of Mr. White’s hiring, he will be entitled to receive shares of our common stock with a value equal to $170,000. If we do not complete this offering within one year of his hiring, Mr. White will receive a $170,000 cash bonus. Mr. White is also entitled to participate in any life and medical insurance plans and other similar plans that we establish from time to time for our executive employees. Pursuant to the terms of his employment agreement, Mr. White has an option to acquire a 0.5% membership interest in our subsidiary Windsor Permian LLC for an aggregate exercise price of $2.5 million, subject to adjustment in the event of certain asset sales. Such option vests in four equal annual installments commencing on the first anniversary of the effective date of Mr. White’s employment agreement and will be exercisable for five years from the effective date of his employment agreement or until his earlier termination (except for termination upon death, disability or by us without cause). In connection with the closing of this offering, this option will be cancelled and replaced with the right to receive $350,000 in cash, restricted stock units in an amount equal to $600,000 divided by the IPO price per share and options to purchase 100,000 shares of our common stock at the IPO price per share. The vesting schedule and exercise rights for these options and the restricted stock units will remain the same as the original option. Mr. White has agreed to certain restrictive covenants in his employment agreement, including, without limitation, his agreement not to compete with us, not to interfere with any of our employees, suppliers or regulators and not to solicit our customers or employees, in each case during Mr. White’s affiliation with us and for a period of six months thereafter. Mr. White’s continued employment with us is “at-will,” meaning that either we or Mr. White may terminate the employment relationship at any time and for any reason, with or without notice. However, if (i) we terminate Mr. White’s employment without “cause,” (ii) Mr. White resigns for good reason, meaning such resignation follows a material uncured breach by us of the employment agreement or a material diminution in Mr. White’s position, duties or authority, or (iii) Mr. White’s employment is terminated due to death or disability, then we will be obligated to continue paying Mr. White’s base annual salary until the expiration of the term of his employment agreement and, in the case of termination without cause or upon death or disability, to honor our obligations with respect to the option described above; provided, in each case, that Mr. White continues to comply with the restrictive covenants described above and (except in the case of clause (iii) above) executes a full general release in our favor. In the event Mr. White’s employment is terminated for “cause,” our obligations will terminate with respect to the payment of any base salary or bonuses and the option described above effective as of the termination date. For purposes of Mr. White’s employment agreement, “cause” is generally defined as Mr. White’s (a) willful and knowing refusal or failure to perform his duties in any material respect, (b) willful misconduct or gross negligence in performing his duties, (c) material breach of his employment agreement or any other agreement with us, (d) conviction of, or a plea of guilty or nolo contendere to, a criminal act that constitutes a felony or involves fraud, dishonesty or moral turpitude, (e) indictment for a

 

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felony involving embezzlement, theft or fraud, (f) filing of a voluntary, or consent to an involuntary, bankruptcy petition, (g) dishonesty in connection with his responsibilities as an employee or (h) failure to comply with directives of our board of directors. In addition, (x) in the event that more than 50% of the combined voting power of our then outstanding stock is controlled by one or more parties that is not Wexford, an affiliate of Wexford or an underwriter temporarily holding securities pursuant to an offering of securities and there is either a material change in Mr. White’s position, duties or authority or Mr. White is required to move outside a 50 mile radius of Midland, Texas or (y) upon termination without cause or due to death or disability, the options described above will vest immediately. The benefits Mr. White is entitled to receive upon certain terminations, resignations and changes of control are summarized below in “Potential Payments Upon Termination, Resignation or Change of Control” on page 125 of this prospectus.

Equity Incentive Plan

Prior to the completion of this offering, we did not have any stock option or other equity incentive plan except for the equity awards granted in the employment agreements with our named executive officers and, except for such awards, there are no stock options, restricted stock units or other equity awards outstanding for any of our named executive officers. Prior to this offering, we intend to implement our equity incentive plan.

Eligible award recipients are employees, consultants and directors of our company and its affiliates. Incentive stock options may be granted only to our employees. Awards other than incentive stock options may be granted to employees, consultants and directors. The shares that may be issued pursuant to awards consist of our authorized but unissued common stock, and the maximum aggregate amount of such common stock which may be issued upon exercise of all awards under the plan, including incentive stock options, may not exceed              shares, subject to adjustment to reflect certain corporate transactions or changes in our capital structure. To the extent that an award is intended to qualify as performance-based compensation under Section 162(m) of the Internal Revenue Code, then the maximum number of shares of common stock issuable in the form of each type of award under our equity incentive plan to any one participant during a calendar year shall not exceed              shares. Additionally, no participant shall receive in excess of the aggregate amount of              shares pursuant to all awards issued under our equity incentive plan during any calendar year.

We anticipate granting options and restricted stock units to employees and certain non-employee directors under the plan upon completion of this offering in the amount to be determined by the compensation committee.

Share Reserve. The aggregate number of shares of common stock initially authorized for issuance under the plan is              shares. However, (i) shares covered by an award that expires or otherwise terminates without having been exercised in full and (ii) shares that are forfeited to, or repurchased by, us pursuant to a forfeiture or repurchase provision under the plan may return to the plan and be available for issuance in connection with a future award.

Administration. Our board of directors (or our compensation committee or any other committee of the board of directors as may be appointed by our board of directors from time to time) administers the plan. Among other responsibilities, the plan administrator selects participants from among the eligible individuals, determines the number of shares that will be subject to each award and determines the terms and conditions of each award, including methods of payment, vesting schedules and limitations and restrictions on awards. The plan administrator may amend, suspend, or terminate the plan at any time. Amendments will not be effective without stockholder approval if stockholder approval is required by applicable law or stock exchange requirements. Unless terminated earlier, our equity incentive plan will terminate in                     , 2022.

Stock Options. Incentive and nonstatutory stock options are granted pursuant to incentive and nonstatutory stock option agreements. Employees, directors and consultants may be granted nonstatutory stock options, but only employees may be granted incentive stock options. The plan administrator determines the exercise price of a stock option, provided that the exercise price of a stock option generally cannot be less than 100% (and in the

 

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case of an incentive stock option granted to a more than 10% stockholder, 110%) of the fair market value of our common stock on the date of grant, except when assuming or substituting options in limited situations such as an acquisition. Generally, options granted under the plan vest ratably over a five-year period and have a term of ten years (five years in the case of an incentive stock option granted to a more than 10% stockholder), unless specified otherwise by the plan administrator in the option agreement.

Acceptable consideration for the purchase of common stock issued upon the exercise of a stock option will be determined by the plan administrator and may include (i) cash or check, (ii) a broker-assisted cashless exercise, (iii) the tender of common stock previously owned by the optionee, (iv) stock withholding and (v) other legal consideration approved by the plan administrator, such as exercise with a full recourse promissory note (not applicable for directors and executive officers).

Unless the plan administrator provides otherwise (solely with respect to intervivos transfers to certain family members and estate planning vehicles), nonstatutory options generally are not transferable except by will or the laws of descent and distribution. An optionee may designate a beneficiary, however, who may exercise the option following the optionee’s death. Incentive stock options are not transferable except by will or the laws of descent and distribution.

Restricted Awards. Restricted awards are awards of either actual shares of common stock (e.g., restricted stock awards), or of hypothetical share units (e.g., restricted stock units) having a value equal to the fair market value of an identical number of shares of common stock, that will be settled in the form of shares of common stock upon vesting or other specified payment date, and which may provide that such restricted awards may not be sold, transferred, or otherwise disposed of for such period as the plan administrator determines. The purchase price and vesting schedule, if applicable, of restricted awards are determined by the plan administrator. A restricted stock unit is similar to a restricted stock award except that participants holding restricted stock units do not have any stockholder rights until the stock unit is settled with shares. Stock units represent an unfunded and unsecured obligation for us and a holder of a stock unit has no rights other than those of a general creditor.

Performance Awards. Performance awards entitle the recipient to vest in or acquire shares of common stock, or hypothetical share units having a value equal to the fair market value of an identical number of shares of common stock that will be settled in the form of shares of common stock upon the attainment of specified performance goals. Performance awards may be granted independent of or in connection with the granting of any other award under the plan. Performance goals will be established by the plan administrator based on one or more business criteria that apply to the plan participant, a business unit, or our company and our affiliates. Performance goals will be objective and will be intended to meet the requirements of Section 162(m) of the Code. Performance goals must be determined prior to the time 25% of the service period has elapsed but not later than 90 days after the beginning of the service period. No payout will be made on a performance award granted to a named executive officer unless all applicable performance goals and service requirements are achieved. Performance awards may not be sold, assigned, transferred, pledged or otherwise encumbered and terminate upon the termination of the participant’s service to us or our affiliates.

Stock Appreciation Rights. Stock appreciation rights may be granted independent of or in tandem with the granting of any option under the plan. Stock appreciation rights are granted pursuant to stock appreciation rights agreements. The exercise price of a stock appreciation right granted independent of an option is determined by the plan administrator, but as a general rule will be no less than 100% of the fair market value of our common stock on the date of grant. The exercise price of a stock appreciation right granted in tandem with an option is the same as the exercise price of the related option. Upon the exercise of a stock appreciation right, we will pay the participant an amount equal to the product of (i) the excess of the per share fair market value of our common stock on the date of exercise over the strike price, multiplied by (ii) the number of shares of common stock with respect to which the stock appreciation right is exercised. Payment will be made in cash, delivery of stock, or a combination of cash and stock as deemed appropriate by the plan administrator.

 

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Adjustments in capitalization. In the event that there is a specified type of change in our common stock without the receipt of consideration by us, such as pursuant to a merger, consolidation, reorganization, recapitalization, reincorporation, stock dividend, dividend in property other than cash, stock split, liquidating dividend, combination of shares, exchange of shares, change in corporate structure or other transaction, appropriate adjustments will be made to the various limits under, and the share terms of, the plan including (i) the number and class of shares reserved under the plan, (ii) the maximum number of stock options and stock appreciation rights that can be granted to any one person in a calendar year and (iii) the number and class of shares and exercise price, strike price, or purchase price, if applicable, of all outstanding stock awards.

Corporate Transactions. In the event of a change in control transaction (other than a transaction resulting in Wexford or an entity controlled by, or under common control with Wexford maintaining direct or indirect control over the Company), or a corporate transaction such as a dissolution or liquidation of our company, or any corporate separation or division, including, but not limited to, a split-up, a split-off or a spin-off, or a sale in one or a series of related transactions, of all or substantially all of the assets of our company or a merger, consolidation, or reverse merger in which we are not the surviving entity, then all outstanding stock awards under the plan may be assumed, continued or substituted for by any surviving or acquiring entity (or its parent company), or may be cancelled either with or without consideration for the vested portion of the awards, all as determined by the plan administrator. In the event an award would be cancelled without consideration paid to the extent vested, the award recipient may exercise the award in full or in part for a period of ten days.

401(k) Plan

We participate in a 401(k) Plan. Employees may elect to defer a portion of their compensation up to the statutorily prescribed limit. Each pay period we make a matching contribution to each employee’s deferral, not to exceed six percent. An employee’s interests in his or her deferrals are 100% vested when contributed. An employee’s interests in the matching contribution are vested at the rate of 20% for each completed year of eligibility. The 401(k) Plan is intended to qualify under Section 401(a) of the Internal Revenue Code. As such, contributions to the 401(k) Plan and earnings on those contributions are not taxable to the employee until distributed from the 401(k) Plan, and all contributions are deductible by us when made.

Potential Payments Upon Termination, Resignation or Change of Control

The following table shows the estimated benefits payable to our named executive officers in various hypothetical scenarios as of December 31, 2011:

 

		Termination Without Cause or Upon Death or Disability(1)(2)																Resignation for Good Reason(3)																Change of Control
Name		Base Salary				Benefits				Options				Total				Base Salary				Benefits				Options				Total				Base Salary				Benefits				Options(4)				Total
Steven West			—				—				—				—				—				—				—				—				—				—				—				—
Travis D. Stice(5)		$	688,767	(7)			—				—			$	688,767	(7)							—				—								—				—
Teresa L. Dick(6)		$	186,986	(8)			—							$	186,986	(8)							—				—								—				—
Jeff White(6)		$	659,507	(9)			—							$	659,507	(9)							—				—								—				—

 

(1)

In the event a named executive officer (except for Mr. West) is terminated upon death or disability, the receipt of the payments and benefits described in this table is subject to such executive’s continued compliance with the non-competition, confidentiality, non-interference, proprietary information, return of property, non-solicitation and non-disparagement provisions of such executive’s employment agreement.

(2)

In the event a named executive officer is terminated without cause, the receipt of the payments and benefits described in this table are subject to (a) such executive’s continued compliance with the non-competition, confidentiality, non-interference, proprietary information, return of property, non-solicitation and non-disparagement provisions of such executive’s employment agreement and (b) such executive executing

 

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(and not revoking) a full general release of all claims, known or unknown against us, Wexford and various other parties affiliated with Wexford.

(3)

Under the terms of the employment agreements with our named executive officers (except for Mr. Stice), the applicable officer is entitled to certain benefits in the event such officer resigns for good cause, which means such resignation follows any (a) material breach by us of the terms of the applicable employment agreement or (b) material diminution in the officer’s position, duties or authority which in either case is not cured within thirty (30) business days following our receipt of notice thereof, subject to (i) such executive’s continued compliance with the non-competition, confidentiality, non-interference, proprietary information, return of property, non-solicitation and non-disparagement provisions of such executive’s employment agreement and (ii) such executive executing (and not revoking) a full general release of all claims, known or unknown against us, Wexford and various other parties affiliated with Wexford.

(4)

In connection with the closing of this offering, these options will be cancelled and replaced with the right to receive cash payments of $1,000,000, $300,000 and $350,000 for Mr. Stice, Ms. Dick and Mr. White, respectively, which, in the case of Mr. Stice, will be payable two-thirds at the time of the offering and one-third on the first anniversary of the offering, restricted stock units in an amount equal to $1,000,000, $300,000 and $600,000 divided by the IPO price per share for Mr. Stice, Ms. Dick and Mr. White, respectively, and options to purchase $300,000, 50,000 and 100,000 shares of our common stock at the IPO price per share for Mr. Stice, Ms. Dick and Mr. White, respectively.

(5)

Under the terms of Mr. Stice’s employment agreement, Mr. Stice’s equity awards granted pursuant to such agreement shall vest immediately in the event that more than 50% of the combined voting power of our then outstanding stock is controlled by one or more parties that is not us, Wexford or an affiliate of Wexford.

(6)

Under the terms of our employment agreement with each of Ms. Dick and Mr. White the equity awards granted under such agreement will vest immediately (a) in the event that more than 50% of the combined voting power of our then outstanding stock is controlled by one or more parties that is not us, Wexford, an affiliate of Wexford or an underwriter temporarily holding securities pursuant to an offering of securities and either there is a material change in the applicable named executive officer’s position, duties or authority or such officer is required to relocate to a location outside of a 50 mile radius of Midland, Texas or (b) upon termination without cause or upon death or disability.

(7)	Represents the amount payable under Mr. Stice’s employment agreement and is equal to Mr. Stice’s base salary for the remainder of the term of his employment agreement, which expires on April 18, 2014.

(8)	Represents the amount payable under Ms. Dick’s employment agreement and is equal to Mr. Dick’s base salary for the remainder of the term of her employment agreement, which expires on September 30, 2012.

(9)	Represents the amount payable under Mr. White’s employment agreement and is equal to Mr. White’s base salary for the remainder of the term of his employment agreement, which expires on September 30, 2014.

Limitations on Liability and Indemnification of Officers and Directors

Certificate of Incorporation and Bylaws

Our certificate of incorporation provides that no director shall be personally liable to us or any of our stockholders for monetary damages resulting from breaches of their fiduciary duty as directors, except to the extent such limitation on or exemption from liability is not permitted under the Delaware General Corporation Law, or DGCL. The effect of this provision of our certificate of incorporation is to eliminate our rights and those of our stockholders (through stockholders’ derivative suits on our behalf) to recover monetary damages against a director for breach of the fiduciary duty of care as a director, including breaches resulting from negligent or grossly negligent behavior, except, as restricted by the DGCL:

 

•

for any breach of the director’s duty of loyalty to the company or its stockholders;

 

•

for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;

 

•

in respect of certain unlawful dividend payments or stock redemptions or repurchases; and

 

•

for any transaction from which the director derives an improper personal benefit.

 

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This provision does not limit or eliminate our rights or the rights of any stockholder to seek non-monetary relief, such as an injunction or rescission, in the event of a breach of a director’s duty of care.

Our certificate of incorporation also provides that we will, to the fullest extent permitted by Delaware law, indemnify our directors and officers against losses that they may incur in investigations and legal proceedings resulting from their service.

Our bylaws include provisions relating to advancement of expenses and indemnification rights consistent with those provided in our certificate of incorporation. In addition, our bylaws provide:

 

•

for a right of indemnitee to bring a suit in the event a claim for indemnification or advancement of expenses is not paid in full by us within a specified period of time; and

 

•

permit us to purchase and maintain insurance, at our expense, to protect us and any of our directors, officers and employees against any loss, whether or not we would have the power to indemnify that person against that loss under Delaware law.

Indemnification Agreements

We will enter into indemnification agreements with each of our current directors and executive officers effective upon the closing of this offering. These agreements require us to indemnify these individuals to the fullest extent permitted under Delaware law against liabilities that may arise by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. We also intend to enter into indemnification agreements with our future directors and executive officers.

Liability Insurance

We intend to provide liability insurance for our directors and officers, including coverage for public securities matters. There is no pending litigation or proceeding involving any of our directors, officers or employees for which indemnification from us is sought. We are not aware of any threatened litigation that may result in claims for indemnification from us.

 

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RELATED PARTY TRANSACTIONS

Review and Approval of Related Party Transactions

We do not currently have a written policy regarding the review and approval of related party transactions, but intend to implement such a policy in connection with, and prior to the completion of, this offering. In connection with this offering, we will establish an audit committee consisting solely of independent directors whose functions will be set forth in the audit committee charter. We anticipate that one of the audit committee’s functions will be to review and approve all relationships and transactions in which we and our directors, director nominees and executive officers and their immediate family members, as well as holders of more than 5% of any class of our voting securities and their immediate family members, have a direct or indirect material interest. We anticipate that such policy will be a written policy included as part the audit committee charter that will be implemented by the audit committee and in the Code of Business Conduct and Ethics that our board of directors will adopt prior to the completion of this offering.

Historically, the review and approval of related party transactions have been the responsibility of our management, and all of the transactions discussed under “Related Party Transactions” below have been approved by our management, subject to a conflicts of interest policy set forth in our employee handbook, pursuant to which all of our employees must avoid any situations where their personal outside interest could conflict, or even appear to conflict, with the interests of the Company. Although our management believes that the terms of the related party transactions described below are reasonable, it is possible that we could have negotiated more favorable terms for such transactions with unrelated third parties.

Our management will continue to review and approve related party transactions, subject to the above-referenced conflicts of interest policy, until the adoption of the policy regarding the review and approval of such transactions by the audit committee, which we intend to adopt in connection with, and prior to the completion of, this offering.

Gulfport Transaction and Investor Rights Agreement

On May 7, 2012, we entered into an agreement with Gulfport in which we agreed to acquire from Gulfport, prior to the effectiveness of the registration statement of which this prospectus is a part, all of its oil and natural gas properties in the Permian Basin in exchange for (i) shares of our common stock representing 35% of our common stock outstanding immediately prior to the closing of this offering and (ii) approximately $63.6 million in the form of a non-interest bearing promissory note that will be repaid in full upon the closing of this offering with a portion of the net proceeds from this offering. The aggregate consideration payable to Gulfport is subject to a post-closing cash adjustment and will be increased or decreased by an amount equal to the difference between $118.1 million and the “final capital amount,” divided by 65% and then multiplied by 35%. For purposes of our agreement with Gulfport, “final capital amount” means Windsor Permian’s (a) total current assets, consisting of cash, trade accounts receivable (net of an allowance for doubtful accounts), inventory, prepaid expenses, other current assets and other assets, less (b) total current liabilities, consisting of trade accounts payable, accounts payable to related parties, accrued capital and other expenses, long-term debt and asset retirement obligations, in each case as of the closing date of the transaction. Accordingly, for purposes of illustration only, if the final capital amount is $110.0 million, we would owe Gulfport an additional approximately $4.4 million and if the final capital amount is $125.0 million, Gulfport would owe us approximately $3.7 million. Gulfport’s obligation to complete this transaction is contingent upon, among other things, the contribution to us of all the outstanding equity interests in Windsor Permian and Gulfport’s satisfaction with the terms of this offering. Under the agreement, Gulfport is generally responsible for all liabilities and obligations with respect to its Permian Basin properties arising prior to the closing of the transaction and we are responsible for such liabilities and obligations arising after the closing of the transaction. At the closing of the Gulfport transaction, we will enter into an investor rights agreement with Gulfport in which Gulfport will be granted certain (i) demand and “piggyback” registration rights, (ii) director nomination rights and (iii) information rights. For additional information regarding the terms of the Gulfport transaction agreement and the investor rights agreement, see “Prospectus Summary—The Transactions,” “Management—Our Board of Directors and Committees” and “Shares Eligible for Future Sale—Registration Rights” beginning on pages 7, 113 and 139, respectively, of this prospectus. Mike Liddell, who served as the Operating Member and Chairman of Windsor Permian prior to the completion of this offering, is also the Chairman of the Board and a

 

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director of Gulfport and has an interest in DB Holdings. Charles E. Davidson, the Chairman and Chief Investment Officer of Wexford, beneficially owned approximately 9.5% of Gulfport’s outstanding common stock as of March 13, 2012.

Administrative Services

We are a party to a shared services agreement, dated March 1, 2008, with Everest Operations Management LLC (formerly, Windsor Energy Resources LLC), or Everest, an entity controlled by Wexford, our equity sponsor. Under this agreement, Everest provided us with administrative and payroll services and office space in Oklahoma City, Oklahoma and we reimbursed Everest in an amount determined by Everest’s management based on estimates of the amount of office space provided and the amount of its employees’ time spent performing services for us. For purposes of presenting the consolidated financial statements, included elsewhere in this prospectus, allocations were made to determine the cost of general and administrative activities performed attributable to us. The allocations were made based upon underlying salary costs of employees performing Company related functions, payroll, revenue or headcount relative to other companies managed by Everest, or specifically identified invoices processed, depending on the nature of the cost.

The initial term of the shared services agreement with Everest was two years. Since the expiration of such two-year period on March 1, 2010, the agreement, by its terms, has continued on a month-to-month basis and will continue to do so until terminated by either party upon thirty days prior written notice. For the three months ended March 31, 2012 and the years ended December 31, 2011, 2010 and 2009, we incurred total costs to Everest of approximately $2.4 million, $10.0 million, $8.0 million and $5.5 million, respectively, and at March 31, 2012 and December 31, 2011, 2010 and 2009, we owed $0.6 million, $0.8 million, $0.4 million and $0.9 million, respectively, under this shared services agreement. We expect to discontinue all services under this shared services agreement prior to the closing of this offering.

Effective January 1, 2012, we entered into a shared services agreement with Everest under which we provide Everest and, at its request, certain of its affiliates with consulting, technical and administrative services, including payroll, human resources administration, accounts payable and treasury services. The initial term of the shared services agreement is two years. Upon expiration of the initial term, the agreement will continue on a month-to-month basis until cancelled by either party upon thirty days prior written notice. Everest, or its affiliates, reimburse us for our dedicated employee time and administrative costs based on the pro rata share of time our employees spend performing these services, including pro rata benefits and bonuses of such employees. For the three months ended March 31, 2012, Everest and its affiliates reimbursed us $445,360 for services and overhead under the shared services agreement and at March 31, 2012, Everest and its affiliates owed us $6,206.

Wexford Contribution

The historical financial and operating information included in this prospectus pertains to the assets, liabilities, revenues and expenses of Windsor Permian. Prior to the completion of this offering, Wexford will cause DB Holdings to contribute all of the outstanding equity interests in Windsor Permian to us in exchange for shares of our common stock and Windsor Permian will become our wholly-owned subsidiary. In addition, Wexford has agreed to cause all the outstanding equity interests in Windsor UT to be contributed to Windsor Permian prior to the time Windsor Permian is contributed to us. For additional information regarding this contribution by Wexford, see “Prospectus Summary—Our History” on page 8 of this prospectus.

Subordinated Note

Effective May 14, 2012, we issued a subordinated note to an affiliate of Wexford pursuant to which the Wexford affiliate may, from time to time, advance up to an aggregate $25.0 million. These advances are solely at the lender’s discretion and neither Wexford nor any of its affiliates has any commitment or obligation to provide future capital support to us. The note bears interest at a rate equal to LIBOR plus 0.28% or 8% per annum,

 

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whichever is lower. Interest is due quarterly in arrears beginning on July 1, 2012. Interest payments are payable in kind by adding such amounts to the principal balance of this note. The unpaid principal balance and all accrued interest on the note is due and payable in full on January 31, 2015 or the earlier completion of this offering. Any indebtedness evidenced by this note is subordinate in the right of payment to any indebtedness outstanding under our revolving credit facility. On June 30, 2012, there was $14.1 million in aggregate principal amount outstanding under this note. We will repay the outstanding borrowings under this note with a portion of the net proceeds of this offering.

Drilling Services

Bison Drilling and Field Services LLC, or Bison, has performed drilling and field services for us under master drilling agreements. Under our most recent master drilling agreement with Bison, effective as of January 1, 2012, Bison committed to accept orders from us for the use of at least two of its rigs. This master drilling agreement is terminable by either party on 30 day’s prior written notice, although neither party will be relieved of its respective obligations arising from a drilling contract being performed prior to the termination of the master drilling agreement. Bison was a wholly-owned subsidiary of Windsor Permian until March 31, 2011, when various entities controlled by Wexford started contributing capital to Bison. These contributions aggregated $11.5 million and ultimately diluted Windsor Permian’s ownership interest to 52.2%. In September 2011, Windsor Permian sold a 25% interest in Bison to Gulfport for $6.0 million, subject to adjustment. At the time of the transaction, an affiliate of Wexford beneficially owned approximately 13.3% of Gulfport’s common stock, but that ownership is now less than 10%. In April 2012, Gulfport increased its ownership interest in Bison to 40%. As a result of these transactions, Windsor Permian’s ownership interest in Bison was reduced to 22%, with the remaining equity interests in Bison held by Gulfport and various entities controlled by Wexford. In June 2012, Windsor Permian distributed its remaining interest in Bison to its member. As a result, we will not own any interest in Bison when all the outstanding equity interests in Windsor Permian are contributed to us prior to the completion of this offering. For the period April 1, 2011 through December 31, 2011 and the three months ended March 31, 2012, we were billed $16.3 million and $3.2 million, respectively, by Bison for drilling services. We owed no amounts to Bison as of March 31, 2012.

Completion and Well Servicing Services

We contracted with Great White Energy Services, or Great White, an entity formerly controlled by Wexford, for certain well completion services. For the year ended December 31, 2010 and 2009, we were billed $7.7 million and $3.3 million by Great White, and we owed $3.1 million for such services at December 31, 2010 and no amounts at December 31, 2009. Effective August 24, 2011, Great White was sold to an unrelated third party and, therefore, Great White is no longer a related party. While still a related party, during the year ended December 31, 2011 Great White billed us $12.5 million for such services.

Marketing Services

On March 1, 2009, we entered into an agreement with Windsor Midstream LLC, or Midstream, an entity controlled by Wexford, pursuant to which Midstream purchased a significant portion of our oil volumes. For the years ended December 31, 2011, 2010 and 2009, our revenues from Midstream were $38.2 million, $21.4 million and $8.8 million, respectively, and at March 31, 2012 and December 31, 2011, 2010 and 2009 we had an accounts receivable balance of zero, $4.1 million, $2.7 million and $1.5 million, respectively. Effective December 1, 2011, we ceased all sales of our oil production to Midstream under this agreement.

Midland Lease

We occupy our corporate headquarters in Midland, Texas under a five-year lease, effective May 15, 2011, with Fasken Midland, LLC, or Fasken, an entity controlled by an affiliate of Wexford. Through December 31, 2011, we paid $40,080 to Fasken under this lease. Our monthly rent as of March 31, 2012 under the lease was $7,593, and this amount will increase approximately 4% annually on June 1 of each year during the remainder of the lease term.

 

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Oklahoma City Lease

We occupy office space in Oklahoma City, Oklahoma under a sixty-seven month lease agreement, effective January 1, 2012, with Caliber Investment Group, LLC, or Caliber, an entity controlled by an affiliate of Wexford. Through March 31, 2012, we paid $123,633 to Caliber under this lease. Our monthly base rent as of March 31, 2012 was $15,352, which will increase to $16,687 on August 1, 2012 for the remainder of the lease term. We are also responsible for paying a portion of specified costs, fees and expenses associated with the operation of the premises.

Area of Mutual Interest and Related Agreements

Effective as of November 1, 2007, we and Gulfport entered into an area of mutual interest agreement to jointly acquire oil and gas leases in the Permian Basin. The agreement provides that each party must offer the other party the right to participate in 50% of each such acquisition. The parties also agreed, subject to certain exceptions, to share third-party costs and expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement. The agreement continues in force on a month-to-month basis until terminated by either party upon 30 days prior written notice.

In connection with the area of mutual interest agreement, we, Gulfport and Windsor Energy Group, L.L.C., or Energy Group, an entity controlled by Wexford, as the operator, entered into a joint development agreement, effective as of November 1, 2007, pursuant to which we and Gulfport agreed to develop certain jointly-held oil and gas leases in the Permian Basin and Energy Group agreed to act as the operator under the terms of a joint operating agreement, effective as of November 1, 2007. In the event either party has a majority interest in a prospect (as defined in the development agreement), the majority party may designate the operator of its choice. The parties agreed to designate Energy Group as the operator with respect to the contract area as provided in the joint operating agreement. As operator of these properties, Energy Group was responsible for the daily operations, monthly operation billings and monthly revenue disbursements for the properties in which we held an interest. Effective February 26, 2010, the agreement with Energy Group was terminated and we became the operator of these properties. As of December 31, 2011 we did not owe Energy Group any amounts. For the years ended December 31, 2010 and 2009, Energy Group billed us approximately $4.4 million and $20.7 million, respectively, and at December 31, 2010 and 2009, we owed $0.07 million and $2.8 million, respectively, for these services.

Upon becoming operator effective February 26, 2010, we began providing joint interest billing services to certain of our affiliates. For the three months ended March 31, 2012 and the years ended December 31, 2011 and 2010, we billed Gulfport $14.2 million, $56.7 million and $32.4 million, respectively, and we billed an entity controlled by Wexford $0.5 million, $5.3 million and $8.8 million, respectively, for such services. At March 31, 2012 and December 31, 2011 and 2010, Gulfport owed us $2.5 million, $8.6 million and $5.6 million, respectively, and the Wexford controlled entity owed us $0.1 million, $0.4 million and zero, respectively.

Our area of mutual interest agreement and joint development agreement, each with Gulfport, will be terminated upon the Gulfport transaction.

Investment in Muskie Holdings LLC

During 2011, Windsor Permian purchased certain assets, real estate and rights in a lease covering land in Wisconsin that is prospective for mining oil and natural gas fracture grade sand for $4.2 million from an unrelated third party. On October 7, 2011, Windsor Permian contributed these assets, real estate and lease rights to a newly-formed entity, Muskie Holdings LLC, or Muskie, in exchange for a 48.6% equity interest. The remaining equity interests in Muskie are held 25% by Gulfport and 26.4% by entities controlled by Wexford. Through additional contributions from the Wexford-controlled entities to Muskie, Windsor Permian’s equity interest decreased to approximately 33%. In June 2012, Windsor Permian distributed its remaining interest in Muskie to its member. As a result, we will not own any interest in Muskie when all the outstanding equity interests in Windsor Permian are contributed to us prior to the completion of this offering.

 

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MidMar

We are party to a gas purchase agreement, dated May 1, 2009, as amended, with MidMar Gas LLC, or MidMar, an entity that owns a gas gathering system and processing plant in the Permian Basin. Under this agreement, MidMar is obligated to purchase from us, and we are obligated to sell to MidMar, all of the gas conforming to certain quality specifications produced from certain of our Permian Basin acreage. Following the expiration of the initial ten-year term, the agreement will continue on a year-to-year basis until terminated by either party on 30 days written notice. Under the gas purchase agreement, MidMar is obligated to pay us 87% of the net revenue received by MidMar for all components of our dedicated gas, including liquid hydrocarbons, and the sale of residue gas, in each case, extracted, recovered or otherwise processed at MidMar’s gas processing plant; and 94.56% of the net revenue received by MidMar from the sale of such gas components and residue gas, extracted, recovered or otherwise processed at the Chevron Headlee plant. Travis D. Stice, our Chief Executive Officer, has served as a manager on MidMar’s board of managers since April 2011 and as Vice President and Secretary of MidMar since April 2012. An entity controlled by Wexford in which Gulfport and certain entities controlled by Wexford are members owns approximately a 28% equity interest in MidMar. The remaining equity interests in MidMar are owned by nonaffiliated third parties. For the three months ended March 31, 2012 and the years ended December 31, 2011 and 2010, MidMar paid us $0.8 million, $3.1 million and $1.1 million, respectively, and at March 31, 2012 and December 31, 2011 and 2010, MidMar owed us $1.0 million, $0.4 million and $0.1 million, respectively, for our portion of the net proceeds from the sale of such gas products and residue gas by MidMar. We were not paid, nor were we owed, any amounts for 2009 by MidMar.

Advisory Services Agreement

Prior to the closing of this offering we will enter into an advisory services agreement with Wexford under which Wexford will provide us with general financial and strategic advisory services related to our business in return for an annual fee of $500,000, plus reasonable out-of-pocket expenses. This agreement has a term of two years commencing on the completion of this offering. The parties may extend the then current term for additional one-year periods by entering into a written agreement reflecting the terms of such extension at least ten days prior to the expiration of the then current term. The agreement may be terminated at any time by either party upon 30 days’ prior written notice. In the event we terminate the agreement, we are obligated to pay all amounts due through the remaining term of the agreement. In addition, in this agreement we have agreed to pay Wexford to-be-negotiated market-based fees approved by our independent directors for such services as may be provided by Wexford at our request in connection with future acquisitions and divestitures, financings or other transactions in which we may be involved. The services provided by Wexford under the advisory services agreement will not extend to our day-to-day business or operations. In this agreement, we have agreed to indemnify Wexford and its affiliates from any and all losses arising out of or in connection with the agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willful misconduct.

Registration Rights

Prior to the closing of this offering, we will enter a registration rights agreements with DB Holdings and Gulfport under which we will grant DB Holdings and Gulfport certain demand and “piggyback” registration rights. For more information regarding this agreement, see “Shares Eligible for Future Sale—Registration Rights” on page 139 of this prospectus.

 

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PRINCIPAL AND SELLING STOCKHOLDERS

The following table sets forth certain information with respect to the beneficial ownership of our common stock by:

 

•

each selling stockholder;

 

•

each stockholder known by us to be the beneficial owner of more than five percent of the outstanding shares of our common stock;

 

•

each of our directors;

 

•

each of our named executive officers; and

 

•

all of our directors and executive officers as a group.

Except as otherwise indicated, we believe that each of the stockholders named in this table has sole voting and investment power with respect to the shares indicated as beneficially owned.

 

Name of Beneficial Owner

Shares Beneficially Owned Prior to Offering

Number of Shares Offered

Shares Beneficially Owned After Offering(1)

Shares to be Sold if Option to Purchase Additional Shares Is Exercised in Full

Shares Beneficially Owned After Offering if Option to Purchase Additional Shares Is Exercised in Full

Number

Percentage

Number

Percentage

Number

Percentage

Selling Stockholders and other 5% Stockholders:

DB Energy Holdings LLC(2)

Gulfport Energy Corporation

Executive Officers and Directors:

Travis D. Stice

Teresa L. Dick

Russell Pantermuehl

Paul Molnar

Michael Hollis

William Franklin

Jeff White

Randall J. Holder

Steven E. West

Michael P. Cross

David L. Houston

Mark L. Plaumann

All executive officers directors and director nominees as a group (12 persons)

 

(1)

Percentage of beneficial ownership is based upon shares of common stock outstanding immediately prior to the offering after giving effect to the Transactions, and             shares of common stock outstanding after the offering. For purposes of this table, a person or group of persons is deemed to have “beneficial ownership” of any shares which such person has the right to acquire within 60 days. For purposes of computing the percentage of outstanding shares held by each person or group of persons named above, any security which such person or group of persons has the right to acquire within 60 days is deemed to be outstanding for the purpose of computing the percentage ownership for such person or persons, but is not deemed to be outstanding for the purpose of computing the percentage ownership of any other person. As a result, the denominator used in calculating the beneficial ownership among our stockholders may differ.

(2)	Wexford is the manager of DB Holdings, which is one of the selling stockholders in this offering. The number of shares to be sold in the offering by DB Holdings includes up to              shares that will be sold if the underwriters exercise

 

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their option to purchase additional shares in full. As manager of DB Holdings, Wexford has the exclusive authority to, among other things, purchase, hold and dispose of its assets, including the shares of our common stock that will be owned by DB Holdings. Wexford may, by reason of its status as manager of DB Holdings, be deemed to beneficially own the interest in the shares of our common stock owned by DB Holdings. Each of Charles E. Davidson and Joseph M. Jacobs may, by reason of his status as a controlling person of Wexford, be deemed to beneficially own the interests in the shares of our common stock owned by DB Holdings. Each of Charles E. Davidson, Joseph M. Jacobs and Wexford share the power to vote and to dispose of the interests in the shares of our common stock owned by DB Holdings. Each of Messrs. Davidson and Jacobs disclaims beneficial ownership of the shares of our common stock owned by DB Holdings and Wexford. Wexford’s address is Wexford Plaza, 411 West Putnam Avenue, Greenwich, Connecticut 06830.

Each of the selling stockholders in this offering is deemed to be an underwriter within the meaning of Section 2(a)(11) of the Securities Act.

 

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DESCRIPTION OF CAPITAL STOCK

We will amend and restate our certificate of incorporation and bylaws in connection with this offering. The following description of our common stock, certificate of incorporation and our bylaws are summaries thereof and are qualified by reference to our certificate of incorporation and our bylaws as so amended and restated, copies of which will be filed with the SEC as exhibits to the registration statement of which this prospectus is a part.

Our authorized capital stock consists of              shares of common stock, par value $0.01 per share, and              shares of preferred stock, par value $0.01 per share. We have applied to have our shares of common stock listed on The NASDAQ Global Market under the symbol “FANG.”

Common Stock

Holders of shares of common stock are entitled to one vote per share on all matters submitted to a vote of stockholders. Shares of common stock do not have cumulative voting rights, which means that the holders of more than 50% of the shares voting for the election of the board of directors can elect all the directors to be elected at that time, and, in such event, the holders of the remaining shares will be unable to elect any directors to be elected at that time. Our certificate of incorporation denies stockholders any preemptive rights to acquire or subscribe for any stock, obligation, warrant or other securities of ours. Holders of shares of our common stock have no redemption or conversion rights nor are they entitled to the benefits of any sinking fund provisions.

In the event of our liquidation, dissolution or winding up, holders of shares of common stock shall be entitled to receive, pro rata, all the remaining assets of our company available for distribution to our stockholders after payment of our debts and after there shall have been paid to or set aside for the holders of capital stock ranking senior to common stock in respect of rights upon liquidation, dissolution or winding up the full preferential amounts to which they are respectively entitled.

Holders of record of shares of common stock are entitled to receive dividends when and if declared by the board of directors out of any assets legally available for such dividends, subject to both the rights of all outstanding shares of capital stock ranking senior to the common stock in respect of dividends and to any dividend restrictions contained in debt agreements. All outstanding shares of common stock and any shares sold and issued in this offering will be fully paid and nonassessable by us.

Preferred Stock

Our board of directors is authorized to issue up to              shares of preferred stock in one or more series. The board of directors may fix for each series:

 

•

the distinctive serial designation and number of shares of the series;

 

•

the voting powers and the right, if any, to elect a director or directors;

 

•

the terms of office of any directors the holders of preferred shares are entitled to elect;

 

•

the dividend rights, if any;

 

•

the terms of redemption, and the amount of and provisions regarding any sinking fund for the purchase or redemption thereof;

 

•

the liquidation preferences and the amounts payable on dissolution or liquidation;

 

•

the terms and conditions under which shares of the series may or shall be converted into any other series or class of stock or debt of the corporation; and

 

•

any other terms or provisions which the board of directors is legally authorized to fix or alter.

 

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We do not need stockholder approval to issue or fix the terms of the preferred stock. The actual effect of the authorization of the preferred stock upon your rights as holders of common stock is unknown until our board of directors determines the specific rights of owners of any series of preferred stock. Depending upon the rights granted to any series of preferred stock, your voting power, liquidation preference or other rights could be adversely affected. Preferred stock may be issued in acquisitions or for other corporate purposes. Issuance in connection with a stockholder rights plan or other takeover defense could have the effect of making it more difficult for a third party to acquire, or of discouraging a third party from acquiring, control of our company. We have no present plans to issue any shares of preferred stock.

Related Party Transactions and Corporate Opportunities

Subject to the limitations of applicable law, our certificate of incorporation, among other things:

 

•

permits us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested so long as it has been approved by our board of directors;

 

•

permits any of our stockholders, officers or directors to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and

 

•

provides that if any director or officer of one of our affiliates who is also one of our officers or directors becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as our director or officer), that director or officer will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer that opportunity to such affiliates and that director or officer will not be deemed to have (i) acted in a manner inconsistent with his or her fiduciary or other duties to us regarding the opportunity or (ii) acted in bad faith or in a manner inconsistent with our best interests.

Anti-takeover Effects of Provisions of Our Certificate of Incorporation and Our Bylaws

Some provisions of our certificate of incorporation and our bylaws contain provisions that could make it more difficult to acquire us by means of a merger, tender offer, proxy contest or otherwise, or to remove our incumbent officers and directors. These provisions, summarized below, are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with our board of directors. We believe that the benefits of increased protection of our potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging such proposals because negotiation of such proposals could result in an improvement of their terms.

Undesignated preferred stock. The ability to authorize and issue undesignated preferred stock may enable our board of directors to render more difficult or discourage an attempt to change control of us by means of a merger, tender offer, proxy contest or otherwise. For example, if in the due exercise of its fiduciary obligations, the board of directors were to determine that a takeover proposal is not in our best interest, the board of directors could cause shares of preferred stock to be issued without stockholder approval in one or more private offerings or other transactions that might dilute the voting or other rights of the proposed acquirer or insurgent stockholder or stockholder group.

Stockholder meetings. Our certificate of incorporation and bylaws provide that a special meeting of stockholders may be called only by the Chairman of the Board, the Chief Executive Officer or by a resolution adopted by a majority of our board of directors.

Requirements for advance notification of stockholder nominations and proposals. Our bylaws establish advance notice procedures with respect to stockholder proposals and the nomination of candidates for election as directors, other than nominations made by or at the direction of the board of directors.

 

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Stockholder action by written consent. Our bylaws provide that, except as may otherwise be provided with respect to the rights of the holders of preferred stock, no action that is required or permitted to be taken by our stockholders at any annual or special meeting may be effected by written consent of stockholders in lieu of a meeting of stockholders, unless the action to be effected by written consent of stockholders and the taking of such action by such written consent have expressly been approved in advance by our board. This provision, which may not be amended except by the affirmative vote of at least 66 2/3% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting together as a single class, makes it difficult for stockholders to initiate or effect an action by written consent that is opposed by our board.

Amendment of the bylaws. Under Delaware law, the power to adopt, amend or repeal bylaws is conferred upon the stockholders. A corporation may, however, in its certificate of incorporation also confer upon the board of directors the power to adopt, amend or repeal its bylaws. Our certificate of incorporation and bylaws grant our board the power to adopt, amend and repeal our bylaws at any regular or special meeting of the board on the affirmative vote of a majority of the directors then in office. Our stockholders may adopt, amend or repeal our bylaws but only at any regular or special meeting of stockholders by an affirmative vote of holders of at least 66 2/3% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting together as a single class.

Removal of Director. Our certificate of incorporation and bylaws provide that members of our board of directors may only be removed by the affirmative vote of holders of at least 66 2/3% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting together as a single class.

Amendment of the Certificate of Incorporation. Our certificate of incorporation provides that, in addition to any other vote that may be required by law or any preferred stock designation, the affirmative vote of the holders of at least 66 2/3% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting together as a single class, is required to amend, alter or repeal, or adopt any provision as part of our certificate of incorporation inconsistent with the provisions of our certificate of incorporation dealing with distributions on our common stock, related party transactions, our board of directors, our bylaws, meetings of our stockholders or amendment of our certificate of incorporation.

The provisions of our certificate of incorporation and bylaws could have the effect of discouraging others from attempting hostile takeovers and, as a consequence, they may also inhibit temporary fluctuations in the market price of our common stock that often result from actual or rumored hostile takeover attempts. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish transactions which stockholders may otherwise deem to be in their best interests.

Transfer Agent and Registrar

Computershare Trust Company, N.A. will be the transfer agent and registrar for our common stock.

 

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SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has been no public market for our common stock. Future sales of substantial amounts of our common stock in the public market, or the perception that such sales may occur, could adversely affect the prevailing market price of our common stock. We cannot predict the effect, if any, that future sales of shares, or the availability of shares for future sales, will have on the market price of our common stock prevailing from time to time.

Sale of Restricted Shares

Upon completion of this offering, we will have              shares of common stock outstanding. Of these shares of common stock, the              shares of common stock being sold in this offering, plus any shares sold upon exercise of the underwriters’ option to purchase additional shares, will be freely tradable without restriction under the Securities Act, except for any such shares held or acquired by an “affiliate” of ours, as that term is defined in Rule 144 promulgated under the Securities Act, which shares will be subject to the volume limitations and other restrictions of Rule 144 described below. The remaining              shares of common stock held by our existing stockholder upon completion of this offering, or              shares if the underwriters exercise their option to purchase additional shares in full, will be “restricted securities,” as that phrase is defined in Rule 144, and may be resold only after registration under the Securities Act or pursuant to an exemption from such registration, including, among others, the exemptions provided by Rule 144 and 701 under the Securities Act, which rules are summarized below. These remaining shares of common stock held by our existing stockholder upon completion of this offering will be available for sale in the public market after the expiration of the lock-up agreements described in “Underwriting ” beginning on page 144 of this prospectus, taking into account the provisions of Rules 144 and 701 under the Securities Act.

Rule 144

In general, under Rule 144 as currently in effect, persons who became the beneficial owner of shares of our common stock prior to the completion of this offering may sell their shares upon the earlier of (1) the expiration of a six-month holding period, if we have been subject to the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), for at least 90 days prior to the date of the sale and have filed all reports required thereunder, or (2) the expiration of a one-year holding period.

At the expiration of the six-month holding period, assuming we have been subject to the Exchange Act reporting requirements for at least 90 days and have filed all reports required thereunder, a person who was not one of our affiliates at any time during the three months preceding a sale would be entitled to sell an unlimited number of shares of our common stock, and a person who was one of our affiliates at any time during the three months preceding a sale would be entitled to sell, within any three-month period, a number of shares of common stock that does not exceed the greater of either of the following:

 

•

1% of the number of shares of our common stock then outstanding, which will equal approximately              shares immediately after this offering; or

 

•

the average weekly trading volume of our common stock on The NASDAQ Global Market during the four calendar weeks preceding the filing of a notice on Form 144 with respect to the sale.

At the expiration of the one-year holding period, a person who was not one of our affiliates at any time during the three months preceding a sale would be entitled to sell an unlimited number of shares of our common stock without restriction. A person who was one of our affiliates at any time during the three months preceding a sale would remain subject to the volume restrictions described above.

Sales under Rule 144 by our affiliates are also subject to manner of sale provisions and notice requirements and to the availability of current public information about us.

 

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Rule 701

In general, under Rule 701, any of our employees, directors, officers, consultants or advisors who purchased shares from us in connection with a compensatory stock or option plan or other written agreement before the effective date of this offering, or who purchased shares from us after that date upon the exercise of options granted before that date, are eligible to resell such shares in reliance upon Rule 144 beginning 90 days after the date of this prospectus. If such person is not an affiliate, the sale may be made subject only to the manner-of-sale restrictions of Rule 144. If such a person is an affiliate, the sale may be made under Rule 144 without compliance with its one-year minimum holding period, but subject to the other Rule 144 restrictions.

Registration Rights

Prior to the closing of this offering, we will enter into a registration rights agreements with DB Holdings and an investor rights agreement with Gulfport. Under these agreements, each of DB Holdings and Gulfport has demand and “piggyback” registration rights. The demand rights enable each such stockholder to require us to register its shares of our common stock with the SEC at any time, subject to the 180-day lock-up agreement it has entered into in connection with this offering. The piggyback rights will allow each such stockholder to register the shares of our common stock that it owns along with any shares that we register with the SEC. These registration rights are subject to customary conditions and limitations, including the right of the underwriters of an offering to limit the number of shares.

Stock Plans

We intend to file one or more registration statements on Form S-8 under the Securities Act to register shares of our common stock issued or reserved for issuance under our equity incentive plan. The first such registration statement is expected to be filed soon after the date of this prospectus and will automatically become effective upon filing with the SEC. Accordingly, shares registered under such registration statement will be available for sale in the open market following the effective date, unless such shares are subject to vesting restrictions with us, Rule 144 restrictions applicable to our affiliates or the lock-up restrictions described below.

Lock-Up Agreements

We, each of our directors and executive officers, DB Holdings and Gulfport have agreed that, subject to certain exceptions, without the prior written consent of Credit Suisse Securities (USA) LLC, we and they will not, directly or indirectly, for a period of 180 days after the date of the offering (a period that may be extended for up to 18 days under certain circumstances), offer, pledge, sell, contract to sell or otherwise transfer or dispose of any shares of our common stock (other than the shares of our common stock subject to this offering) or any other securities convertible into or exercisable or exchangeable for our common stock. For additional information, see “Underwriting” beginning on page 144 of this prospectus.

 

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MATERIAL U.S. FEDERAL INCOME AND ESTATE TAX CONSIDERATIONS FOR NON-U.S. HOLDERS

The following is a general discussion of material U.S. federal income and estate tax consequences of the ownership and disposition of our common stock by a non-U.S. holder (as defined below). This discussion deals only with common stock purchased in this offering that is held as a “capital asset” within the meaning of Section 1221 of the Internal Revenue Code of 1986, as amended, or the Code (generally, property held for investment), by a non-U.S. holder. Except as modified for estate tax purposes, the term “non-U.S. holder” means a beneficial owner of our common stock that is not a “U.S. person” or a partnership for U.S. federal income and estate tax purposes. A U.S. person is any of the following:

 

•

an individual who is a citizen or resident of the United States;

 

•

a corporation (including any entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof or the District of Columbia;

 

•

an estate whose income is subject to U.S. federal income taxation regardless of its source; or

 

•

a trust, if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have authority to control all substantial decisions of the trust, or if it has a valid election in effect under applicable U.S. Treasury Regulations to be treated as a U.S. person.

An individual may generally be treated as a resident of the United States in any calendar year for U.S. federal income tax purposes, by, among other ways, being present in the United States for at least 31 days in that calendar year and for an aggregate of at least 183 days during a three-year period ending in the current calendar year. For purposes of the 183-day calculation, all of the days present in the current year, one-third of the days present in the immediately preceding year and one-sixth of the days present in the second preceding year are counted. Residents are taxed for U.S. federal income tax purposes as if they were U.S. citizens.

This discussion is based upon provisions of the Code, and Treasury Regulations, administrative rulings and judicial decisions, all as of the date hereof. Those authorities may be changed, perhaps retroactively, so as to result in U.S. federal income and estate tax consequences different from those discussed below. No ruling has been or will be sought from the Internal Revenue Service, or IRS, with respect to the matters discussed below, and there can be no assurance the IRS will not take a contrary position regarding the tax consequences of the acquisition, ownership or disposition of our common stock, or that such contrary position would not be sustained by a court. This discussion does not address all aspects of U.S. federal income and estate taxation and does not deal with other U.S. federal tax laws (such as gift tax laws) or foreign, state, local or other tax considerations that may be relevant to non-U.S. holders in light of their personal circumstances. In addition, this discussion does not address tax considerations applicable to investors that may be subject to special treatment under the U.S. federal income tax laws, such as (without limitation):

 

•

certain former U.S. citizens or residents;

 

•

shareholders that hold our common stock as part of a straddle, constructive sale transaction, synthetic security, hedge, conversion transaction or other integrated investment or risk reduction transaction;

 

•

shareholders that acquired our common stock through the exercise of employee stock options or otherwise as compensation or through a tax-qualified retirement plan;

 

•

shareholders that are partnerships or entities treated as partnerships for U.S. federal income tax purposes or other pass-through entities or owners thereof;

 

•

shareholders that own, or are deemed to own, more than five percent (5%) of our outstanding common stock (except to the extent specifically set forth below);

 

•

shareholders subject to the alternative minimum tax;

 

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•

financial institutions, banks and thrifts;

 

•

insurance companies;

 

•

tax-exempt entities;

 

•

real estate investment trusts;

 

•

“controlled foreign corporations,” “passive foreign investment companies” or corporations that accumulate earnings to avoid U.S. federal income tax;

 

•

broker-dealers or dealers in securities or foreign currencies; and

 

•

traders in securities that use a mark-to-market method of accounting for U.S. federal income tax purposes.

If a partnership (including an entity treated as a partnership for U.S. federal income tax purposes) holds our common stock, the U.S. federal income tax treatment of a partner generally will depend upon the status of the partner and the activities of the partnership. If you are a partner of a partnership (including an entity treated as a partnership for U.S. federal income tax purposes) holding our common stock, you should consult your tax advisor.

THIS DISCUSSION IS FOR GENERAL INFORMATION ONLY AND SHOULD NOT BE VIEWED AS TAX ADVICE. INVESTORS CONSIDERING THE PURCHASE OF OUR COMMON STOCK SHOULD CONSULT THEIR OWN TAX ADVISORS REGARDING THE APPLICATION OF THE U.S. FEDERAL INCOME AND ESTATE AND GIFT TAX LAWS TO THEIR PARTICULAR SITUATION AS WELL AS THE APPLICABILITY AND EFFECT OF ANY STATE, LOCAL OR FOREIGN TAX LAWS OR TAX TREATIES AND ANY OTHER U.S. FEDERAL TAX LAWS.

Distributions on Common Stock

We do not expect to pay any cash distributions on our common stock in the foreseeable future. However, in the event we do make such cash distributions, these distributions generally will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. If any such distribution exceeds our current and accumulated earnings and profits, the excess will be treated as a non-taxable return of capital to the extent of the non-U.S. holder’s tax basis in our common stock and thereafter as capital gain from the sale or exchange of such common stock. See “—Gain on Disposition of Common Stock” below. Dividends paid to a non-U.S. holder of our common stock that are not effectively connected with the non-U.S. holder’s conduct of a trade or business within the United States will be subject to U.S. withholding tax at a 30% rate, or if an income tax treaty applies, a lower rate specified by the treaty. In order to receive a reduced treaty rate, a non-U.S. holder must provide to us or our withholding agent IRS Form W-8BEN (or applicable substitute or successor form) properly certifying eligibility for the reduced rate. Non-U.S. holders that do not timely provide us or our withholding agent with the required certification, but that qualify for a reduced treaty rate, may obtain a refund of any excess amounts withheld by timely filing an appropriate claim for refund with the IRS. Non-U.S. holders should consult their tax advisors regarding their entitlement to benefits under an applicable income tax treaty.

Dividends that are effectively connected with a non-U.S. holder’s conduct of a trade or business in the United States and, if an income tax treaty so requires, are attributable to a permanent establishment maintained by the non-U.S. holder in the United States, are taxed on a net income basis at the regular graduated rates and in the manner applicable to U.S. persons. In that case, we or our withholding agent will not have to withhold U.S. federal withholding tax if the non-U.S. holder complies with applicable certification and disclosure requirements (which may generally be met by providing an IRS Form W-8ECI). In addition, a “branch profits tax” may be imposed at a 30% rate (or a lower rate specified under an applicable income tax treaty) on a foreign corporation’s effectively connected earnings and profits for the taxable year, as adjusted for certain items. Non-U.S. holders should consult any applicable income tax treaties that may provide for different rules.

 

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Gain on Disposition of Common Stock

Subject to the discussion below regarding backup withholding, a non-U.S. holder generally will not be subject to U.S. federal income tax on gain recognized on a disposition of our common stock unless:

 

•

the gain is effectively connected with the non-U.S. holder’s conduct of a trade or business in the United States and, if an income tax treaty applies, is attributable to a permanent establishment maintained by the non-U.S. holder in the United States, in which case, the gain will be taxed on a net income basis at the U.S. federal income tax rates and in the manner applicable to U.S. persons, and if the non-U.S. holder is a foreign corporation, the branch profits tax described above may also apply;

 

•

the non-U.S. holder is an individual who is present in the United States for 183 days or more in the taxable year of the disposition and meets other requirements, in which case, the non-U.S. holder will be subject to a flat 30% tax on the gain derived from the disposition (or such lower rate specified by an applicable income tax treaty), which may be offset by U.S. source capital losses, provided the non-U.S. holder has timely filed U.S. federal income tax returns with respect to such losses; or

 

•

we are or have been a “United States real property holding corporation”, or USRPHC, for U.S. federal income tax purposes at any time during the shorter of the five-year period ending on the date of disposition or the period that the non-U.S. holder held our common stock.

Generally, a corporation is a USRPHC if the fair market value of its United States real property interests equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We believe we currently are a USRPHC. If we are or become a USRPHC, a non-U.S holder nonetheless will not be subject to U.S. federal income tax or withholding in respect of any gain realized on a sale or other disposition of our common stock so long as (i) our common stock is “regularly traded on an established securities market” for U.S. federal income tax purposes and (ii) such non-U.S. holder does not actually or constructively own, at any time during the applicable period described in the third bullet point, above, more than 5% of our outstanding common stock. We expect our common stock to be “regularly traded” on an established securities market, although we cannot guarantee it will be so traded. Accordingly, a non-U.S holder who actually or constructively owns more than 5% of our common stock would be subject to U.S. federal income tax and withholding in respect of any gain realized on any sale or other disposition of common stock (taxed in the same manner as gain that is effectively connected income, except that the branch profits tax would not apply). Non-U.S. holders should consult their own advisor about the consequences that could result if we are, or become, a USRPHC.

Information Reporting and Backup Withholding Tax

Dividends paid to you will generally be subject to information reporting and may be subject to U.S. backup withholding. You will be exempt from backup withholding if you properly provide a Form W-8BEN certifying under penalties of perjury that you are a non-U.S. holder or otherwise meet documentary evidence requirements for establishing that you are a non-U.S. holder, or you otherwise establish an exemption. Copies of the information returns reporting such dividends and the tax withheld with respect to such dividends also may be made available to the tax authorities in the country in which you reside.

The gross proceeds from the disposition of our common stock may be subject to information reporting and backup withholding. If you receive payments of the proceeds of a disposition of our common stock to or through a U.S. office of a broker, the payment will be subject to both U.S. backup withholding and information reporting unless you properly provide an IRS Form W-8BEN certifying under penalties of perjury that you are a non-U.S. person (and the payor does not have actual knowledge or reason to know that you are a U.S. person) or you otherwise establish an exemption. If you sell your common stock outside the United States through a non-U.S. office of a non-U.S. broker and the sales proceeds are paid to you outside the United States, then the U.S. backup withholding and information reporting requirements generally will not apply to that payment. However, U.S.

 

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information reporting, but not backup withholding, will generally apply to a payment of sales proceeds, even if that payment is made outside the United States, if you sell your common stock through a non-U.S. office of a broker that has certain relationships with the United States unless the broker has documentary evidence in its files that you are a non-U.S. person and certain other conditions are met, or you otherwise establish an exemption.

Backup withholding is not an additional tax. You may obtain a refund or credit of any amounts withheld under the backup withholding rules that exceed your U.S. federal income tax liability, if any, provided the required information is timely furnished to the IRS.

Additional Withholding Requirements

Withholding taxes may apply to certain types of payments made to “foreign financial institutions” (as defined in the Code) and certain other non-U.S. entities. Specifically, the relevant withholding agent may be required to withhold 30% of any dividends and the proceeds of a sale or other disposition of our common stock paid to (i) a foreign financial institution unless such foreign financial institution undertakes certain diligence and reporting and enters into an agreement with the IRS requiring, among other things, that it undertake to identify accounts held by certain U.S. persons or U.S. owned foreign entities, annually report certain information about such accounts, and withhold 30% on payments to non-compliant foreign financial institutions and certain other account holders or (ii) a non-financial foreign entity that is the beneficial owner of the payment unless such entity certifies that it does not have any substantial United States owners or provides the name, address and taxpayer identification number of each substantial United States owner and such entity meets certain other requirements.

Although these rules currently apply to applicable payments made after December 31, 2012, the IRS has issued Proposed Treasury Regulations providing that withholding will only be made on payments of dividends made on or after January 1, 2014, and on other withholdable payments (including payments of gross proceeds) made on or after January 1, 2015. The Proposed Treasury Regulations described above will not be effective until they are issued in their final form, and as of the date of this prospectus, it is not possible to determine whether the proposed regulations will be finalized in their current form or at all. Prospective investors should consult their tax advisors regarding these withholding provisions.

Federal Estate Tax

Our common stock that is owned (or treated as owned) by an individual who is not a citizen or resident of the United States (as specially defined for U.S. federal estate tax purposes) at the time of death will be included in such individual’s gross estate for U.S. federal estate tax purposes, unless an applicable estate tax treaty provides otherwise, and, therefore, may be subject to U.S. federal estate tax.

 

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UNDERWRITING

Under the terms and subject to the conditions contained in an underwriting agreement dated                 , 2012 we and the selling stockholders have agreed to sell to the underwriters named below, for whom Credit Suisse Securities (USA) LLC is acting as representative, the following respective numbers of shares of common stock:

 

Underwriter		Number of Shares
Credit Suisse Securities (USA) LLC
Total

The underwriting agreement provides that the underwriters are obligated to purchase all the shares of common stock in the offering if any are purchased, other than those shares covered by the option described below. The underwriting agreement also provides that if an underwriter defaults, the purchase commitments of non-defaulting underwriters may be increased or the offering may be terminated.

We and the selling stockholders have granted to the underwriters a 30-day option to purchase on a pro rata basis up to an aggregate of              additional shares at the initial public offering price less the underwriting discounts and commissions. The option may be exercised only to cover any over-allotments of common stock.

The underwriters propose to offer the shares of common stock initially at the public offering price on the cover page of this prospectus and to selling group members at that price less a selling concession of $            per share. The underwriters and selling group members may allow a discount of $            per share on sales to other broker/dealers. After the initial public offering the representatives may change the public offering price and concession and discount to broker/dealers. The offering of the shares by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.

Each of the selling stockholders in this offering is deemed to be an underwriter within the meaning of Section 2(a)(11) of the Securities Act.

The following table summarizes the compensation and estimated expenses we and the selling stockholders will pay:

 

		Per Share				Total
		Without Over-allotment		With Over-allotment		Without Over-allotment		With Over-allotment
Underwriting Discounts and Commissions paid by us		$		$		$		$
Expenses payable by us		$		$		$		$
Underwriting Discounts and Commissions paid by selling stockholders		$		$		$		$

We estimate that our out of pocket expenses for this offering will be approximately $            . We have agreed to pay expenses incurred by the selling stockholders in connection with this offering other than the underwriting discounts and commissions.

The representative has informed us that it does not expect sales to accounts over which the underwriters have discretionary authority to exceed 5% of the shares of common stock being offered.

We have agreed that, subject to certain exceptions, we will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, or file with the Securities and Exchange Commission a registration statement under the Securities Act relating to any shares of our common stock or securities convertible into or

 

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exchangeable or exercisable for any shares of our common stock, or publicly disclose the intention to make any offer, sale, pledge, disposition or filing, without the prior written consent of Credit Suisse Securities (USA) LLC for a period of 180 days after the date of this prospectus. However, in the event that either (1) during the last 17 days of the “lock-up” period, we release earnings results or material news or a material event relating to us occurs or (2) prior to the expiration of the “lock-up” period, we announce that we will release earnings results during the 16-day period beginning on the last day of the “lock-up” period, then in either case the expiration of the “lock-up” will be extended until the expiration of the 18-day period beginning on the date of the release of the earnings results or the occurrence of the material news or event, as applicable, unless Credit Suisse Securities (USA) LLC waives, in writing, such an extension.

Our officers and directors and the selling stockholders have agreed that, subject to certain exceptions, they will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, any shares of our common stock or securities convertible into or exchangeable or exercisable for any shares of our common stock, enter into a transaction that would have the same effect, or enter into any swap, hedge or other arrangement that transfers, in whole or in part, any of the economic consequences of ownership of our common stock, whether any of these transactions are to be settled by delivery of our common stock or other securities, in cash or otherwise, or publicly disclose the intention to make any offer, sale, pledge or disposition, or to enter into any transaction, swap, hedge or other arrangement, without, in each case, the prior written consent of Credit Suisse Securities (USA) LLC for a period of 180 days after the date of this prospectus. However, in the event that either (1) during the last 17 days of the “lock-up” period, we release earnings results or material news or a material event relating to us occurs or (2) prior to the expiration of the “lock-up” period, we announce that we will release earnings results during the 16-day period beginning on the last day of the “lock-up” period, then in either case the expiration of the “lock-up” will be extended until the expiration of the 18-day period beginning on the date of the release of the earnings results or the occurrence of the material news or event, as applicable, unless Credit Suisse Securities (USA) LLC waives, in writing, such an extension.

Credit Suisse Securities (USA) LLC, in its sole discretion, may release the common stock and other securities subject to the lock-up agreements described above in whole or in part at any time. When determining whether or not to release the common stock and other securities from lock-up agreements, Credit Suisse Securities (USA) LLC will consider, among other factors, the holder’s reasons for requesting the release and the number of shares of common stock or other securities for which the release is being requested.

The underwriters have reserved for sale at the initial public offering price up to                 shares of the common stock for employees, directors and other persons associated with us who have expressed an interest in purchasing common stock in the offering. The number of shares available for sale to the general public in the offering will be reduced to the extent these persons purchase the reserved shares. Any reserved shares not so purchased will be offered by the underwriters to the general public on the same terms as the other shares.

We and the selling stockholders have agreed to indemnify the underwriters against liabilities under the Securities Act, or contribute to payments that the underwriters may be required to make in that respect.

We have applied to list the shares of our common stock on The NASDAQ Global Market under the symbol “FANG”.

In connection with the listing of our common stock on The NASDAQ Global Market, the underwriters will undertake to sell round lots of 100 shares or more to a minimum of 400 beneficial owners.

Prior to this offering, there has been no public market for our common stock. The initial public offering price for our common stock will be determined by negotiation between us, the selling stockholders and the underwriters. The principal factors to be considered in determining the initial public offering price include the following:

 

•

the general condition of the securities markets;

 

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•

market conditions for initial public offerings;

 

•

the market for securities of companies in businesses similar to ours;

 

•

the history and prospects for the industry in which we compete;

 

•

our past and present operations and earnings and our current financial position;

 

•

the history and prospects for our business;

 

•

an assessment of our management; and

 

•

other information included in this prospectus and otherwise available to the underwriters.

We cannot assure you that the initial public offering price will correspond to the price at which our common stock will trade in the public market subsequent to this offering or that an active trading market will develop and continue after this offering.

Certain of the underwriters and their respective affiliates have from time to time performed, and may in the future perform, various financial advisory, commercial banking and investment banking services for us and for our affiliates in the ordinary course of business for which they have received and would receive customary compensation.

In connection with the offering the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Exchange Act.

 

•

Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

 

•

Over-allotment involves sales by the underwriters of shares in excess of the number of shares the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of shares over-allotted by the underwriters is not greater than the number of shares that they may purchase in the over-allotment option. In a naked short position, the number of shares involved is greater than the number of shares in the over-allotment option. The underwriters may close out any covered short position by either exercising their over-allotment option and/or purchasing shares in the open market.

 

•

Syndicate covering transactions involve purchases of the common stock in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of shares to close out the short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through the over-allotment option. If the underwriters sell more shares than could be covered by the over-allotment option, a naked short position, the position can only be closed out by buying shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering.

 

•

Penalty bids permit the representative to reclaim a selling concession from a syndicate member when the common stock originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common stock or preventing or retarding a decline in the market price of the common stock. As a result the price of our common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NASDAQ Global Market or otherwise and, if commenced, may be discontinued at any time.

 

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A prospectus in electronic format may be made available on the web sites maintained by one or more of the underwriters, or selling group members, if any, participating in this offering and one or more of the underwriters participating in this offering may distribute prospectuses electronically. The representative may agree to allocate a number of shares to underwriters and selling group members for sale to their online brokerage account holders. Internet distributions will be allocated by the underwriters and selling group members that will make internet distributions on the same basis as other allocations.

European Economic Area

In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each such state being referred to herein as a Relevant Member State), each underwriter has represented and agreed that with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (each such date being referred to herein as a Relevant Implementation Date) it has not made and will not make an offer of shares to the public in that Relevant Member State prior to the publication of a prospectus in relation to the shares which has been approved by the competent authority in that Relevant Member State or, where appropriate, approved in another Relevant Member State and notified to the competent authority in that Relevant Member State, all in accordance with the Prospectus Directive, except that it may, with effect from and including the Relevant Implementation Date, make an offer of shares to the public in that Relevant Member State at any time:

(a) to legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities;

(b) to any legal entity which has two or more of (1) an average of at least 250 employees during the last financial year; (2) a total balance sheet of more than €43,000,000 and (3) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts;

(c) to fewer than 100 natural or legal persons (other than qualified investors as defined in the Prospectus Directive) subject to obtaining the prior consent of the representatives for any such offer; or

(d) in any other circumstances which do not require the publication by the Company of a prospectus pursuant to Article 3 of the Prospectus Directive.

For the purposes of this provision, the expression an “offer of shares to the public” in relation to any shares in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and the shares to be offered so as to enable an investor to decide to purchase or subscribe the shares, as the same may be varied in that Relevant Member State by any measure implementing the Prospectus Directive in that Relevant Member State and the expression Prospectus Directive means Directive 2003/71/EC and includes any relevant implementing measure in each Relevant Member State.

United Kingdom

Each underwriter has represented and agreed that:

(a)    it has only communicated or caused to be communicated and will only communicate or cause to be communicated an invitation or inducement to engage in investment activity (within the meaning of Section 21 of the Financial Services and Markets Act 2000, or the FSMA, received by it in connection with the issue or sale of the shares in circumstances in which Section 21(1) of the FSMA does not apply to the Company; and

(b)    it has complied and will comply with all applicable provisions of the FSMA with respect to anything done by it in relation to the shares in, from or otherwise involving the United Kingdom.

 

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Hong Kong

The shares may not be offered or sold by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap.32, Laws of Hong Kong), or (ii) to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap.571, Laws of Hong Kong) and any rules made thereunder, or (iii) in other circumstances which do not result in the document being a “prospectus” within the meaning of the Companies Ordinance (Cap.32, Laws of Hong Kong), and no advertisement, invitation or document relating to the shares may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to shares which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder.

Singapore

This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the shares may not be circulated or distributed, nor may the shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore, or the SFA, (ii) to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA.

Where the shares are subscribed or purchased under Section 275 by a relevant person which is: (a) a corporation (which is not an accredited investor) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or (b) a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary is an accredited investor, shares, debentures and units of shares and debentures of that corporation or the beneficiaries’ rights and interest in that trust shall not be transferable for 6 months after that corporation or that trust has acquired the shares under Section 275 except: (1) to an institutional investor under Section 274 of the SFA or to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA; (2) where no consideration is given for the transfer; or (3) by operation of law.

Japan

The securities have not been and will not be registered under the Financial Instruments and Exchange Law of Japan, or the Financial Instruments and Exchange Law, and each underwriter has agreed that it will not offer or sell any securities, directly or indirectly, in Japan or to, or for the benefit of, any resident of Japan (which term as used herein means any person resident in Japan, including any corporation or other entity organized under the laws of Japan), or to others for re-offering or resale, directly or indirectly, in Japan or to a resident of Japan, except pursuant to an exemption from the registration requirements of, and otherwise in compliance with, the Financial Instruments and Exchange Law and any other applicable laws, regulations and ministerial guidelines of Japan.

 

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LEGAL MATTERS

The validity of the shares of common stock that are offered hereby by us and the selling stockholders will be passed upon by Akin Gump Strauss Hauer  & Feld LLP. The underwriters have been represented by Latham & Watkins LLP, Houston, Texas.

EXPERTS

The audited financial statements included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the reports of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

Information referenced in this prospectus regarding our estimated quantities of oil and gas reserves and the discounted present value of future net cash flows therefrom is based upon estimates of such reserves and present values prepared by Ryder Scott Company L.P. as of December 31, 2011 and by Pinnacle Energy Services, LLC as of December 31, 2010 and 2009, each an independent petroleum engineering firm. Information referenced in this prospectus regarding estimated quantities of oil and gas reserves and the discounted present value of future net cash flows attributable to the Windsor UT properties and the properties subject to the Gulfport transaction is based upon estimates of such reserves and present values prepared in each case by Ryder Scott Company L.P. as of December  31, 2011.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 under the Securities Act covering the securities offered by this prospectus, which constitutes a part of that registration statement. Items included in the registration statement as Part II are omitted from this prospectus in accordance with the rules and regulations of the SEC. For further information about us and the common stock offered by this prospectus, reference is made to the registration statement and the exhibits filed with the registration statement. Statements contained in this prospectus and any prospectus supplement as to the contents of any contract or other document referred to are qualified by reference to each such contract or document filed as part of the registration statement. When we complete this offering, we will be required to file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read any materials we file with the SEC free of charge at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Copies of all or any part of these documents may be obtained from such office upon the payment of the fees prescribed by the SEC. The public may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the site is www.sec.gov. The registration statement, including all exhibits thereto and amendments thereof, has been filed electronically with the SEC.

 

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Appendix A

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a description of the meanings of some of the oil and natural gas industry terms used in this prospectus.

3-D seismic. Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.

Basin-centered gas. A regional abnormally-pressured, gas-saturated accumulation in low-permeability reservoirs.

Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this prospectus in reference to crude oil or other liquid hydrocarbons.

Bbls/d. Bbls per day.

BOE. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

BOE/d. BOE per day.

Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Coalbed methane (CBM). Natural gas formed as a byproduct of the coal formation process, which is trapped in coal seams and produced by non-traditional means.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

Deviated well. A well purposely deviated from the vertical using controlled angles to reach an objective location other than directly below the surface location.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

 

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Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Finding and Development Costs. Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.

Fracturing. The process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle with a specified interval.

MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.

MBOE. One thousand barrels of crude oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Mcf. Thousand cubic feet of natural gas.

Mcf/d. Mcf per day.

MMBtu. Million British Thermal Units.

MMcf. Million cubic feet of natural gas.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.

Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

PDP. Proved developed producing.

Play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

PUD. Proved undeveloped.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

 

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Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves. The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Stratigraphic play. An oil or natural gas formation contained within an area created by permeability and porosity changes characteristic of the alternating rock layer that result from the sedimentation process.

Structural play. An oil or natural gas formation contained within an area created by earth movements that deform or rupture (such as folding or faulting) rock strata.

Tight formation. A formation with low permeability that produces natural gas with very low flow rates for long periods of time.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

Workover. The repair or stimulation of an existing production well for the purpose of restoring, prolonging or enhancing the production of hydrocarbons.

 

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Appendix B

WINDSOR PERMIAN LLC

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold Interests

SEC Parameters

As of

December 31, 2011

 

		/s/ Don P. Griffin, P.E. Don P. Griffin, P.E. TBPE License No. 64150 Senior Vice President
		RYDER SCOTT COMPANY, L.P. TBPE Firm License No. F-1580		[SEAL]

 

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

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May 31, 2012

Windsor Permian LLC

500 West Texas, Suite 1210

Midland, Texas 79701

Gentlemen:

At your request, Ryder Scott Company (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold interests of Windsor Permian LLC (Windsor) as of December 31, 2011. This report supersedes our report of January 20, 2012 and reflects a revised drilling schedule. The subject properties are located in the state of Texas. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 20, 2012 and presented herein, was prepared for public disclosure in Windsor’s filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves of Windsor as of December 31, 2011.

The results of this study are summarized below.

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold Interests of Windsor

Permian LLC

As of December 31, 2011

 

		Proved
		Developed												Total Proved
		Producing				Non-Producing				Undeveloped
Net Remaining Reserves
Oil/Condensate – MBbl			3,494				311				12,912				16,717
Plant Products – MBbl			1,143				90				3,530				4,763
Gas – MMCF			4,799				388				14,432				19,619
MBOE			5,437				466				18,847				24,750
Income Data ($M)
Future Gross Revenue		$	386,409			$	33,732			$	1,383,373			$	1,803,514
Deductions			115,007				10,909				706,770				832,686
Future Net Income (FNI)		$	271,402			$	22,823			$	676,603			$	970,828
Discounted FNI @ 10%		$	147,447			$	12,090			$	187,482			$	347,019

 

SUITE 600, 1015 4TH STREET, S.W.		CALGARY, ALBERTA T2R 1J4		TEL (403) 262-2799		FAX (403) 262-2790
621 17TH STREET, SUITE 1550		DENVER, COLORADO 80293-1501		TEL (303) 623-9147		FAX (303) 623-4258

 

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The estimated reserves and future net income amounts presented in this report, as of December 31, 2011 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the un-weighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report.

Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (MBbl). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. The net remaining reserves are also shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. MBOE means thousands barrels of oil equivalent. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package Aries^TM System Petroleum Economic Evaluation Software, a copyrighted program of Halliburton. The program was used solely at the request of Windsor. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs and development costs. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

Liquid hydrocarbon reserves account for approximately 96.0 percent and gas reserves account for the remaining 4.0 percent of total future gross revenue from proved reserves.

 

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The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

 

		Discounted Future Net Income         As of December 31, 2011 ($M)
Discount Rate Percent		Total     Proved
5		$542,432
15		$240,230
20		$174,762
25		$131,473

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report. The proved developed non-producing reserves included herein consist of the shut-in category.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes included herein do not attribute gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Windsor’s request, this report addresses the proved reserves attributable to the properties evaluated herein.

 

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Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”

Reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Windsor’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of reserves presented herein were based upon a detailed study of the properties in which Windsor owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These

 

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analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods, analogy, or a combination of both methods. Approximately 85 percent of the proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of historical production and pressure data available through December, 2011 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Windsor and were considered sufficient for the purpose thereof. The remaining 15 percent of the proved reserves were estimated by analogy, or a combination of performance and analogy methods. The analogy method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

All proved developed non-producing and undeveloped reserves included herein were estimated by the analogy method.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates.

 

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Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Windsor has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Windsor with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Windsor. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Windsor. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

 

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Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month un-weighted arithmetic average as previously described.

As noted above, Windsor furnished us with the average prices in effect on December 31, 2011. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Windsor and were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Windsor to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves by reserve category for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

 

Geographic Area

Product

Price Reference

Avg Benchmark Prices

Avg Proved Realized Prices

North America

United States

Oil/Condensate

WTI Cushing

$

96.19/Bbl

$

93.09/Bbl

NGLs

WTI Cushing

$

61.97/Bbl

$

56.33/Bbl

Gas

Henry Hub

$

4.12/MMBTU

$

3.90/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

 

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Costs

Operating costs for the leases and wells in this report are based on the operating expense reports of Windsor and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Windsor. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by Windsor and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. Windsor’s estimates of zero abandonment costs after salvage value for onshore properties were used in this report. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for Windsor’s estimate.

The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with Windsor’s plans to develop these reserves as of December 31, 2011. The implementation of Windsor’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Windsor’s management. As the result of our inquiries during the course of preparing this report, Windsor has informed us that the development activities included herein have been subjected to and received the internal approvals required by Windsor’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Windsor. Additionally, Windsor has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by Windsor were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or

 

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Windsor Permian LLC

May 31, 2012

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a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Windsor. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Windsor.

We have provided Windsor with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Windsor and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

 

 

DPG/pl		[SEAL]

 

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Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Don P. Griffin was the primary technical person responsible for overseeing the estimate of the reserves, future production and income presented herein.

Mr. Griffin, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1981, is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Griffin served in a number of engineering positions with Amoco Production Company. For more information regarding Mr. Griffin’s geographic and job specific experience, please refer to the Ryder Scott Company website at http://www.ryderscott.com/Experience/Employees.php.

Mr. Griffin graduated with honors from Texas Tech University with a Bachelor of Science degree in Electrical Engineering in 1975 and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Griffin fulfills. Mr. Griffin attended an additional 15 hours of training during 2011 covering such topics as reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants.

Based on his educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Griffin has attained the professional qualifications as a Reserves Estimator and Reserves Auditor as set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

 

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PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

 

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Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves.    Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves.    Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

 

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PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

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RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by: SOCIETY OF

PETROLEUM ENGINEERS (SPE) WORLD

PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

 

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

 

(1)

completion intervals which are open at the time of the estimate, but which have not started producing;

 

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(2)

wells which were shut-in for market conditions or pipeline connections; or

 

(3)

wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

 

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Appendix C

WINDSOR UT, LLC

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold Interests

SEC Parameters

As of

December 31, 2011

 

/s/ Don P. Griffin, P.E.

 

Don P. Griffin, P.E.

TBPE License No. 64150

Senior Vice President

RYDER SCOTT COMPANY, L.P.

TBPE Firm License No. F-1580

[SEAL]

 

 

 

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May 31, 2012

Windsor UT, LLC

500 West Texas, Suite 1210

Midland, Texas 79701

Gentlemen:

At your request, Ryder Scott Company (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold interests of Windsor UT (Windsor) as of December 31, 2011. This report supersedes our report of January 20, 2012 and reflects a revised drilling schedule. The subject properties are located in the state of Texas. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 20, 2012 and presented herein, was prepared for public disclosure in Windsor’s filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves of Windsor as of December 31, 2011.

The results of this study are summarized below.

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold Interests of

Windsor UT, LLC

As of December 31, 2011

 

 

		Proved
		Developed								Undeveloped				Total     Proved
		Producing				Non-Producing
Net Remaining Reserves
Oil/Condensate – MBbl			109				34				1,240				1,383
Plant Products – MBbl			23				7				256				286
Gas – MMCF			76				23				834				933
MBOE			145				45				1,635				1,825
Income Data ($M)
Future Gross Revenue		$	11,199			$	3,512			$	126,439			$	141,150
Deductions			3,327				1,561				70,584				75,472
Future Net Income (FNI)		$	7,872			$	1,951			$	55,855			$	65,678
Discounted FNI @ 10%		$	4,449			$	829			$	12,315			$	17,593

 

SUITE 600, 1015 4TH STREET, S.W. 621 17TH STREET, SUITE 1550		CALGARY, ALBERTA T2R 1J4 DENVER, COLORADO 80293-1501		TEL (403) 262-2799 TEL (303) 623-9147		FAX (403) 262-2790 FAX (303) 623-4258

 

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The estimated reserves and future net income amounts presented in this report, as of December 31, 2011 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the un-weighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report.

Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (MBbl). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. The net remaining reserves are also shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. MBOE means thousands barrels of oil equivalent. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package Aries^TM System Petroleum Economic Evaluation Software, a copyrighted program of Halliburton. The program was used solely at the request of Windsor. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs and development

 

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costs. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income.

Liquid hydrocarbon reserves account for approximately 97.5 percent and gas reserves account for the remaining 2.5 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

 

		Discounted Future Net Income         As  of December 31, 2011 ($M)
Discount Rate             Percent		Total     Proved
5		$	32,102
15		$	10,095
20		$	5,763
25		$	3,080

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definitions as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report. The proved developed non-producing reserves included herein consist of the shut-in category.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes included herein do not attribute gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities

 

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determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Windsor’s request, this report addresses the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”

Reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Windsor’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

 

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The estimates of reserves presented herein were based upon a detailed study of the properties in which Windsor owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

 

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The proved reserves for the properties included herein were estimated by performance methods, analogy, or a combination of both methods. Approximately 85 percent of the proved producing reserves attributable to producing wells were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, which utilized extrapolations of historical production and pressure data available through December, 2011 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Windsor and were considered sufficient for the purpose thereof. The remaining 15 percent of the proved reserves were estimated by analogy, or a combination of performance and analogy methods. The analogy method was used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

All proved developed non-producing and undeveloped reserves included herein were estimated by the analogy method.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Windsor has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Windsor with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Windsor. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities

 

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and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Windsor. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month un-weighted arithmetic average as previously described.

As noted above, Windsor furnished us with the average prices in effect on December 31, 2011. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

 

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May 31, 2012

Page 8

 

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Windsor and were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Windsor to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves by reserve category for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

 

Geographic Area		Product		Price Reference		Avg Benchmark Prices		Avg Proved Realized Prices
North America
United     States		Oil/Condensate		WTI Cushing		$96.19/Bbl		$92.99/Bbl
		NGLs		WTI Cushing		$61.97/Bbl		$56.74/Bbl
				Henry Hub
		Gas				$4.12/MMBTU		$3.92/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report are based on the operating expense reports of Windsor and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Windsor. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by Windsor and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. Windsor’s estimates of zero abandonment costs

 

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May 31, 2012

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after salvage value for onshore properties were used in this report. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for Windsor’s estimate.

The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with Windsor’s plans to develop these reserves as of December 31, 2011. The implementation of Windsor’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Windsor’s management. As the result of our inquiries during the course of preparing this report, Windsor has informed us that the development activities included herein have been subjected to and received the internal approvals required by Windsor’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Windsor. Additionally, Windsor has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by Windsor were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Windsor. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

 

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May 31, 2012

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The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Windsor.

We have provided Windsor with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Windsor and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

/s/ Don P. Griffin, P.E.                            

Don P. Griffin, P.E.

TBPE License No. 64150

Senior Vice President

 

DPG/pl		[SEAL]

 

RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

 

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RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

 

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Don P. Griffin was the primary technical person responsible for overseeing the estimate of the reserves, future production and income presented herein.

Mr. Griffin, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1981, is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Griffin served in a number of engineering positions with Amoco Production Company. For more information regarding Mr. Griffin’s geographic and job specific experience, please refer to the Ryder Scott Company website at http://www.ryderscott.com/Experience/Employees.php.

Mr. Griffin graduated with honors from Texas Tech University with a Bachelor of Science degree in Electrical Engineering in 1975 and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Griffin fulfills. Mr. Griffin attended an additional 15 hours of training during 2011 covering such topics as reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants.

Based on his educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Griffin has attained the professional qualifications as a Reserves Estimator and Reserves Auditor as set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

 

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RYDER SCOTT COMPANY    PETROLEUM CONSULTANTS

 

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature

 

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of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves.    Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

 

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PROVED RESERVES (SEC DEFINITIONS) CONTINUED

 

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

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RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

 

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Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1)

completion intervals which are open at the time of the estimate, but which have not started producing;

(2)

wells which were shut-in for market conditions or pipeline connections; or

(3)

wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

 

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Appendix D

GULFPORT ENERGY CORPORATION

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold Interests

SEC Parameters

As of

December 31, 2011

 

		\s\ Don P. Griffin
		Don P. Griffin, P.E.
		TBPE License No. 64150
		Senior Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

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May 29, 2012

Gulfport Energy Corporation

14313 N. May, Suite 100

Oklahoma City, Oklahoma 73134

Gentlemen:

At your request, Ryder Scott Company (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold interests of Gulfport Energy Corporation (Gulfport) as of December 31, 2011. This report corrects a mis-statement in our January 13, 2012 letter concerning the geographical area of coverage. The subject properties are located in the state of Texas. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 6, 2012, and presented herein, was prepared for public disclosure by Gulfport in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves in Gulfport’s Permian Basin area as of December 31, 2011.

The results of this study are summarized below.

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold Interests of

Gulfport Energy Corporation

As of December 31, 2011

 

		Proved
		Developed												Total Proved
		Producing				Non-Producing				Undeveloped
Net Remaining Reserves
Oil/Condensate – Mbbl			1,853				244				5,989				8,086
Plant Products – Mbbl			660				46				2,085				2,791
Gas – MMCF			2,853				197				8,996				12,046
Income Data ($M)
Future Gross Revenue		$	210,025			$	24,859			$	675,799			$	910,683
Deductions			52,844				2,238				348,154				403,236
Future Net Income (FNI)		$	157,181			$	22,621			$	327,645			$	507,447
Discounted FNI @ 10%		$	84,900			$	14,551			$	102,837			$	202,288

 

SUITE 600, 1015 4TH STREET, S.W. CALGARY, ALBERTA T2R 1J4		TEL (403) 262-2799		FAX (403) 262-2790
621 17TH STREET, SUITE 1550    DENVER, COLORADO 80293-1501		TEL (303) 623-9147		FAX (303) 623-4258

 

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The estimated reserves and future net income amounts presented in this report, as of December 31, 2011, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report.

Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (Mbbl). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package Aries^TM System Petroleum Economic Evaluation Software, a copyrighted program of Halliburton. The program was used solely at the request of Gulfport. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, and development costs. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 94.9 percent and gas reserves account for the remaining 5.1 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

 

		Discounted Future Net Income ($M) As of December 31, 2011
Discount Rate Percent		Total Proved
5		$303,812
15		$144,573
20		$108,577
25		$  84,579

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

 

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The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report. The proved developed non-producing reserves included herein consist of the shut-in category.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes included herein do not attribute gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Gulfport’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. The proved reserves included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Gulfport’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Gulfport owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the

 

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Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods, analogy, or a combination of methods. Approximately 90 percent of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. These performance methods involved decline curve analysis which utilized extrapolations of historical production and pressure data available through October 2011 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Gulfport or obtained from public data sources and were considered sufficient for the purpose thereof. The remaining 10 percent of the proved producing reserves were estimated by analogy or a combination of performance and analogy. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

All of the proved developed non-producing and undeveloped reserves included herein were estimated by the analogy method. The data utilized from the analogues were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic

 

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producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Gulfport has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Gulfport with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, and development costs, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Gulfport. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Gulfport. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the

 

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contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

Gulfport furnished us with the above mentioned average prices in effect on December 31, 2011. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Gulfport. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Gulfport to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

 

Geographic Area

Product

Price Reference

Average Benchmark Prices

Average Realized Prices

North America

United States

Oil/Condensate

WTI Cushing

$

96.19/Bbl

$

93.11/Bbl

NGLs

WTI Cushing

$

96.19/Bbl

$

57.09/Bbl

Gas

Henry Hub — Colorado Interstate

$

4.12/MMBTU

$

4.04/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report are based on the operating expense reports of Gulfport and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Gulfport. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by Gulfport and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. Gulfport’s estimates of zero abandonment costs after salvage value for onshore properties were used in this report. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for Gulfport’s estimate.

 

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The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with Gulfport’s plans to develop these reserves as of December 31, 2011. The implementation of Gulfport’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Gulfport’s management. As the result of our inquiries during the course of preparing this report, Gulfport has informed us that the development activities included herein have been subjected to and received the internal approvals required by Gulfport’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Gulfport. Additionally, Gulfport has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by Gulfport were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Gulfport. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Gulfport.

We have provided Gulfport with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Gulfport and the original signed report letter, the original signed report letter shall control and supersede the digital version.

 

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The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

 

[SEAL]

DPG/pl

 

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Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Don P. Griffin was the primary technical person responsible for overseeing the estimate of the reserves, future production and income presented herein.

Mr. Griffin, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1981, is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Griffin served in a number of engineering positions with Amoco Production Company. For more information regarding Mr. Griffin’s geographic and job specific experience, please refer to the Ryder Scott Company website at http://www.ryderscott.com/Experience/Employees.php.

Mr. Griffin graduated with honors from Texas Tech University with a Bachelor of Science degree in Electrical Engineering in 1975 and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Griffin fulfills. As part of his 2009 continuing education hours, Mr. Griffin attended an internally presented 16 hours of formalized training relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Mr. Griffin attended an additional 15 hours of training during 2010 covering such topics as reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants.

Based on his educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Griffin has attained the professional qualifications as a Reserves Estimator and Reserves Auditor as set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

 

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PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

 

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Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

 

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(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

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RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

 

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Shut-In

Shut-in Reserves are expected to be recovered from:

 

(1)

completion intervals which are open at the time of the estimate, but which have not started producing;

 

(2)

wells which were shut-in for market conditions or pipeline connections; or

 

(3)

wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

 

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INDEX TO FINANCIAL STATEMENTS

 

Windsor Permian LLC and Subsidiaries
Report of Independent Registered Public Accounting Firm			F-2
Consolidated Balance Sheets as of December 31, 2011 and 2010			F-3
Consolidated Statements of Operations for the Years Ended December 31, 2011, 2010 and 2009			F-4
Consolidated Statement of Changes in Member’s Equity for the Years Ended December  31, 2009, 2010 and 2011			F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009			F-6
Notes to Consolidated Financial Statements			F-7
Consolidated Balance Sheets (Unaudited) as of March 31, 2012 and December 31, 2011			F-28
Consolidated Statements of Operations (Unaudited) for the Three Months Ended March 31, 2012 and  2011			F-29
Consolidated Statement of Changes in Member’s Equity (Unaudited) for the Three Months Ended March 31, 2012 and 2011			F-30
Consolidated Statements of Cash Flows (Unaudited) for the Three Months Ended March 31, 2012 and  2011			F-31
Notes to Consolidated Financial Statements (Unaudited)			F-32
Windsor UT LLC
Report of Independent Certified Public Accountants			F-50
Balance Sheets as of December 31, 2011 and 2010			F-51
Statements of Operations for the Year Ended December 31, 2011 and Period from Inception (April  28, 2010) to December 31, 2010			F-52
Statement of Changes in Member’s Equity for the Period From Inception (April 28, 2010) to December 31, 2010 and the Year Ended December 31, 2011			F-53
Statements of Cash Flows for the Year Ended December 31, 2011 and Period from Inception (April 28, 2010) to December 31, 2010			F-54
Notes to Financial Statements			F-55
Balance Sheets (Unaudited) as of March 31, 2012 and December 31, 2011			F-65
Statements of Operations (Unaudited) for the Three Months Ended March 31, 2012 and 2011			F-66
Statement of Changes in Member’s Equity (Unaudited) for the Three Months Ended March 31, 2012 and 2011			F-67
Statements of Cash Flows (Unaudited) for the Three Months Ended March 31, 2012 and 2011			F-68
Notes to Consolidated Financial Statements (Unaudited)			F-69
Statements of Revenues and Direct Operating Expenses of Certain Property Interests of Gulfport Energy Corporation
Report of Independent Certified Public Accountants			F-75
Statements of Revenues and Direct Operating Expenses for the Years Ended December 31, 2011 and  2010			F-76
Notes to Statements of Revenues and Direct Operating Expenses for the Years Ended December 31, 2011 and 2010			F-77
Statements of Revenues and Direct Operating Expenses (Unaudited) for the Three Months Ended March  31, 2012 and 2011			F-80
Notes to Statements of Revenues and Direct Operating Expenses (Unaudited) for the Three Months Ended March 31, 2012 and 2011			F-81

 

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Report of Independent Registered Public Accounting Firm

Members

Windsor Permian LLC

We have audited the accompanying consolidated balance sheets of Windsor Permian LLC and subsidiaries (collectively the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, changes in member’s equity, and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Windsor Permian LLC and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the financial statements, the Company adopted the new oil and gas reserve estimation and disclosure requirements as of December 31, 2009.

/s/ Grant Thornton LLP

Oklahoma City, Oklahoma

March 23, 2012

 

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Windsor Permian LLC and Subsidiaries

Consolidated Balance Sheets

 

		December 31,
		2011				2010
Assets
Current assets:
Cash and cash equivalents		$	6,802,389			$	4,089,745
Accounts receivable:
Joint interest and other			3,734,513				3,540,244
Oil and natural gas sales			838,791				305,500
Related party			13,122,589				8,342,033
Inventories			6,006,355				8,433,734
Prepaid expenses and other			428,202				326,148
Total current assets			30,932,839				25,037,404
Property and equipment
Oil and natural gas properties, at cost, based on the full cost method of accounting ($1,732,329 and $825,742 excluded from amortization at December 31, 2011 and December 31, 2010, respectively)			325,510,080				239,771,620
Other property and equipment			1,016,574				11,915,780
Accumulated depletion, depreciation, amortization and impairment			(119,500,035	)			(104,845,670	)
			207,026,619				146,841,730
Investments-equity method			10,309,668				—
Other assets			1,214,759				637,562
Total assets		$	249,483,885			$	172,516,696
Liabilities and Member’s Equity
Current liabilities:
Accounts payable trade		$	8,769,491			$	8,641,089
Accounts payable–related party			3,436,195				4,785,810
Accrued capital expenditures			13,922,932				5,387,746
Other accrued liabilities			4,804,069				696,583
Revenues and royalties payable			3,165,267				499,048
Derivative contracts			8,320,351				—
Total current liabilities			42,418,305				20,010,276
Note payable credit facility–long term			85,000,000				44,766,687
Derivative contracts			6,138,573				1,373,864
Asset retirement obligations			1,079,725				727,826
Total liabilities			134,636,603				66,878,653
Commitments and contingencies (Note 11)
Member’s equity			114,847,282				105,638,043
Total liabilities and member’s equity		$	249,483,885			$	172,516,696

See accompanying notes to consolidated financial statements.

 

F-3

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Table of Contents

Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Consolidated Statements of Operations

 

		Year Ended December 31,
		2011				2010				2009
Revenues:
Oil sales-related party		$	38,178,686			$	21,402,799			$	8,815,681
Oil sales			2,582,019				74,574				973,058
Natural gas sales			1,646,848				1,400,584				922,137
Natural gas liquid sales			4,773,249				3,563,970				2,005,135
Oil and natural gas services-related party			1,490,910				811,247				—
Total revenues			48,671,712				27,253,174				12,716,011
Costs and expenses:
Lease operating expenses			8,218,217				3,039,462				1,551,047
Lease operating expenses-related party			2,127,138				1,549,097				815,576
Production taxes-related party			1,759,601				993,383				406,627
Production taxes			574,252				353,496				256,441
Gathering and transportation			201,828				105,870				42,091
Oil and natural gas services			1,207,101				228,046				—
Oil and natural gas services –related party			525,791				583,201				—
Depreciation, depletion and amortization			15,402,826				8,145,143				3,215,891
General and administrative expenses-related party			3,160,512				2,656,278				4,632,671
General and administrative expenses			442,967				395,349				429,947
Asset retirement obligation accretion expense			63,259				37,856				27,934
Total costs and expenses			33,683,492				18,087,181				11,378,225
Income from operations			14,988,220				9,165,993				1,337,786
Other income (expense)
Interest income			11,197				34,474				35,075
Interest expense			(2,528,058	)			(836,265	)			(10,938	)
Loss on derivative contracts			(13,009,393	)			(147,983	)			(4,068,005	)
Loss from equity investment			(7,017	)			—				—
Total other expense, net			(15,533,271	)			(949,774	)			(4,043,868	)
Net income (loss)		$	(545,051	)		$	8,216,219			$	(2,706,082	)
Pro forma information-(unaudited)
Net income (loss) before income taxes, as reported		$	(545,051	)		$	8,216,219			$	(2,706,082	)
Pro forma provision (benefit) for income tax			—				—				—
Pro forma net (loss) income		$	(545,051	)		$	8,216,219			$	(2,706,082	)
Pro forma income (loss) per common share — basic and diluted		$
Weighted average pro forma shares outstanding — basic and diluted

See accompanying notes to consolidated financial statements.

 

F-4

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Table of Contents

Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Consolidated Statement of Changes in Member’s Equity

 

		Total member’s equity
Balance at January 1, 2009		$	70,615,293
Contributions			16,893,000
Distributions			(600,000	)
Net loss			(2,706,082	)
Balance at December 31, 2009			84,202,211
Contributions			18,798,613
Distributions			(5,579,000	)
Net income			8,216,219
Balance at December 31, 2010			105,638,043
Contributions			9,210,000
Equity based compensation			544,290
Net loss			(545,051	)
Balance at December 31, 2011		$	114,847,282

See accompanying notes to consolidated financial statements.

 

F-5

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Table of Contents

Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Consolidated Statements of Cash Flows

 

		Year Ended December 31,
		2011				2010				2009
Cash flows from operating activities:
Net income (loss)		$	(545,051	)		$	8,216,219			$	(2,706,082	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Asset retirement obligation accretion expense			63,259				37,856				27,934
Depreciation, depletion, and amortization			15,905,315				8,145,143				3,215,891
Amortization of debt issuance costs			250,010				163,297				10,937
Loss on derivative contracts			13,009,393				147,983				4,068,005
(Gain) loss on sale of assets			(22,942	)			(4,675	)			1,588
Equity-based compensation expense			544,290				—				—
Changes in operating assets and liabilities:
Accounts receivable			(1,085,025	)			(1,822,949	)			592,489
Accounts receivable-related party			(4,780,556	)			(6,793,208	)			(1,548,825	)
Inventories			(871,969	)			(4,896,909	)			83,048
Prepaid expenses and other			(201,732	)			(326,148	)			—
Accounts payable and accrued liabilities			2,656,836				1,952,645				(597,506	)
Accounts payable and accrued liabilities-related party			759,377				(408,892	)			(445,913	)
Revenues and royalties payable			2,666,219				499,048				—
Revenues and royalties payable-related party			2,036,770				266,414				—
Net cash provided by operating activities			30,384,194				5,175,824				2,701,566
Cash flows from investing activities:
Additions to oil and natural gas properties			(58,159,977	)			(7,623,975	)			(26,622,735	)
Additions to oil and natural gas properties-related party			(17,219,632	)			(34,849,118	)			—
Proceeds from sale of oil and natural gas properties			—				1,250,000				—
Purchase of other property and equipment			(7,064,972	)			(11,741,073	)			(8,856	)
Proceeds from sale of property and equipment			54,909				20,075				2,000
Settlement of non-hedge derivative instruments			(4,126,800	)			(3,962,440	)			(2,770,026	)
Receipt (payment) on derivative margins			4,202,467				3,771,890				(2,750,000	)
Deconsolidation of Bison			(9,536	)			—				—
Proceeds from sale of membership interest in equity investment			6,009,499				—				—
Net cash used in investing activities			(76,314,042	)			(53,134,641	)			(32,149,617	)
Cash flows from financing activities:
Borrowing on credit facility			40,233,313				61,066,687				7,650,000
Repayment on credit facility			—				(23,950,000	)			—
Debt issuance costs			(770,462	)			(718,046	)			(50,000	)
Initial public offering costs			(30,359	)			—				(43,750	)
Contributions by members			9,210,000				18,798,613				16,893,000
Distributions by members			—				(5,579,000	)			(600,000	)
Net cash provided by financing activities			48,642,492				49,618,254				23,849,250
Net increase (decrease) in cash and cash equivalents			2,712,644				1,659,437				(5,598,801	)
Cash and cash equivalents at beginning of period			4,089,745				2,430,308				8,029,109
Cash and cash equivalents at end of period		$	6,802,389			$	4,089,745			$	2,430,308
Supplemental cash flow information
Interest paid, net of capitalized interest		$	2,265,005			$	600,194			$	—
Asset retirement obligation incurred, including changes in estimate		$	288,640			$	208,083			$	79,666

See accompanying notes to consolidated financial statements.

 

F-6

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Table of Contents

Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements

1. Organization

Windsor Permian LLC (“Windsor”) is a limited liability company formed on October 23, 2007 to acquire, produce, develop and exploit oil and natural gas properties. As a limited liability company, the members of Windsor are not liable for the liabilities or other obligations of Windsor. Windsor is wholly owned by an investment fund which is controlled and managed by Wexford Capital LP (“Wexford”). Collectively, Windsor and its subsidiaries, Bison Drilling and Field Services LLC (formerly known as Windsor Drilling LLC) through March 31, 2011, and West Texas Field Services LLC, are referred to in these financial statements as the “Company”.

The Company is engaged in the acquisition, exploitation, development and production of oil and natural gas properties and related sale of oil, natural gas and natural gas liquids. The Company’s reserves are located in the Southern region of the United States. The Company’s results of operations are largely dependent on the difference between the prices received for its oil, natural gas and natural gas liquids and the cost to find, develop, produce and market such resources. Oil and natural gas prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond the Company’s control. These factors include worldwide political instability, quantity of natural gas in storage, foreign supply of oil and natural gas, the price of foreign imports, the level of consumer demand and the price of available alternative fuels, among others.

2. Summary of Significant Accounting Policies

The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. The consolidated financial statements include the accounts of Windsor and its wholly owned subsidiaries, except for the accounts of Bison Drilling and Field Services LLC, which has been excluded from the Company’s consolidated financial statements effective March 31, 2011 (Note 5). All significant intercompany accounts and transactions have been eliminated in consolidation.

Use of estimates

Certain amounts included in or affecting the Company’s consolidated financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates.

The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved reserve quantities and related estimates of the present value of future net revenues, the carrying value of oil and gas properties and asset retirement obligations.

Cash and Cash Equivalents

The Company considers all highly liquid debt instruments purchased with a maturity of three months or less and money market funds to be cash equivalents. The Company utilizes bank deposit accounts which periodically sweep available cash into uninsured short-term investment securities. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts.

 

F-7

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Table of Contents

Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

Accounts Receivable

Accounts receivable consist of receivables from joint interest owners on properties the Company operates and oil and natural gas production delivered to purchasers. The purchasers remit payment for production directly to the Company. As discussed in Note 10, through February 26, 2010 a significant portion of the Company’s oil and natural gas properties were contractually operated by an affiliate. Prior to February 26, 2010, purchasers remitted payment for production to the affiliated operator and the affiliated operator, in turn, remitted payment to the Company. Most payments are received within three months after the production date.

Accounts receivable are stated at amounts due from joint interest owners or purchasers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2011, 2010 and 2009.

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, derivatives and note payable. The carrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of the instruments. The fair value of the revolving credit facility approximates its carrying value based on the borrowing rates currently available to the Company for bank loans with similar terms and maturities. Derivatives are recorded at fair value (see Note 9).

Oil and Natural Gas Properties

The Company accounts for its oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized. General and administrative costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All general and administrative costs not directly associated with exploration and development activities are charged to expense as they are incurred. Capitalized general and administrative costs were $871,036 for the year ended December 31, 2011, and no amounts were capitalized for the years ended December 31, 2010 and 2009. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Any income from services provided by subsidiaries to working interest owners of properties in which the Company also owns an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties proportionate to the Company’s investment in the subsidiary (see Note 5). Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves. The average depletion rate per barrel equivalent unit of production was $25.40, $17.78 and $11.21 for the years ended December 31, 2011, 2010 and 2009, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties was $15,178,366, $7,373,126 and $3,155,084 for the years ended December 31, 2011, 2010 and 2009, respectively.

 

F-8

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Table of Contents

Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment exceed the discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense.

Beginning December 31, 2009, the Company used the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date in estimating discounted future net revenues. No impairment on proved oil and natural gas properties was recorded for the years ended December 31, 2011, 2010 or 2009.

Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company assesses all items classified as unevaluated property on an annual basis for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within three years.

Other Property and Equipment

Other property and equipment is recorded at cost. The Company expenses maintenance and repairs in the period incurred. Upon retirements or disposition of assets, the cost and related accumulated depreciation are removed from the consolidated balance sheet with the resulting gains or losses, if any, reflected in operations. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years. Depreciation expense was $726,949, $772,017 and $60,807 for the years ended December 31, 2011, 2010 and 2009, respectively.

Impairment of Long-Lived Assets

Other long-lived assets, drilling rigs and related equipment used in operations are reviewed whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss is recognized only if the carrying amount of a long-lived asset is not recoverable from its estimated future undiscounted cash flows. An impairment loss is the difference between the carrying amount and fair value of the asset. The Company had no such impairment losses for the years ended December 31, 2011, 2010 or 2009.

Capitalized Interest

The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Capitalized interest cannot exceed gross interest expense. During the years ended December 31, 2010 and 2009, the Company capitalized interest expense totaling $150,280 and $54,322, respectively. During the year ended December 31, 2011, the Company did not capitalize any interest expense.

 

F-9

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Table of Contents

Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

Inventories

Inventories are stated at the lower of cost or market and consist of the following:

 

		December 31,
		2011				2010
Tubular goods and equipment		$	5,630,208			$	8,269,628
Crude oil			376,147				164,106
		$	6,006,355			$	8,433,734

The Company’s tubular goods and equipment is primarily comprised of oil and gas drilling or repair items such as tubing, casing and pumping units. The inventory is primarily acquired for use in future drilling or repair operations and is carried at lower of cost or market. “Market”, in the context of inventory valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint accounts under joint operating agreements to which the Company is a party. As of December 31, 2011, the Company estimated that all of its tubular goods and equipment will be utilized within one year. The total inventory includes tubular goods in transit of $1,093,708 and $1,377,567 at December 31, 2011 and 2010, respectively. Some of the tubular and casing pipe has been purchased, at cost, from an affiliated company. The Company owed this affiliate $68,875 at December 31, 2010, and did not have an outstanding balance with the affiliated company at December 31, 2011. This amount is included in accounts payable-related party in the consolidated balance sheets.

Debt issuance costs

The Company amortizes debt issuance costs related to its credit facility as interest expense over the scheduled maturity period of the debt. Unamortized debt issuance costs were $1,167,621 and $637,562 as of December 31, 2011 and 2010, respectively. The Company includes the unamortized costs in other assets in its consolidated balance sheets.

Revenue and Royalties Payable

For certain oil and natural gas properties, where the Company serves as operator, the Company receives production proceeds from the purchaser and further distributes such amounts to other revenue and royalty owners. Production proceeds applicable to other revenue and royalty owners are reflected as revenue and royalties payable in the accompanying consolidated balance sheets. The Company recognizes revenue for only its net revenue interest in oil and natural gas properties.

Revenue Recognition

Oil and natural gas revenues are recorded when title passes to the purchaser, net of royalty interests, discounts and allowances, as applicable. The Company accounts for oil and natural gas production imbalances using the sales method, whereby a liability is recorded when the Company’s overtake volumes exceed its estimated remaining recoverable reserves. No receivables are recorded for those wells where the Company has taken less than its ownership share of production. The Company did not have any gas imbalances as of December 31, 2011 and 2010. Revenues from oil and natural gas services are recognized as services are provided.

Investments

Equity investments in which the Company exercises significant influence but does not control, are accounted for using the equity method. Under the equity method, generally the Company’s share of investees’ earnings or loss

 

F-10

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Table of Contents

Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

is recognized in the statement of operations. However, because substantially all of Bison’s earnings are generated by performing services on properties owned and operated by the Company, the Company’s share of Bison’s earnings has not been recognized but has been credited to oil and gas properties. The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company would recognize an impairment provision. There was no impairment for the Company’s equity investments at December 31, 2011. For additional information on the Company’s investments, see Note 5.

Accounting for Equity-Based Compensation

The Company accounts for equity-based compensation in accordance with the provisions of FASB ASC Topic 718, “Compensation—Stock Compensation” (“FASB ASC 718”). FASB ASC 718 requires equity-based payments to employees to be recognized as expense over the applicable service period based on the fair value of the award on the date of grant.

Concentrations

The Company is subject to risk resulting from the concentration of its crude oil and natural gas sales and receivables with several significant purchasers. For the years ended December 31, 2011 and 2010, Windsor Midstream LLC, an entity controlled by Wexford, our equity sponsor, accounted for 78% and 81% of our revenue, respectively. For the year ended December 31, 2009, two purchasers accounted for more than 10% of our revenue: Windsor Midstream LLC (68.3%) and DCP Midstream, LP (14.8%). The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Commodity Risk Management

The Company has used energy derivatives for the purpose of mitigating the risk resulting from fluctuations in the market price of crude oil. The Company recognizes all of its derivative instruments as either assets or liabilities at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and further on the type of hedging relationship. For those derivative instruments that are designated and qualify as hedging instruments, the Company designates the hedging instrument, based on the exposure being hedged, as either a fair value hedge or a cash flow hedge. Changes in the fair value of instruments designated as a fair value hedge offset changes in the fair value of the hedged item and changes in the fair value of instruments designated as cash flow hedges are shown in accumulated other comprehensive income until the hedged item is recognized in earnings. For derivative instruments not designated as hedging instruments, the unrealized gain or loss on the change in fair value of these instruments are recognized in earnings during the period of change. None of the Company’s derivatives were designated as hedging instruments during the years ended December 31, 2011, 2010 and 2009.

Environmental Compliance and Remediation

Environmental compliance and remediation costs, including ongoing maintenance and monitoring, are expensed as incurred. Liabilities are accrued when environmental assessments and remediation are probable, and the costs can be reasonably estimated.

Income Taxes

The operations of the Company, as limited liability companies, are not subject to federal income taxes. As appropriate, the taxable income or loss applicable to those operations is included in the federal income tax returns

 

F-11

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Table of Contents

Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

of the respective owners and no income tax effect is included in the accompanying consolidated financial statements. The Company is subject to margin tax in the state of Texas. During the years ended December 31, 2011, 2010 and 2009, there was no margin tax expense. The Company’s 2008, 2009 and 2010 federal income tax and state margin tax returns remain open to examination by tax authorities. As of December 31, 2011 and 2010, the Company has no unrecognized tax benefits that would have a material impact on the effective rate. The Company is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2011, 2010 and 2009, there was no interest or penalties associated with uncertain tax positions in the Company’s consolidated financial statements.

Unaudited Pro Forma Income Taxes and Earnings Per Share

Prior to the completion of a proposed 2012 initial public offering of common stock (“IPO”) by Diamondback Energy, Inc. (“Diamondback”), all the equity interests in Windsor will be contributed to Diamondback and Windsor will become a wholly-owned subsidiary of Diamondback (“Proposed Contribution Transaction”). Diamondback, a holding company formed on December 30, 2011 which will not conduct any material business operations prior to the Proposed Contribution Transaction, is a C-Corp under the Internal Revenue Code and is subject to income taxes. Accordingly, the Company computed a pro forma income tax provision as if the Company were a C-Corp for all periods presented. The pro forma tax provision has been calculated at a rate based upon a federal corporate level tax rate and a state tax rate, net of federal benefit, incorporating permanent differences. However, on a pro forma basis, management has determined that any net deferred income tax asset would not be realizable; therefore, tax expense would be zero for all periods. Additionally, upon Windsor becoming a subsidiary of Diamondback, the Company will establish a net deferred tax liability for differences between the tax and book basis of the Company’s assets and liabilities, and record a corresponding “first day” tax expense to net income from continuing operations. On a pro forma basis, at December 31, 2011 the amount of this charge would have been approximately $26.2 million.

Also, upon completion of the Proposed Contribution Transaction, the Company will present pro forma earnings per share for the most recent period. Pro forma basic and diluted income per share will be computed by dividing net income attributable to the Company by the number of shares of common stock outstanding as if the shares of Diamondback issued in the Proposed Contribution Transaction were issued and outstanding for the year ended December 31, 2011.

Recently issued accounting standards

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS,” which provides a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between U.S. GAAP and International Financial Reporting Standards. This new guidance changes some fair value measurement principles and disclosure requirements, but does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. The update is effective for annual periods beginning after December 15, 2011. The adoption of this guidance will not have a significant impact on our financial position, results of operations or cash flow.

In June 2011, the FASB issued Accounting Standards Update No. 2011-05, “Comprehensive Income: Presentation of Comprehensive Income,” which provides amendments to FASB ASC Topic 220, “Comprehensive Income” (“FASB ASC 220”). The purpose of the amendments in this update is to provide a

 

F-12

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Table of Contents

Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

more consistent method of presenting non-owner transactions that affect an entity’s equity. The amendments eliminate the option to report other comprehensive income and its components in the statement of changes in equity and require an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. In December 2011, the FASB issued Accounting Standards Update 2011-12 which defers the requirement in Accounting Standards Update 2011-05 that companies present reclassification adjustments for each component of accumulated other comprehensive income in both net income and other comprehensive income on the face of the financial statements. Both amendments are effective for interim and annual periods beginning after December 15, 2011 and should be applied retrospectively. The adoption of this guidance will not have a significant impact on our financial position, results of operations or cash flow.

3. Property and Equipment

Property and equipment includes the following:

 

		December 31,
		2011				2010
Oil and natural gas properties:
Subject to depletion		$	323,777,751			$	238,945,878
Not subject to depletion-acquisition costs
Incurred in 2011			1,199,679				—
Incurred in 2010			—				293,092
Incurred in 2009			532,650				532,650
Total not subject to depletion			1,732,329				825,742
Gross oil and natural gas properties			325,510,080				239,771,620
Less accumulated depreciation, depletion, amortization and impairment			(119,167,476	)			(103,989,110	)
Oil and natural gas properties, net			206,342,604				135,782,510
Drilling rigs			—				7,622,586
Workover rigs and related equipment			—				3,304,577
Other property and equipment			1,016,574				988,617
Less accumulated depreciation			(332,559	)			(856,560	)
Other property and equipment, net			684,015				11,059,220
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment		$	207,026,619			$	146,841,730

4. Asset Retirement Obligations

The Company measures the future cost to retire its tangible long-lived assets and recognizes such cost as a liability in accordance with ASC Topic 410, Asset Retirement and Environmental Obligations (“ASC Topic 410”), which provides accounting and reporting guidance for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset.

 

F-13

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Table of Contents

Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

ASC Topic 410 requires companies to record a liability relating to the retirement and removal of assets used in their businesses. For the Company, asset retirement obligations represent the future abandonment costs of tangible assets, namely wells. ASC Topic 410 requires that the fair value of a liability for an asset’s retirement obligation be recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and that the corresponding cost be capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, the difference is recorded in oil and natural gas properties.

A reconciliation of the asset retirement obligation is as follows:

 

		Year Ended December 31,
		2011				2010				2009
Asset retirement obligation, beginning of period		$	727,826			$	481,887			$	374,287
Additional liability incurred			288,640				208,083				79,666
Accretion expense			63,259				37,856				27,934
Asset retirement obligation, end of period			1,079,725				727,826				481,887
Less current portion			—				—				—
Asset retirement obligations - long-term		$	1,079,725			$	727,826			$	481,887

5. Equity Method Investments

Bison Drilling and Field Services LLC

The Company held a wholly owned subsidiary, Bison Drilling and Field Services LLC (“Bison”), formerly known as Windsor Drilling LLC, formed on November 15, 2010. In addition, the Company also held a wholly owned subsidiary, West Texas Field Services LLC, formed on March 2, 2010 which, on January 1, 2011, contributed all of its assets and liabilities to Bison. Bison owns and operates four drilling rigs and various oil and gas well servicing equipment.

Beginning on March 31, 2011, various related party investors contributed capital to Bison diluting the Company’s ownership interest. The Company assessed its ability to exercise financial control over Bison and based on the results of its assessment, the Company concluded it maintained significant influence but it no longer had the ability to exercise control over Bison. The Company deconsolidated Bison for financial reporting purposes as of March 31, 2011 and the previously consolidated amounts were removed from the consolidated balance sheet and reflected as an equity method investment. The Company now reflects its investment in Bison on the equity method basis of accounting. The Company eliminates any intercompany profits or losses in relation to its continuing involvement with Bison, proportionate to its equity interest.

An entity is required to deconsolidate a subsidiary when the entity ceases to have a controlling financial interest in the subsidiary. Upon deconsolidation of a subsidiary, an entity recognizes a gain or loss on the transaction and measures any retained investment in the subsidiary at fair value. The gain or loss includes any gain or loss associated with the difference between the fair value of the retained investment in the subsidiary and its carrying amount at the date the subsidiary is deconsolidated.

The Company internally reviewed the balance sheet of Bison to determine its fair value. At the time of the transaction Bison was still a recently formed company and had not yet built value in its operations. Bison’s assets consisted primarily of four recently purchased drilling rigs. Two of the drilling rigs were purchased at market

 

F-14

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Table of Contents

Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

price from a third party in December 2010 and the second two were purchased from the same third party in April 2011. The Company also reviewed pricing of similar rigs in the market through retail and auction transactions. Because the rigs had just recently been purchased and this purchase price was in line with other outside transactions, the Company determined that Bison’s book value equaled fair value. There was no gain or loss recorded and the retained investment was recorded at fair value which equaled book value.

In September 2011, the Company completed the sale of 25% of its membership interest in Bison to a related party. The Company internally reviewed the fair value of Bison and, because the effective date of this transaction was May 1, 2011 and was within thirty days of the above valuation, the Company concluded the value of Bison had not changed. The Company determined that fair value equaled book value at the date of this transaction. There was no gain or loss recorded and the retained investment was recorded at fair value which equaled book value.

The Company has a 27.2% ownership in Bison at December 31, 2011. As of December 31, 2011, the Company’s investment in Bison is reflected as a non-current asset of $6,172,480.

The table below summarizes financial information for Bison as of December 31, 2011:

 

		December 31, 2011
Current assets		$	4,438,458
Property and equipment, net			21,707,528
Other assets			880,213
Current liabilities			2,418,902
Equity			24,607,297

Muskie Holdings LLC

During 2011, the Company paid approximately $4,200,000 for land and various other capital items related to the land. On October 7, 2011, the Company contributed these assets to a newly formed entity, Muskie Holdings LLC, a Delaware limited liability company, for a 48.6% equity interest. Through additional contributions to Muskie from a related party and various Wexford portfolio companies, it is expected that the Company’s interest in Muskie will decrease through 2012 to approximately 13%. Muskie generated a loss in 2011 and the Company has recorded its share of this loss. As of December 31, 2011, the Company’s investment in Muskie is reflected as a non-current asset of $4,137,188.

The table below summarizes financial information for Muskie as of December 31, 2011:

 

		December 31, 2011
Current assets		$	994,166
Property and equipment, net			7,584,779
Current liabilities			26,816
Equity			8,552,129

 

F-15

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Table of Contents

Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

6. Revolving Bank Credit Facility

Credit Facility-BNP Paribus

On October 15, 2010, the Company executed a secured loan agreement with BNP Paribas (“BNP”) as the administrative agent, sole book runner and lead arranger. The loan agreement originally provided for a maximum principal amount of $100 million and was increased to $250 million through an amendment dated December 30, 2011. The loan agreement is subject to a collateral borrowing base calculation which is based on the Company’s oil and natural gas reserves (the “borrowing base”). The loan bears interest at a rate elected by the Company that is based on the prime, LIBOR or federal funds rate plus margins ranging from 1.25% to 3.00% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base.

Principal is payable voluntarily by the Company or is required to be paid (i) if the loan amount exceeds the borrowing base; (ii) if the lender elects to require periodic payments as a part of a borrowing base re-determination; and (iii) at the maturity date of October 15, 2014. The Company is obligated to pay, quarterly, a commitment fee equal to 0.5% per year of the unused portion of the borrowing base. The loan is secured by substantially all of the Company’s assets. The borrowing base is re-determined semi-annually with effective dates of April 1st and October 1st (a “scheduled redetermination”). In addition, the Company may request an additional three redeterminations of the borrowing base between scheduled redeterminations. The borrowing base was $45 million at December 31, 2010. The borrowing base increased throughout 2011 through various redeterminations and at December 31, 2011 the borrowing base was $100 million. The current lenders and their percentage commitments in the reserve-based credit facility are BNP (45%), Amegy Bank of Texas (25%), US Bancorp (25%) and West Texas National Bank (5%).

As of December 31, 2011 and 2010, the Company had outstanding borrowings of $85,000,000 and $44,766,687, respectively. The credit facility bears a weighted average interest rate of 3.3% and 3.5% as of December 31, 2011 and 2010, respectively.

The agreement contains various affirmative and restrictive covenants. These covenants, among other things, prohibit additional indebtedness, sales of assets, mergers and consolidations, dividends and distributions, and changes in management and require the maintenance of various financial ratios defined below.

 

Financial Covenant		Required Ratio
Ratio of EBITDAX to interest expense, as defined in the credit agreement		Not less than 2.5 to 1.0
Ratio of total debt to EBITDAX		Not greater than 3.5 to 1.0
Current ratio, as defined in the credit agreement		Not less than 1.0 to 1.0

As of December 31, 2011 and 2010, the Company was in compliance with all financial covenants under the revolving bank credit facility. The lenders may accelerate all of the indebtedness under the revolving bank credit facility upon the occurrence of any event of default unless the Company cures any such default within any applicable grace period. For payments of principal and interest under the revolving bank credit facility, the Company generally has a three business day grace period, and a 30-day cure period for most covenant defaults, but not for defaults of certain specific covenants, including the financial covenants and negative covenants.

Credit Facility-Bank of Oklahoma, N.A.

On September 17, 2009, the Company entered into a revolving credit facility with the Bank of Oklahoma, N.A. (“BOK”). This revolving credit facility was repaid and closed in October 2010 with borrowings from the BNP revolving credit facility. The BOK revolving credit facility had a maximum principal amount of $50 million; subject to a collateral borrowing base calculation, which was based on the underlying reserve value of the oil and natural gas properties securing the credit facility and outstanding letters of credit.

 

F-16

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Table of Contents

Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

7. Derivatives

The Company has used price swap derivatives to reduce price volatility associated with certain of its oil sales. In these swaps, the Company receives the fixed price per the contract and pays a floating market price to the counterparty based on New York Mercantile Exchange Light Sweet Crude Oil pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. The counterparties to the Company’s derivative contracts are BNP Paribas (“BNP”) and Hess Corporation (“Hess”), who the Company believes are acceptable credit risks.

All derivative financial instruments are recorded on the consolidated balance sheets at fair value. The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity.

On October 4, 2011, in order to lock-in prices on the anticipated base level of production, while at the same time providing downside protection for the Borrowing Base, the Company executed with BNP, West Texas Intermediate light sweet crude oil swaps on the NYMEX for calendar year 2012 and 2013 of one thousand barrels per day priced at $78.50 and $80.55, respectively.

Set forth below are the summarized amounts, terms and fair values of outstanding instruments held as of December 31, 2011.

 

Description and Production Period		Volume (Bbls)				Original Strike Price (per Bbl)				December 31, 2011
										Fair Value Liability
Crude Oil Swaps:
January – November 2012			335,000			$	78.50			$	6,833,265
December 2012			31,000			$	78.50				594,223
January – December 2013			365,000			$	80.55				5,544,350

The Company enters into counter-swaps from time to time for the purpose of locking-in the value of a swap. Under the counter-swap, the Company receives a floating price for the hedged commodity and pays a fixed price to the counterparty. The counter-swap is effective in locking-in the value of a swap since subsequent changes in the market value of the swap are entirely offset by subsequent changes in the market value of the counter-swap.

In December 2007, the Company placed a swap contract with Hess covering 1,680,000 Bbls of crude oil for the period from January 2008 to December 2012 at various fixed prices. In April 2008, the Company entered into a series of counter-swaps to lock-in the value of certain of these swaps settling 1,188,000 Bbls of crude oil swaps. In June 2009, the Company entered into an additional series of counter-swaps to lock-in the value of the remaining swaps settling 324,000 Bbls of crude oil swaps.

 

F-17

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Table of Contents

Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the April 2008 settlements as of December 31, 2011 and 2010, respectively.

 

Description and Production Period		Volume (Bbls)				Original Strike Price (per Bbl)				Lock-in Price (per Bbl)				December 31,
														2011				2010
														Fair Value Liability				Fair Value Liability
Crude Oil Swaps:
December 2010			22,000			$	82.80			$	99.45–103.20			$	—			$	392,462
January – November 2011			180,000				82.90				98.50–102.20				—				4,159,695
December 2011			90,000				82.90				98.50–102.20				378,750				377,314
January – December 2012			270,000				85.07				98.25–101.80				3,876,959				3,844,101

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the June 2009 settlements as of December 31, 2011 and 2010, respectively.

 

Description and Production Period		Volume (Bbls)				Original Strike Price (per Bbl)				Lock-in Price (per Bbl)				December 31,
														2011				2010
														Fair Value Asset				Fair Value Asset
Crude Oil Swaps:
December 2010			8,000				82.80				75.00			$	—			$	62,400
January – November 2011			82,500				82.90				78.42				—				369,205
December 2011			7,500				82.90				78.42				33,600				33,503
January – December 2012			90,000				85.07				80.52				409,380				406,489

None of the Company’s derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following summarizes the loss on derivative contracts included in the consolidated statements of operations:

 

		Years Ended December 31,
		2011				2010				2009
Unrealized loss on open non-hedge derivative instruments		$	12,971,838			$	—			$	—
Unrealized loss on locked-in non-hedge derivative instruments			—				—				1,297,979
Loss on settlement of non-hedge derivative instruments			37,555				147,983				2,770,026
Loss on derivative contracts		$	13,009,393			$	147,983			$	4,068,005

The Company is required to provide margin deposits to Hess whenever its unrealized losses exceed predetermined credit limits. The Company had a margin deposit held by Hess of $2,325,643 and $6,528,111 as of December 31, 2011 and 2010, respectively, which earns interest that is remitted to the Company. As the Company has a master netting agreement with Hess, the Company has offset this margin deposit against its derivative positions.

 

F-18

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Table of Contents

Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

8. Equity-Based Compensation

During the year ended December 31, 2011, the Company granted to its executive officers options to acquire membership interests in the Company. Such options vest in four equal annual installments commencing on the first anniversary of the date of grant and are exercisable for five years from the date of grant. Generally, in the event more than 50% of the combined voting power of the Company is not owned by Wexford or its affiliates and there is a material change in the terms of the option holder’s employment, the options will vest immediately. Summarized below are the grant dates with the total exercise prices and total fair values of the underlying options:

 

Grants Made During the Months Ended		Membership Interest Granted				Exercise Price				Fair Value at Date of Grant
April 2011			1.00	%		$	3,600,000			$	1,452,851
August 2011			1.20	%			6,000,000				1,383,976
September 2011			1.25	%			5,900,000				1,532,612
November 2011			0.25	%			1,250,000				288,328
			3.70	%		$	16,750,000			$	4,657,767

At December 31, 2011, for outstanding options, the intrinsic value was $112,500 and the weighted-average remaining contractual terms were 4.6 years. Also, at December 31, 2011, no options were exercisable.

The Company accounts for such options issued using a fair-value-based method calculated on the grant-date of the award. The resulting cost is recognized on a straight-line basis over the vesting period of the entire option.

The fair value of the options issued was estimated using the Black-Scholes option-pricing model. One of the inputs to this model is the estimate of the fair value of the underlying membership interest on the date of grant. The other inputs include an estimate of the expected volatility of the membership interest, an option’s expected term, the risk-free interest rate over the option’s expected term, the option’s exercise price, and the Company’s expectations regarding dividends.

The Company does not have a history of market prices for its membership interests because such interests are not publicly traded. The expected volatility was determined using the historical volatility for a peer group of companies. The expected term for options issued was determined based on the contractual term of the awards. The weighted-average risk-free interest rate was based on the daily U.S. treasury yield curve rate whose term was consistent with the expected life of the options. The Company does not anticipate paying cash dividends; therefore, the expected dividend yield was assumed to be zero.

A summary of the significant assumptions used to estimate the fair value of the options to acquire membership interests during the year ended December 31, 2011 was as follows:

 

		Year Ended December 31, 2011
Expected term			5 years
Risk-free interest rate			0.96	%
Expected volatility			45.50	%
Expected dividend yield			0.00	%

As of December 31, 2011, the Company assumed no annual forfeiture rate because of its lack of turnover and lack of history for this type of award. The Company will continue to evaluate the appropriateness of the forfeiture rate based on actual forfeiture experience, analysis of employee turnover behavior, and other factors.

 

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Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

Changes in the estimated forfeiture rate can have a significant effect on reported equity-based compensation expense, because the cumulative effect of adjusting the rate for all expense amortization is recognized in the period the forfeiture estimate is changed.

Equity-based compensation expense recorded for the year ended December 31, 2011 was $544,290. The unrecognized equity-based compensation expense as of December 31, 2011 was $4,113,477 related to these awards which is expected to be recognized over a weighted-average period of 3.6 years. No equity-based compensation expense was recorded for the years ended December 31, 2010 and 2009 as the Company had not historically issued equity-based compensation awards.

9. Fair Value Measurements

The Company measures and discloses fair value in accordance with ASC Topic 820, Fair Value Measurements and Disclosures (“ASC Topic 820”). Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.

ASC Topic 820 describes a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities.

The three levels of the fair value hierarchy defined by ASC Topic 820 are as follows:

Level 1—Pricing inputs include quoted prices available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, marketable securities and listed equities.

Level 2—Pricing inputs include quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Level 2 instruments primarily include non-exchange traded derivatives such as over-the-counter commodity price swaps, basis swaps, investments and interest rate swaps. The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The Company utilizes its counterparties’ valuations to assess the reasonableness of its prices and valuation techniques.

Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

 

F-20

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Table of Contents

Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2011 and 2010.

 

		Quoted Prices in Active Markets Level 1				Significant Other Observable Inputs Level 2				Significant Unobservable Inputs Level 3				Cash Collateral(1)				Net Fair Value
Financial Liabilities
		December 31, 2011
Derivative contracts		$	—			$	16,784,567			$	—			$	(2,325,643	)		$	14,458,924
		December 31, 2010
Derivative contracts		$	—			$	7,901,975			$	—			$	(6,528,111	)		$	1,373,864

 

(1)	Represents the impact of netting cash collateral with a counterparty with which the right of offset exists.

Level 2 Fair Value Measurements

Derivative contracts-The fair values of the Company’s crude oil swaps are measured internally using established index prices and other sources. These are based upon, among other things, futures prices and time to maturity.

Asset Retirement and Environmental Obligations

The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410, “Asset Retirement and Environmental Obligations” (“FASB ASC 410”). The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 4 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred were $288,640, $208,083 and $79,666 during the years ended December 31, 2011, 2010 and 2009, respectively.

10. Related Party Transactions

Administrative Services

An entity under common management provided technical, administrative and payroll services to the Company under a shared services agreement which began January 1, 2008. The reimbursement amount for indirect expenses is determined by the affiliate’s management based on estimates of office space provided and time devoted to the Company. During the years ended December 31, 2011, 2010 and 2009, the Company incurred total costs of $10,020,059, $7,982,816 and $5,464,190, respectively. Costs incurred unrelated to drilling activities are expensed and costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties have been capitalized. The expensed costs were partially offset in general and administrative expenses by overhead reimbursements of $1,896,829, $1,375,267 and $831,519 for the years ended December 31, 2011, 2010 and 2009, respectively. Amounts received until February 26, 2010 were through the related party operator discussed below from the Company’s working interest partners. As of December 31, 2011 and December 31, 2010, the Company owed the administrative services affiliate $769,278 and $372,121, respectively and such amounts are included in accounts payable-related party in the accompanying consolidated balance sheets.

 

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Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

Operating Services

An entity under common management operated a significant portion of the oil and natural gas properties in which the Company has working and revenue interests. As operator of these properties, this entity was responsible for the daily operations, monthly operation billings and monthly revenue disbursements for the properties in which the Company holds an interest. Effective February 26, 2010, the agreement with this entity was terminated and the Company took over as operator of the properties. As of December 31, 2011, the Company did not have a balance payable to this entity. As of December 31, 2010, the Company had an accounts payable-related party balance to this entity of $73,322.

As of December 31, 2011, amounts due to affiliated parties related to property operations consist of drilling and servicing costs of $153,827, prepaid drilling costs of $209,906 and revenues payable of $2,303,184. As of December 31, 2010 amounts due to affiliated parties consist of prepaid drilling costs of $943,390, tubular goods of $68,875 and revenues payable of $266,414. These amounts are included in accounts payable-related party in the accompanying consolidated balance sheets. Each of these affiliated parties is either controlled by or was an affiliate of Wexford.

As of December 31, 2011 and 2010, amounts due from affiliates related to joint interest billings and included in accounts receivable-related party in the accompanying consolidated balance sheets is $8,990,273 and $5,611,550, respectively. Each of these affiliated parties is either controlled by or was an affiliate of Wexford.

Completion and Well Servicing Services

The Company contracted with an affiliate for certain of its well completion services. Effective August 24, 2011, the affiliate was sold to a non-related third party. While still an affiliate of the Company, the Company was billed $12,511,084, $7,709,051 and $3,261,932 during the years ended December 31, 2011, 2010 and 2009, respectively. Such amounts are capitalized in oil and natural gas properties in the accompanying consolidated balance sheet. At December 31, 2010, approximately $3,061,688 in charges were owed under monthly operations billings and included in accounts payable-related party in the accompanying consolidated balance sheets. At December 31, 2011, the entity was no longer a related party.

Marketing Services

The Company entered into an agreement on March 1, 2009 with an entity under common management that purchases and receives a significant portion of the Company’s oil volumes. The Company’s revenues from the affiliate were $38,178,686, $21,402,799 and $8,815,681 during the years ended December 31, 2011, 2010 and 2009, respectively, and such amounts are included in oil sales in the accompanying consolidated statements of operations. As of December 31, 2011 and 2010, the Company had an accounts receivable-related party balance with the affiliate of $4,132,316 and $2,730,483, respectively, and such amounts are included in the accompanying consolidated balance sheets.

Midland Lease

Effective May 15, 2011, the Company occupied corporate office space in Midland, Texas under a lease with a five-year term. The office space is owned by an entity controlled by an affiliate of Wexford. Through December 31, 2011, the Company paid $40,080 under this lease. The current monthly rent under the lease will increase approximately 4% annually on June 1 of each year during the lease term.

 

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Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

Reliance on Wexford

As discussed in Note 1, the Company is wholly owned by an investment fund which is controlled and managed by Wexford. Management believes the credit facility combined with the cash flow generated from operations will be sufficient to sustain the Company’s operations through the end of 2012; however, if additional financing is required management will seek additional sources with could include Wexford.

11. Commitments and Contingencies

The Company could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations.

In March 2011, the Company began leasing field office space in Midland, Texas from an unrelated party. The lease term is 84 months with equal monthly installments that escalate 3% annually on March 1st of each year. In May 2011, the Company began leasing corporate office space in Midland, Texas from an entity controlled by an affiliate of Wexford with a lease term of five years. (See Note 10) Future minimum lease payments for these leases are as follows as of December 31, 2011:

 

2012		$	219,074
2013			222,379
2014			229,566
2015			237,929
2016			185,358
Thereafter			172,600
Total		$	1,266,906

Rent expense for the year ended December 31, 2011 was $74,279.

12. Subsequent Events

The Company has evaluated the period after December 31, 2011 through March 23, 2012, the date the financial statements were available to be issued, noting no subsequent events or transactions that required recognition or disclosure in the financial statements, other than noted below.

On February 21, 2012, Wells Fargo & Company announced it had agreed to purchase BNP Paribas’ energy lending business in the United States and that the purchase is subject to regulatory and other approvals and is expected to close in the second quarter of 2012. BNP Paribas is administrative agent, sole book runner and lead arranger of our reserve-based credit facility with 45% of our current borrowing base of $100 million, and a counterparty to certain of our commodity derivatives. The purchase of BNP’s energy lending business by Wells Fargo & Company should not have an effect on the Company’s credit facility.

13. Supplemental Information on Oil and Natural Gas Operations (Unaudited)

The following supplemental unaudited information regarding the oil and natural gas activities of the Company is presented pursuant to the disclosure requirements promulgated by the United States Securities and Exchange Commission (the “SEC”) and the FASB ASU 2010-03, “Extractive Activities-Oil and Gas (Topic 932)”. The

 

F-23

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Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

reserve reports were prepared in accordance with guidelines established by the SEC and, accordingly, were based on existing economic and operating conditions.

Proved oil and natural gas reserve estimates as of December 31, 2010 and 2009 were prepared by Pinnacle Energy Services, LLC and as of December 31, 2011 were prepared by Ryder Scott Company L.P., both independent petroleum engineers.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

The Company’s oil and natural gas reserves are attributable solely to properties within the United States.

Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows:

 

		Year Ended December 31,
		2011				2010				2009
Acquisition costs:
Proved properties		$	—			$	—			$	—
Unproved properties			3,213,932				2,393,744				1,816,032
Development costs			72,661,524				47,434,500				16,399,583
Exploration costs			9,574,364				3,394,329				851,036
Capitalized asset retirement costs			288,640				208,083				79,666
Total		$	85,738,460			$	53,430,656			$	19,146,317

Results of Operations from Oil and Natural Gas Producing Activities

The Company’s results of operations from oil, natural gas and natural gas liquid producing activities are presented below for years ended December 31, 2011, 2010 and 2009. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our oil, natural gas and natural gas liquids operations.

 

		Year Ended December 31,
		2011				2010				2009
Oil, natural gas and natural gas liquid sales		$	47,180,802			$	26,441,927			$	12,716,011
Lease operating expenses			(10,345,355	)			(4,588,559	)			(2,366,623	)
Production taxes			(2,333,853	)			(1,346,879	)			(663,068	)
Gathering and transportation			(201,828	)			(105,870	)			(42,091	)
Depreciation, depletion and amortization			(15,178,366	)			(7,373,126	)			(3,155,084	)
Results of operations from oil, natural gas and natural gas liquids		$	19,121,400			$	13,027,493			$	6,489,145

 

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Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

Oil and Natural Gas Reserves

The changes in estimated proved reserves are as follows:

 

		Oil (Bbls)				Natural Gas Liquids (Bbls)				Natural Gas (Mcf)
Proved Developed and Undeveloped Reserves:
As of January 1, 2009			1,750,440				771,625				2,945,130
Extensions and discoveries			746,019				128,998				478,092
Revisions of previous estimates			26,903,222				6,691,986				24,311,919
Purchase of reserves in place			—				—				—
Production			(168,741	)			(70,384	)			(253,321	)
Sales of reserves in place			—				—				—
As of December 31, 2009			29,230,940				7,522,225				27,481,820
Extensions and discoveries			1,591,094				1,194,217				13,011,377
Revisions of previous estimates			(11,722,263	)			(3,072,486	)			(18,506,630	)
Purchase of reserves in place			—				—				—
Production			(280,721	)			(79,978	)			(323,847	)
Sales of reserves in place			—				—				—
As of December 31, 2010			18,819,050				5,563,978				21,662,720
Extensions and discoveries			1,705,682				448,164				1,824,339
Revisions of previous estimates			(3,366,041	)			(1,162,054	)			(3,454,552	)
Purchase of reserves in place			—				—				—
Production			(441,822	)			(86,815	)			(413,640	)
Sales of reserves in place			—				—				—
As of December 31, 2011			16,716,869				4,763,273				19,618,867
Proved Developed Reserves:
January 1, 2009			1,750,440				771,625				2,945,130
December 31, 2009			1,954,060				591,532				2,453,750
December 31, 2010			3,307,550				1,105,216				4,255,300
December 31, 2011			3,805,291				1,233,318				5,186,941
Proved Undeveloped Reserves:
January 1, 2009			—				—				—
December 31, 2009			27,276,880				6,930,693				25,028,070
December 31, 2010			15,511,500				4,458,762				17,407,420
December 31, 2011			12,911,578				3,529,955				14,431,926

As of December 31, 2011, 2010 and 2009 reserves were computed using the 12-month unweighted average of the first-day-of-the-month prices, in accordance with revised guidelines of the SEC applicable to reserves estimates as of year-end 2009.

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

 

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Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

The Company experienced downward reserve revisions in estimated proved reserves in 2011. These downward revisions were primarily the result of negative revisions in proved undeveloped wells due to offset well performance; exclusion of proved undeveloped locations that were not scheduled to be drilled within the next five years; and the movement of reserves previously categorized as proved undeveloped to probable reserves due to changes in booking methodology used by our independent petroleum engineers as well as performance of wells in one prospect area.

The Company experienced downward reserve revisions in 2010, due to undeveloped locations being scheduled for development beyond five years and thus being excluded from proved reserves.

The Company experienced upward reserve revisions in 2009, due to the pricing recovery in 2009 and the amendments of ASC 932 in ASU 2010-03.

The increase in 2009 reserves described above had an effect on our depletion and net loss in 2009. The Company is unable to estimate the effect on the 2009 financial statements of the SEC Modernization of the Oil and Gas Reporting Requirement rule that was effective as of December 31, 2009 because a comparative reserve report prepared under the previous rules does not exist.

As of December 31, 2008 all proved undeveloped reserves were noneconomic due to the commodity pricing utilized for the reserve estimate at year end.

Standardized Measure of Discounted Future Net Cash Flows

The following information has been prepared in accordance with the provisions of the FASB ASU 2010-03, “Extractive Activities—Oil and Gas (Topic 932).” As of December 31, 2011, 2010 and 2009 the standardized measure of discounted future net cash flows are based on the average, first-day-of-the-month price.

The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. The Company’s investment and operating decisions are not based on the information presented, but on a wide range of reserve estimates that include probable as well as proved reserves and on different price and cost assumptions.

The standardized measure is intended to provide a better means for comparing the value of the Company’s proved reserves at a given time with those of other oil and gas producing companies than is provided by a comparison of raw proved reserve quantities.

 

		December 31,
		2011(1)				2010				2009
Future cash inflows		$	1,900,958,750			$	1,776,887,010			$	2,040,811,600
Future development costs			(373,750,281	)			(376,204,640	)			(397,076,030	)
Future production costs			(458,936,062	)			(365,712,860	)			(429,507,800	)
Future production taxes			(97,444,617	)			(121,987,210	)			(138,799,710	)
Future net cash flows			970,827,790				912,982,300				1,075,428,060
10% discount to reflect timing of cash flows			(623,808,665	)			(582,624,480	)			(682,509,150	)
Standardized measure of discounted future net cash flows		$	347,019,125			$	330,357,820			$	392,918,910

 

(1)	2011 amounts have been revised from those previously reported to reflect reserve report changes, primarily relating to the timing of development of proved undeveloped reserves.

 

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Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

 

In the table below the average first-day-of–the-month price for oil, natural gas and natural gas liquids is presented, all utilized in the computation of future cash inflows.

 

		December 31,
		2011				2010				2009
		Unweighted Arithmetic Average First-Day-of-the- Month Prices
Oil (per Bbl)		$	93.09			$	77.61			$	58.84
Natural gas (per Mcf)		$	3.91			$	4.14			$	3.64
Natural gas liquids (per Bbl)		$	56.33			$	40.74			$	29.37

The effect of the adoption of the revised SEC rules as of December 31, 2009 with respect to the use of the 12-month unweighted average price caused decreases in reserve volumes and pricing as follows:

 

•

oil volumes of 515,390 Bbls and $18.18 per Bbl;

 

•

natural gas liquids volumes of 130,100 Bbls and $8.85 per Bbl; and

 

•

gas volumes of 537,010 Mcf and $1.84 per Mcf.

Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows:

 

		Year Ended December 31,
		2011				2010				2009
Standardized measure of discounted future net cash flows at the beginning of the period		$	330,357,820			$	392,918,910			$	41,435,980
Sales of oil and natural gas, net of production costs			(34,299,766	)			(20,400,619	)			(9,644,229	)
Purchase of minerals in place			—				—				—
Extensions and discoveries, net of future development costs			69,375,680				52,678,768				18,489,620
Previously estimated development costs incurred during the period			83,166,092				51,023,970				16,345,261
Net changes in prices and production costs			80,480,005				178,197,726				7,580,209
Changes in estimated future development costs			(76,990,690	)			(23,991,650	)			(409,015,151	)
Revisions of previous quantity estimates			(100,433,225	)			(292,306,238	)			798,975,216
Sales of reserves in place, net of future development costs			—				—				—
Accretion of discount			33,035,782				39,291,891				4,143,598
Net changes in timing of production and other(1)			(37,672,573	)			(47,054,938	)			(75,391,594	)
Standardized measure of discounted future net cash flows at the end of the period(1)		$	347,019,125			$	330,357,820			$	392,918,910

 

(1)	2011 amounts have been revised from those previously reported to reflect reserve report changes, primarily relating to the timing of development of proved undeveloped reserves.

 

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Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Consolidated Balance Sheets

 

		March 31, 2012				December 31, 2011
		(Unaudited)
Assets
Current assets:
Cash and cash equivalents		$	9,043,365			$	6,802,389
Accounts receivable:
Joint interest and other			2,444,749				3,734,513
Oil and natural gas sales			5,690,527				838,791
Related party			2,818,743				13,122,589
Inventories			7,184,217				6,006,355
Prepaid expenses and other			400,450				428,202
Total current assets			27,582,051				30,932,839
Property and equipment
Oil and natural gas properties, at cost, based on the full cost method of accounting ($5,727,513 and $1,732,329 excluded from amortization at March 31, 2012 and December 31, 2011, respectively)			350,424,685				325,510,080
Other property and equipment			1,205,367				1,016,574
Accumulated depletion, depreciation, amortization and impairment			(124,159,732	)			(119,500,035	)
			227,470,320				207,026,619
Investments-equity method			10,490,579				10,309,668
Other assets			1,497,856				1,214,759
Total assets		$	267,040,806			$	249,483,885
Liabilities and Members’ Equity
Current liabilities:
Accounts payable trade		$	9,317,178			$	8,769,491
Accounts payable–related party			3,139,944				3,436,195
Accrued capital expenditures			9,626,704				13,922,932
Other accrued liabilities			3,534,712				4,804,069
Revenues and royalties payable			4,399,130				3,165,267
Derivative contracts			10,965,579				8,320,351
Note payable credit facility–short term			12,490,000				—
Total current liabilities			53,473,247				42,418,305
Note payable credit facility–long term			85,000,000				85,000,000
Derivative contracts			6,926,100				6,138,573
Asset retirement obligations			1,136,123				1,079,725
Total liabilities			146,535,470				134,636,603
Commitments and contingencies (Note 11)
Members’ equity			120,505,336				114,847,282
Total liabilities and members’ equity		$	267,040,806			$	249,483,885

See accompanying notes to consolidated financial statements.

 

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Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Consolidated Statements of Operations

(Unaudited)

 

		Three Months Ended March 31,
		2012				2011
Revenues:
Oil sales		$	14,299,429			$	11,046
Oil sales-related party			—				9,296,654
Natural gas sales			347,322				319,081
Natural gas liquid sales			1,357,756				957,121
Oil and natural gas services-related party			—				1,490,910
Total revenues			16,004,507				12,074,812
Costs and expenses:
Lease operating expenses			2,126,439				1,736,230
Lease operating expenses-related party			555,411				460,729
Production taxes			780,574				96,814
Production taxes-related party			—				426,601
Gathering and transportation			67,232				35,482
Oil and natural gas services			—				1,207,101
Oil and natural gas services – related party			—				525,791
Depreciation, depletion and amortization			4,664,942				3,616,694
General and administrative expenses			481,946				54,668
General and administrative expenses-related party			709,456				546,380
Asset retirement obligation accretion expense			19,855				13,691
Total costs and expenses			9,405,855				8,720,181
Income from operations			6,598,652				3,354,631
Other income (expense)
Interest income			1,310				4,212
Interest expense			(881,469	)			(495,768	)
Other income			445,360				—
Loss on derivative contracts			(4,792,104	)			(12,114	)
Loss from equity investment			(12,618	)			—
Total other expense, net			(5,239,521	)			(503,670	)
Net income		$	1,359,131			$	2,850,961
Pro forma information
Net income before income taxes, as reported		$	1,359,131			$	2,850,961
Pro forma provision for income tax			—				—
Pro forma net income		$	1,359,131			$	2,850,961
Pro forma income per common share – basic and diluted		$
Weighted average pro forma shares outstanding – basic and diluted

See accompanying notes to consolidated financial statements.

 

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Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Consolidated Statement of Changes in Members’ Equity

(Unaudited)

 

		Total members’ equity
Balance at January 1, 2012		$	114,847,282
Contributions			4,007,813
Equity based compensation			291,110
Net income			1,359,131
Balance at March 31, 2012		$	120,505,336
Balance at January 1, 2011		$	105,638,043
Net income			2,850,961
Balance at March 31, 2011		$	108,489,004

See accompanying notes to consolidated financial statements.

 

F-30

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Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)

 

		Three Months Ended March 31,
		2012				2011
Cash flows from operating activities:
Net income		$	1,359,131			$	2,850,961
Adjustments to reconcile net income to net cash provided by operating activities:
Asset retirement obligation accretion expense			19,855				13,691
Depreciation, depletion, and amortization			4,664,942				4,119,183
Amortization of debt issuance costs			105,041				65,347
Loss on derivative contracts			4,792,104				12,114
(Gain) loss on sale of assets			(1,525	)			(12,135	)
Equity-based compensation expense			291,110				—
Loss on equity investment			12,618				—
Changes in operating assets and liabilities:
Accounts receivable			(3,561,972	)			976,033
Accounts receivable-related party			10,307,359				(4,536,744	)
Inventories			812,008				(121,491	)
Prepaid expenses and other			(56,702	)			(172,969	)
Accounts payable and accrued liabilities			(678,955	)			2,097,746
Accounts payable and accrued liabilities-related party			(192,073	)			235,089
Revenues and royalties payable			1,233,863				99,657
Revenues and royalties payable-related party			49,648				(58,588	)
Net cash provided by operating activities			19,156,452				5,567,894
Cash flows from investing activities:
Additions to oil and natural gas properties			(28,950,115	)			(10,976,892	)
Additions to oil and natural gas properties-related party			(2,668,470	)			(4,896,895	)
Purchase of other property and equipment			(194,037	)			(5,466,193	)
Proceeds from sale of property and equipment			1,525				12,135
Settlement of non-hedge derivative instruments			(2,288,766	)			(1,020,450	)
Receipt on derivative margins			929,417				401,773
Deconsolidation of Bison			—				(9,536	)
Net cash used in investing activities			(33,170,446	)			(21,956,058	)
Cash flows from financing activities:
Borrowing on credit facility			12,490,000				13,533,313
Debt issuance costs			(9,274	)			(150,000	)
Initial public offering costs			(233,569	)			—
Contributions by members			4,007,813				—
Net cash provided by financing activities			16,254,970				13,383,313
Net increase (decrease) in cash and cash equivalents			2,240,976				(3,004,851	)
Cash and cash equivalents at beginning of period			6,802,389				4,089,745
Cash and cash equivalents at end of period		$	9,043,365			$	1,084,894
Supplemental cash flow information
Interest paid, net of capitalized interest		$	764,569			$	447,547
Asset retirement obligation incurred, including changes in estimate		$	36,543			$	86,588

See accompanying notes to consolidated financial statements.

 

F-31

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Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements

(Unaudited)

1. Organization

Windsor Permian LLC (“Windsor”) is a limited liability company formed on October 23, 2007 to acquire, produce, develop and exploit oil and natural gas properties. As a limited liability company, the members of Windsor are not liable for the liabilities or other obligations of Windsor. Windsor is wholly owned by an investment fund which is controlled and managed by Wexford Capital LP (“Wexford”). Collectively, Windsor and its subsidiaries, Bison Drilling and Field Services LLC (formerly known as Windsor Drilling LLC) through March 31, 2011, Diamondback E&P LLC, formed on February 17, 2012, and West Texas Field Services LLC, are referred to in these financial statements as the “Company”.

The Company is engaged in the acquisition, exploitation, development and production of oil and natural gas properties and related sale of oil, natural gas and natural gas liquids. The Company’s reserves are located in the Southern region of the United States. The Company’s results of operations are largely dependent on the difference between the prices received for its oil, natural gas and natural gas liquids and the cost to find, develop, produce and market such resources. Oil and natural gas prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond the Company’s control. These factors include worldwide political instability, quantity of natural gas in storage, foreign supply of oil and natural gas, the price of foreign imports, the level of consumer demand and the price of available alternative fuels, among others.

2. Summary of Significant Accounting Policies

The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. The consolidated financial statements include the accounts of Windsor and its wholly owned subsidiaries, except for the accounts of Bison Drilling and Field Services LLC, which has been excluded from the Company’s consolidated financial statements effective March 31, 2011 (Note 5). All significant intercompany accounts and transactions have been eliminated in consolidation.

The accompanying unaudited financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information. Pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, the accompanying unaudited financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly our financial position as of March 31, 2012, and our results of operations, changes in members’ equity and cash flows for the three months ended March 31, 2012 and 2011. Operating results for the three months ended March 31, 2012 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for natural gas and oil, natural production declines, timing of development and exploration activities, the uncertainty of exploration and development drilling results and other factors. For a more complete understanding of our operations, financial position and accounting policies, these financial statements should be read in conjunction with our annual financial statements.

Use of estimates

Certain amounts included in or affecting the Company’s consolidated financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates.

 

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Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

 

The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved reserve quantities and related estimates of the present value of future net revenues, the carrying value of oil and gas properties and asset retirement obligations.

Cash and Cash Equivalents

The Company considers all highly liquid debt instruments purchased with a maturity of three months or less and money market funds to be cash equivalents. The Company utilizes bank deposit accounts which periodically sweep available cash into uninsured short-term investment securities. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts.

Accounts Receivable

Accounts receivable consist of receivables from joint interest owners on properties the Company operates and oil and natural gas production delivered to purchasers. The purchasers remit payment for production directly to the Company. Most payments are received within three months after the production date.

Accounts receivable are stated at amounts due from joint interest owners or purchasers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary at March 31, 2012 and December 31, 2011.

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, derivatives and note payable. The carrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of the instruments. The fair value of the revolving credit facility approximates its carrying value based on the borrowing rates currently available to the Company for bank loans with similar terms and maturities. Derivatives are recorded at fair value (see Note 9).

Oil and Natural Gas Properties

The Company accounts for its oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized. General and administrative costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other

 

F-33

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Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

 

administrative costs associated with overseeing the exploration and development activities. All general and administrative costs not directly associated with exploration and development activities are charged to expense as they are incurred. Capitalized general and administrative costs were $692,115 for the three months ended March 31, 2012, and no amounts were capitalized for the three months ended March 31, 2011. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Any income from services provided by subsidiaries to working interest owners of properties in which the Company also owns an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties proportionate to the Company’s investment in the subsidiary (see Note 5). Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves. The average depletion rate per barrel equivalent unit of production was $23.00 and $26.42 for the three months ended March 31, 2012 and 2011, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties was $4,590,514 and $3,563,692 for the three months ended March 31, 2012 and 2011, respectively.

The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment exceed the discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. No impairment on proved oil and natural gas properties was recorded for the three months ended March 31, 2012 or 2011.

Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company assesses all items classified as unevaluated property on an annual basis for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within three years.

Other Property and Equipment

Other property and equipment is recorded at cost. The Company expenses maintenance and repairs in the period incurred. Upon retirements or disposition of assets, the cost and related accumulated depreciation are removed from the consolidated balance sheet with the resulting gains or losses, if any, reflected in operations. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years. Depreciation expense was $74,429 and $555,082 for the three months ended March 31, 2012 and 2011, respectively.

Impairment of Long-Lived Assets

Other long-lived assets, drilling rigs and related equipment used in operations are reviewed whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss is recognized only if the carrying amount of a long-lived asset is not recoverable from its estimated future

 

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Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

 

undiscounted cash flows. An impairment loss is the difference between the carrying amount and fair value of the asset. The Company had no such impairment losses for the three months ended March 31, 2012 or 2011.

Capitalized Interest

The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Capitalized interest cannot exceed gross interest expense. During the three months ended March 31, 2012 and 2011, the Company did not capitalize any interest expense.

Inventories

Inventories are stated at the lower of cost or market and consist of the following:

 

		March 31, 2012				December 31, 2011
Tubular goods and equipment		$	6,830,370			$	5,630,208
Crude oil			353,847				376,147
		$	7,184,217			$	6,006,355

The Company’s tubular goods and equipment is primarily comprised of oil and gas drilling or repair items such as tubing, casing and pumping units. The inventory is primarily acquired for use in future drilling or repair operations and is carried at lower of cost or market. “Market”, in the context of inventory valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint accounts under joint operating agreements to which the Company is a party. As of March 31, 2012 and December 31, 2011, the Company estimated that all of its tubular goods and equipment will be utilized within one year. The total inventory includes tubular goods held by others of $1,093,708 at both March 31, 2012 and December 31, 2011. Some of the tubular and casing pipe has been purchased, at cost, from an affiliated company. The Company did not have a balance outstanding with the affiliated company at either March 31, 2012 or December 31, 2011.

Debt issuance costs

The Company amortizes debt issuance costs related to its credit facility as interest expense over the scheduled maturity period of the debt. Unamortized debt issuance costs were $1,077,952 and $1,167,621 as of March 31, 2012 and December 31, 2011, respectively. The Company includes the unamortized costs in other assets in its consolidated balance sheets.

Revenue and Royalties Payable

For certain oil and natural gas properties, where the Company serves as operator, the Company receives production proceeds from the purchaser and further distributes such amounts to other revenue and royalty owners. Production proceeds applicable to other revenue and royalty owners are reflected as revenue and royalties payable in the accompanying consolidated balance sheets. The Company recognizes revenue for only its net revenue interest in oil and natural gas properties.

 

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Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

 

Revenue Recognition

Oil and natural gas revenues are recorded when title passes to the purchaser, net of royalty interests, discounts and allowances, as applicable. The Company accounts for oil and natural gas production imbalances using the sales method, whereby a liability is recorded when the Company’s overtake volumes exceed its estimated remaining recoverable reserves. No receivables are recorded for those wells where the Company has taken less than its ownership share of production. The Company did not have any gas imbalances as of March 31, 2012 or December 31, 2011. Revenues from oil and natural gas services are recognized as services are provided.

Investments

Equity investments in which the Company exercises significant influence but does not control are accounted for using the equity method. Under the equity method, generally the Company’s share of investees’ earnings or loss is recognized in the statement of operations. However, because substantially all of Bison’s earnings are generated by performing services on properties owned and operated by the Company, the Company’s share of Bison’s earnings has not been recognized but has been credited to oil and gas properties. The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company would recognize an impairment provision. There was no impairment for the Company’s equity investments at March 31. 2012 or December 31, 2011. For additional information on the Company’s investments, see Note 5.

Accounting for Equity-Based Compensation

The Company accounts for equity-based compensation in accordance with the provisions of FASB ASC Topic 718, “Compensation—Stock Compensation” (“FASB ASC 718”). FASB ASC 718 requires equity-based payments to employees to be recognized as expense over the applicable service period based on the fair value of the award on the date of grant.

Concentrations

The Company is subject to risk resulting from the concentration of its crude oil and natural gas sales and receivables with several significant purchasers. For the three months ended March 31, 2012, three purchasers accounted for 64%, 14% and 13% of our revenue. For the three months ended March 31, 2011, Windsor Midstream LLC, an entity controlled by Wexford, our equity sponsor, accounted for 88% of our revenue. The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Commodity Risk Management

The Company has used energy derivatives for the purpose of mitigating the risk resulting from fluctuations in the market price of crude oil. The Company recognizes all of its derivative instruments as either assets or liabilities at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and further on the type of hedging relationship. For those derivative instruments that are designated and qualify as hedging instruments, the Company designates the hedging instrument, based on the exposure being hedged, as either a fair value hedge or a cash flow hedge. Changes in the fair value of instruments designated as a fair value hedge offset changes in the fair value of the hedged item and changes in the fair value of instruments designated as cash flow hedges are

 

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Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

 

shown in accumulated other comprehensive income until the hedged item is recognized in earnings. For derivative instruments not designated as hedging instruments, the unrealized gain or loss on the change in fair value of these instruments are recognized in earnings during the period of change. None of the Company’s derivatives were designated as hedging instruments.

Environmental Compliance and Remediation

Environmental compliance and remediation costs, including ongoing maintenance and monitoring, are expensed as incurred. Liabilities are accrued when environmental assessments and remediation are probable, and the costs can be reasonably estimated.

Income Taxes

The operations of the Company, as limited liability companies, are not subject to federal income taxes. As appropriate, the taxable income or loss applicable to those operations is included in the federal income tax returns of the respective owners and no income tax effect is included in the accompanying consolidated financial statements. The Company is subject to margin tax in the state of Texas. During the three months ended March 31, 2012 and 2011, there was no margin tax expense. The Company’s 2008, 2009 and 2010 federal income tax and state margin tax returns remain open to examination by tax authorities. As of March 31, 2012 and December 31, 2011, the Company had no unrecognized tax benefits that would have a material impact on the effective rate. The Company is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the three months ended March 31, 2012 and 2011, there was no interest or penalties associated with uncertain tax positions in the Company’s consolidated financial statements.

Unaudited Pro Forma Income Taxes and Earnings Per Share

Prior to the completion of a proposed 2012 initial public offering of common stock (“IPO”) by Diamondback Energy, Inc. (“Diamondback”), all the equity interests in Windsor will be contributed to Diamondback and Windsor will become a wholly-owned subsidiary of Diamondback (Proposed Contribution Transaction). Diamondback, a holding company formed on December 30, 2011 which will not conduct any material business operations prior to the Proposed Contribution Transaction, is a C-Corp under the Internal Revenue Code and is subject to income taxes. Accordingly, the Company computed a pro forma income tax provision as if the Company were a C-Corp for all periods presented. The pro forma tax provision has been calculated at a rate based upon a federal corporate level tax rate and a state tax rate, net of federal benefit, incorporating permanent differences. However, on a pro forma basis, management has determined that any net deferred income tax asset would not be realizable; therefore, tax expense would be zero for all periods. Additionally, upon Windsor becoming a subsidiary of Diamondback, the Company will establish a net deferred tax liability for differences between the tax and book basis of the Company’s assets and liabilities, and record a corresponding “first day” tax expense to net income from continuing operations. On a pro forma basis, at March 31, 2012 the amount of this charge would have been approximately $27.1 million.

Also, upon completion of the Proposed Contribution Transaction, the Company will present pro forma earnings per share for the most recent period. Pro forma basic and diluted income per share will be computed by dividing net income attributable to the Company by the number of shares of common stock outstanding as if the shares of Diamondback Energy, Inc., issued in the Proposed Contribution Transaction, were issued and outstanding for the three months ended March 31, 2012.

 

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Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

 

Recently issued accounting standards

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS,” which provides a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between U.S. GAAP and International Financial Reporting Standards. This new guidance changes some fair value measurement principles and disclosure requirements, but does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. The update is effective for annual periods beginning after December 15, 2011. The adoption of this guidance will not have a significant impact on our financial position, results of operations or cash flow.

In June 2011, the FASB issued Accounting Standards Update No. 2011-05, “Comprehensive Income: Presentation of Comprehensive Income,” which provides amendments to FASB ASC Topic 220, “Comprehensive Income” (“FASB ASC 220”). The purpose of the amendments in this update is to provide a more consistent method of presenting non-owner transactions that affect an entity’s equity. The amendments eliminate the option to report other comprehensive income and its components in the statement of changes in equity and require an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. In December 2011, the FASB issued Accounting Standards Update 2011-12 which defers the requirement in Accounting Standards Update 2011-05 that companies present reclassification adjustments for each component of accumulated other comprehensive income in both net income and other comprehensive income on the face of the financial statements. Both amendments are effective for interim and annual periods beginning after December 15, 2011 and should be applied retrospectively. The adoption of this guidance did not have any impact on our financial position, results of operations or cash flow.

3. Property and Equipment

Property and equipment includes the following:

 

		March 31, 2012				December 31, 2011
Oil and natural gas properties:
Subject to depletion		$	344,697,172			$	323,777,751
Not subject to depletion-acquisition costs
Incurred in 2012			4,010,897				—
Incurred in 2011			1,177,879				1,199,679
Incurred in 2010			—				—
Incurred in 2009			538,737				532,650
Total not subject to depletion			5,727,513				1,732,329
Gross oil and natural gas properties			350,424,685				325,510,080
Less accumulated depreciation, depletion, amortization and impairment			(123,757,989	)			(119,167,476	)
Oil and natural gas properties, net			226,666,696				206,342,604
Other property and equipment			1,205,367				1,016,574
Less accumulated depreciation			(401,743	)			(332,559	)
Other property and equipment, net			803,624				684,015
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment		$	227,470,320			$	207,026,619

 

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Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

 

4. Asset Retirement Obligations

The Company measures the future cost to retire its tangible long-lived assets and recognizes such cost as a liability in accordance with ASC Topic 410, Asset Retirement and Environmental Obligations (“ASC Topic 410”), which provides accounting and reporting guidance for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset.

ASC Topic 410 requires companies to record a liability relating to the retirement and removal of assets used in their businesses. For the Company, asset retirement obligations represent the future abandonment costs of tangible assets, namely wells. ASC Topic 410 requires that the fair value of a liability for an asset’s retirement obligation be recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and that the corresponding cost be capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, the difference is recorded in oil and natural gas properties.

A reconciliation of the asset retirement obligation is as follows:

 

		Three Months Ended March 31,
		2012				2011
Asset retirement obligation, beginning of period			1,079,725			$	727,826
Additional liability incurred			36,543				86,588
Accretion expense			19,855				13,691
Asset retirement obligation, end of period			1,136,123				828,105
Less current portion			—				—
Asset retirement obligations - long-term		$	1,136,123			$	828,105

5. Equity Method Investments

Bison Drilling and Field Services LLC

The Company held a wholly owned subsidiary, Bison Drilling and Field Services LLC (“Bison”), formerly known as Windsor Drilling LLC, formed on November 15, 2010. In addition, the Company also held a wholly owned subsidiary, West Texas Field Services LLC, formed on March 2, 2010 which, on January 1, 2011, contributed all of its assets and liabilities to Bison. Bison owns and operates drilling rigs and various oil and gas well servicing equipment.

Beginning on March 31, 2011, various related party investors contributed capital to Bison diluting the Company’s ownership interest. The Company assessed its ability to exercise financial control over Bison and based on the results of its assessment, the Company concluded it maintains significant influence but it no longer had the ability to exercise control over Bison. The Company has deconsolidated Bison for financial reporting purposes as of March 31, 2011 and the previously consolidated amounts were removed from the consolidated balance sheet and reflected as an equity method investment. The Company now reflects its investment in Bison on the equity method basis of accounting. The Company eliminates any intercompany profits or losses in relation to its continuing involvement with Bison, proportionate to its equity interest.

 

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Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

 

An entity is required to deconsolidate a subsidiary when the entity ceases to have a controlling financial interest in the subsidiary. Upon deconsolidation of a subsidiary, an entity recognizes a gain or loss on the transaction and measures any retained investment in the subsidiary at fair value. The gain or loss includes any gain or loss associated with the difference between the fair value of the retained investment in the subsidiary and its carrying amount at the date the subsidiary is deconsolidated.

The Company internally reviewed the balance sheet of Bison to determine its fair value. At the time of the transaction, Bison was still a recently formed company and had not yet built value in its operations. Bison’s assets consisted primarily of four recently purchased drilling rigs. Two of the drilling rigs were purchased at market price from a third party in December 2010 and the second two were purchased from the same third party in April 2011. The Company also reviewed pricing of similar rigs in the market through retail and auction transactions. Because the rigs had just recently been purchased and this purchase price was in line with other outside transactions, the Company determined that Bison’s book value equaled fair value. There was no gain or loss recorded and the retained investment was recorded at fair value which equaled book value.

In September 2011, the Company completed the sale of 25% of its membership interest in Bison to a related party. The Company internally reviewed the fair value of Bison and, because the effective date of this transaction was May 1, 2011 and was within thirty days of the above valuation, concluded the value of Bison had not changed. The Company determined that fair value equaled book value at the date of this transaction. There was no gain or loss recorded and the retained investment was recorded at fair value which equaled book value.

The Company has a 27.2% ownership in Bison at March 31, 2012. As of March 31, 2012, the Company’s investment in Bison is reflected as a non-current asset of $6,369,522.

The table below summarizes financial information for Bison as of March 31, 2012:

 

		March 31, 2012
Current assets		$	4,232,780
Property and equipment, net			21,619,847
Other assets			976,460
Current liabilities			1,699,517
Equity			25,129,570

Muskie Holdings LLC

During 2011, the Company paid approximately $4,200,000 for land and various other capital items related to the land. On October 7, 2011, the Company contributed these assets to a newly formed entity, Muskie Holdings LLC, a Delaware limited liability company, for a 48.6% ownership interest. Through additional contributions to Muskie from a related party and various Wexford portfolio companies, it is expected that the Company’s interest in Muskie will decrease through 2012. Muskie generated a loss during the three months ended March 31, 2012 and the Company has recorded its share of this loss. As of March 31, 2012, the Company’s ownership interest in Muskie is 34% and is reflected as a non-current asset of $4,121,057.

 

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Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

 

The table below summarizes financial information for Muskie as of March 31, 2012:

 

		March 31, 2012
Current assets		$	1,886,371
Property and equipment, net			10,478,623
Current liabilities			142,697
Equity			12,222,297

6. Revolving Bank Credit Facility

Credit Facility-BNP Paribus

On October 15, 2010, the Company executed a secured loan agreement with BNP Paribas (“BNP”) as the administrative agent, sole book runner and lead arranger. The loan agreement originally provided for a maximum principal amount of $100 million and was increased to $250 million through an amendment dated December 30, 2011. The loan agreement is subject to a collateral borrowing base calculation which is based on the Company’s oil and natural gas reserves (the “borrowing base”). The loan bears interest at a rate elected by the Company that is based on the prime, LIBOR or federal funds rate plus margins ranging from 1.25% to 3.00% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base.

Principal is payable voluntarily by the Company or is required to be paid (i) if the loan amount exceeds the borrowing base; (ii) if the lender elects to require periodic payments as a part of a borrowing base re-determination; and (iii) at the maturity date of October 15, 2014. The Company is obligated to pay, quarterly, a commitment fee equal to 0.5% per year of the unused portion of the borrowing base. The loan is secured by substantially all of the Company’s assets. The borrowing base is re-determined semi-annually with effective dates of April 1st and October 1st (a “scheduled redetermination”). In addition, the Company may request an additional three redeterminations of the borrowing base between scheduled redeterminations. The borrowing base was $45 million at December 31, 2010. The borrowing base increased throughout 2011 through various redeterminations and at December 31, 2011 the borrowing base was $100 million. Under the terms of the revolving credit agreement as currently in effect, the borrowing base will remain at $100 million through October 15, 2012, at which time the borrowing base will be reduced to $85 million, subject to the periodic and elective borrowing base redeterminations described above. The current lenders and their percentage commitments in the reserve-based credit facility are BNP (45%), Amegy Bank of Texas (25%), US Bancorp (25%) and West Texas National Bank (5%).

As of March 31, 2012 and December 31, 2011, the Company had outstanding borrowings of $97,490,000 and $85,000,000, respectively. The credit facility bears a weighted average interest rate of 3.3% and 3.3% as of March 31, 2012 and December 31, 2011, respectively.

The agreement contains various affirmative and restrictive covenants. These covenants, among other things, prohibit additional indebtedness, sales of assets, mergers and consolidations, dividends and distributions, and changes in management and require the maintenance of various financial ratios defined below.

 

Financial Covenant		Required Ratio
Ratio of EBITDAX to interest expense, as defined in the credit agreement		Not less than 2.5 to 1.0
Ratio of total debt to EBITDAX		Not greater than 3.5 to 1.0
Current ratio, as defined in the credit agreement		Not less than 1.0 to 1.0

 

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Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

 

As of March 31, 2012 and December 31, 2011, the Company was in compliance with all financial covenants under the revolving bank credit facility. The lenders may accelerate all of the indebtedness under the revolving bank credit facility upon the occurrence of any event of default unless the Company cures any such default within any applicable grace period. For payments of principal and interest under the revolving bank credit facility, the Company generally has a three business day grace period, and a 30-day cure period for most covenant defaults, but not for defaults of certain specific covenants, including the financial covenants and negative covenants.

7. Derivatives

The Company has used price swap derivatives to reduce price volatility associated with certain of its oil sales. In these swaps, the Company receives the fixed price per the contract and pays a floating market price to the counterparty based on New York Mercantile Exchange Light Sweet Crude Oil pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. The counterparties to the Company’s derivative contracts are BNP Paribas (“BNP”) and Hess Corporation (“Hess”), who the Company believes are acceptable credit risks.

All derivative financial instruments are recorded on the consolidated balance sheets at fair value. The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity.

On October 4, 2011, in order to lock-in prices on the anticipated base level of production, while at the same time providing downside protection for the Borrowing Base, the Company executed with BNP, West Texas Intermediate light sweet crude oil swaps on the NYMEX for calendar year 2012 and 2013 of one thousand barrels per day priced at $78.50 and $80.55, respectively.

Set forth below are the summarized amounts, terms and fair values of outstanding instruments held as of March 31, 2012 and December 31, 2011.

 

						Original Strike Price (per Bbl)				March 31, 2012				December 31, 2011
Description and Production Period		Volume (Bbls)								Fair Value Liability				Fair Value Liability
Crude Oil Swaps:
January – February 2012			60,000			$	78.50			$	—			$	1,228,289
March – November 2012			275,000			$	78.50				7,190,009				5,604,976
December 2012			31,000			$	78.50				831,348				594,223
January – February 2013			59,000			$	80.55				1,451,454				982,519
March – December 2013			306,000			$	80.55				6,926,100				4,561,831

The Company enters into counter-swaps from time to time for the purpose of locking-in the value of a swap. Under the counter-swap, the Company receives a floating price for the hedged commodity and pays a fixed price to the counterparty. The counter-swap is effective in locking-in the value of a swap since subsequent changes in the market value of the swap are entirely offset by subsequent changes in the market value of the counter-swap.

In December 2007, the Company placed a swap contract with Hess covering 1,680,000 Bbls of crude oil for the period from January 2008 to December 2012 at various fixed prices. In April 2008, the Company entered into a series of counter-swaps to lock-in the value of certain of these swaps settling 1,188,000 Bbls of crude oil swaps. In June 2009, the Company entered into an additional series of counter-swaps to lock-in the value of the remaining swaps settling 324,000 Bbls of crude oil swaps.

 

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Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

 

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the April 2008 settlements as of March 31, 2012 and December 31, 2011, respectively.

 

						Original Strike Price (per Bbl)				Lock-in Price (per Bbl)				March 31, 2012				December 31, 2011
Description and Production Period		Volume (Bbls)												Fair Value Liability				Fair Value Liability
Crude Oil Swaps:
December 2011			22,500			$	82.90			$	98.50–$102.20			$	—			$	378,750
January – February 2012			45,000			$	85.07			$	98.25–$101.80				—				646,338
March – December 2012			225,000			$	85.07			$	98.25–$101.80				3,230,066				3,230,621

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the June 2009 settlements as of March 31, 2012 and December 31, 2011, respectively.

 

						Original Strike Price (per Bbl)				Lock-in Price (per Bbl)				March 31, 2012				December 31, 2011
Description and Production Period		Volume (Bbls)												Fair Value Asset				Fair Value Asset
Crude Oil Swaps:
December 2011			7,500			$	82.90			$	78.42			$	—			$	33,600
January – February 2012			15,000			$	85.07			$	80.52				—				68,249
March – December 2012			75,000			$	85.07			$	80.52				341,072				341,131

None of the Company’s derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following summarizes the loss on derivative contracts included in the consolidated statements of operations:

 

		Three Months Ended March 31,
		2012				2011
Unrealized loss on open non-hedge derivative instruments		$	3,427,073			$	—
Loss on settlement of non-hedge derivative instruments			1,365,031				12,114
Loss on derivative contracts		$	4,792,104			$	12,114

The Company is required to provide margin deposits to Hess whenever its unrealized losses exceed predetermined credit limits. The Company had a margin deposit held by Hess of $1,396,226 and $2,325,643 as of March 31, 2012 and December 31, 2011, respectively, which earns interest that is remitted to the Company. As the Company has a master netting agreement with Hess, the Company has offset this margin deposit against its derivative positions.

8. Equity-Based Compensation

During the year ended December 31, 2011, the Company granted to its executive officers options to acquire membership interests in the Company. Such options vest in four equal annual installments commencing on the first anniversary of the date of grant and are exercisable for five years from the date of grant. Generally, in the event more than 50% of the combined voting interests of the Company is not owned by Wexford or its affiliates and there is a material change in the terms of the option holder’s employment, the options will vest immediately. Under one agreement, however, the options will vest solely in the event that more than 50% of the voting interests of the Company is not owned by Wexford or its affiliates.

 

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Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

 

Summarized below are the grant dates with the total exercise prices and total fair values of the underlying options:

 

Grants Made During the Months Ended		Membership Interest Granted				Exercise Price				Fair Value at Date of Grant
April 2011			1.00	%		$	3,600,000			$	1,452,851
August 2011			1.20	%			6,000,000				1,383,976
September 2011			1.25	%			5,900,000				1,532,612
November 2011			0.25	%			1,250,000				288,328
			3.70	%		$	16,750,000			$	4,657,767

At March 31, 2012 and December 31, 2011, for outstanding options, the intrinsic value was $112,500 and $112,500, respectively, and the weighted-average remaining contractual terms were 4.3 and 4.6 years, respectively. Also, at March 31, 2012 and December 31, 2011, no options were exercisable.

The Company accounts for such options issued using a fair-value-based method calculated on the grant-date of the award. The resulting cost is recognized on a straight-line basis over the vesting period of the entire option.

The fair value of the options issued was estimated using the Black-Scholes option-pricing model. One of the inputs to this model is the estimate of the fair value of the underlying membership interest on the date of grant. The other inputs include an estimate of the expected volatility of the membership interest, an option’s expected term, the risk-free interest rate over the option’s expected term, the option’s exercise price, and the Company’s expectations regarding dividends.

The Company does not have a history of market prices for its membership interests because such interests are not publicly traded. The expected volatility was determined using the historical volatility for a peer group of companies. The expected term for options issued was determined based on the contractual term of the awards. The weighted-average risk-free interest rate was based on the daily U.S. treasury yield curve rate whose term was consistent with the expected life of the options. The Company does not anticipate paying cash dividends; therefore, the expected dividend yield was assumed to be zero.

A summary of the significant assumptions used to estimate the fair value of the options to acquire membership interests during the year ended December 31, 2011 was as follows:

 

Expected term			5 years
Risk-free interest rate			0.96	%
Expected volatility			45.50	%
Expected dividend yield			0.00	%

The Company assumed no annual forfeiture rate because of its lack of turnover and lack of history for this type of award. The Company will continue to evaluate the appropriateness of the forfeiture rate based on actual forfeiture experience, analysis of employee turnover behavior, and other factors. Changes in the estimated forfeiture rate can have a significant effect on reported equity-based compensation expense, because the cumulative effect of adjusting the rate for all expense amortization is recognized in the period the forfeiture estimate is changed.

 

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Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

 

Equity-based compensation expense recorded for the three months ended March 31, 2012 was $291,110. The unrecognized equity-based compensation expense as of March 31, 2012 and December 31, 2011 was $3,822,366 and $4,113,477, respectively, related to these awards which is expected to be recognized over a weighted-average period of 3.3 and 3.6, years, respectively. No equity-based compensation expense was recorded for the three months ended March 31, 2011 as the Company had not historically issued equity-based compensation awards.

9. Fair Value Measurements

The Company measures and discloses fair value in accordance with ASC Topic 820, Fair Value Measurements and Disclosures (“ASC Topic 820”). Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.

ASC Topic 820 describes a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities.

The three levels of the fair value hierarchy defined by ASC Topic 820 are as follows:

Level 1—Pricing inputs include quoted prices available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, marketable securities and listed equities.

Level 2—Pricing inputs include quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Level 2 instruments primarily include non-exchange traded derivatives such as over-the-counter commodity price swaps, basis swaps, investments and interest rate swaps. The Company’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The Company utilizes its counterparties’ valuations to assess the reasonableness of its prices and valuation techniques.

Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

 

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Table of Contents

Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

 

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of March 31, 2012 and December 31, 2011.

 

		Quoted Prices in Active Markets Level 1				Significant Other Observable Inputs Level 2				Significant Unobservable Inputs Level 3				Cash Collateral(1)				Net Fair Value
Financial Liabilities
		March 31, 2012
Derivative contracts		$	—			$	19,287,905			$	—			$	(1,396,226	)		$	17,891,679
		December 31, 2011
Derivative contracts		$	—			$	16,784,567			$	—			$	(2,325,643	)		$	14,458,924

 

(1)	Represents the impact of netting cash collateral with a counterparty with which the right of offset exists.

Level 2 Fair Value Measurements

Derivative contracts-The fair values of the Company’s crude oil swaps are measured internally using established index prices and other sources. These are based upon, among other things, futures prices and time to maturity.

Asset Retirement and Environmental Obligations

The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410, “Asset Retirement and Environmental Obligations” (“FASB ASC 410”). The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 4 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred were $36,543 and $86,588 during the three months ended March 31, 2012 and 2011, respectively.

10. Related Party Transactions

Administrative Services

An entity under common management provided technical, administrative and payroll services to the Company under a shared services agreement which began January 1, 2008. Through December 31, 2011, amounts charged to the Company included those costs directly attributable to the Company as well as indirect costs allocated to the Company. The reimbursement amount for indirect costs is determined by the affiliate’s management based on estimates of time devoted to the Company. During the three months ended March 31, 2012 and 2011, the Company incurred total costs of $2,449,792 and $2,725,096, respectively. Costs incurred unrelated to drilling activities are expensed and costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties have been capitalized. The expensed costs were partially offset in general and administrative expenses by operator overhead reimbursements of $539,314 and $452,787 for the three months ended March 31, 2012 and 2011, respectively. As of March 31, 2012 and December 31, 2011, the Company owed the administrative services affiliate $577,206 and $769,278, respectively, and such amounts are included in accounts payable-related party in the accompanying consolidated balance sheets.

 

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Table of Contents

Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

 

Effective January 1, 2012, the Company entered into an additional shared services agreement with this entity. Under this agreement, the Company provides this entity and, at its request, certain of its affiliates, with consulting, technical and administrative services. The initial term of the additional shared services agreement is two years. Upon expiration of the initial term the agreement will continue on a month-to-month basis until cancelled by either party upon thirty days prior written notice. Costs that are attributable to and billed to other affiliates are reported as other income. For the three months ended March 31, 2012, costs that were attributable to and billed to other affiliates was $445,360, and at March 31, 2012, the Company had a receivable of $6,206 for such billings.

Operating Services

The Company operates all of the oil and natural gas properties in which it has a working and revenue interest. As operator of these properties, the Company is responsible for the daily operations, monthly operation billings and monthly revenue disbursements for the properties.

As of March 31, 2012, the Company had amounts due to affiliated parties related to revenue distributions payable of $2,562,738. As of December 31, 2011, amounts due to affiliated parties related to prepaid drilling costs of $209,906 and revenue distributions payable of $2,303,184. These amounts are included in accounts payable-related party in the accompanying consolidated balance sheets. Each of these affiliated parties is either controlled by or was an affiliate of Wexford.

As of March 31, 2012 and December 31, 2011, amounts due from affiliates related to joint interest billings and included in accounts receivable-related party in the accompanying consolidated balance sheets is $2,818,743 and $8,990,273, respectively. Each of these affiliated parties is either controlled by or was an affiliate of Wexford.

Drilling Services

Bison has performed drilling and field services for the Company under master drilling agreements. Under the Company’s most recent master drilling agreement with Bison, effective as of January 1, 2012, Bison committed to accept orders from the Company for the use of at least two of its rigs, and is currently providing drilling services to the Company using four of its rigs. This master drilling agreement is terminable by either party on 30 days prior written notice, although neither party will be relieved of its respective obligations arising from a drilling contract being performed prior to the termination of the master drilling agreement. For the three months ended March 31, 2012, the Company was billed $3,153,932 by Bison. The Company owed no amounts to Bison as of March 31, 2012 and $153,826 as of December 31, 2011.

Completion and Well Servicing Services

The Company contracted with an affiliate for certain of its well completion services. Effective August 24, 2011, the affiliate was sold to a non-related third party. While still an affiliate of the Company, the Company was billed $6,187,108 during the three months ended March 31, 2011. Such amounts are capitalized in oil and natural gas properties in the accompanying consolidated balance sheet. At March 31, 2012 and December 31, 2011, the entity was no longer a related party.

Marketing Services

The Company entered into an agreement on March 1, 2009 with an entity under common management that purchases and receives a significant portion of the Company’s oil volumes. Effective January 1, 2012 the

 

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Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

 

agreement with the affiliate was cancelled. The Company’s revenues from the affiliate were $9,296,654 during the three months ended March 31, 2011 and such amounts are included in oil sales in the accompanying consolidated statements of operations. As of December 31, 2011, the Company had an accounts receivable-related party balance with the affiliate of $4,132,316 and such amount is included in the accompanying consolidated balance sheets.

MidMar

The Company is party to a gas purchase agreement, dated May 1, 2009, as amended, with MidMar Gas LLC, or MidMar, an entity affiliated with Wexford that owns a gas gathering system and processing plant in the Permian Basin. Under this agreement, MidMar is obligated to purchase from the Company, and the Company is obligated to sell to MidMar, all of the gas conforming to certain quality specifications produced from certain of the Company’s Permian Basin acreage. Following the expiration of the initial ten-year term, the agreement will continue on a year-to-year basis until terminated by either party on 30 days written notice. Under the gas purchase agreement, MidMar is obligated to pay the Company 87% of the net revenue received by MidMar for all components of the Company’s dedicated gas, including the liquid hydrocarbons, and the sale of residue gas, in each case extracted, recovered or otherwise processed at MidMar’s gas processing plant, and 94.56% of the net revenue received by MidMar from the sale of such gas components and residue gas, extracted, recovered or otherwise processed at Chevron’s Headlee plant. For the three months ended March 31, 2012, MidMar paid the Company $812,551. For the three months ended March 31, 2011 MidMar, through its affiliate, paid the Company $307,316. As of March 31, 2012 and December 31, 2011, MidMar owed the Company $1,072,956 and $461,956, respectively, for the Company’s portion of the net proceeds from the sale of gas, gas products and residue gas.

Midland Lease

Effective May 15, 2011, the Company occupied corporate office space in Midland, Texas under a lease with a five-year term. The office space is owned by an entity controlled by an affiliate of Wexford. For the three months ended March 31, 2012, the Company paid $32,423 under this lease. The current monthly rent under the lease will increase approximately 4% annually on June 1 of each year during the lease term.

Oklahoma City Lease

Effective January 1, 2012, the Company occupied corporate office space in Oklahoma City, Oklahoma under a lease with a 67 month term. The office space is owned by an entity controlled by an affiliate of Wexford. For the three months ended March 31, 2012, the Company paid $123,633 under this lease. The current monthly rent under the lease will increase $2.00 per square foot on August 1, 2012 with no further escalations for the remaining term of the lease.

Reliance on Wexford

As discussed in Note 1, the Company is wholly owned by an investment fund which is controlled and managed by Wexford. Management believes the credit facility combined with the cash flow generated from operations will be sufficient to sustain the Company’s operations; however, if additional financing is required management will seek additional sources which could include Wexford.

 

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Index to Financial Statements

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

 

11. Commitments and Contingencies

The Company could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations.

In March 2011, the Company began leasing field office space in Midland, Texas from an unrelated party. The lease term is 84 months with equal monthly installments that escalate 3% annually on March 1st of each year. In May 2011, the Company began leasing corporate office space in Midland, Texas from an entity controlled by an affiliate of Wexford with a lease term of five years. In January 2012, the Company began leasing corporate office space in Oklahoma City, Oklahoma from an entity controlled by an affiliate of Wexford with a lease term of 67 months. (See Note 10)

Future minimum lease payments for these leases are as follows as of March 31, 2012:

 

2012		$	309,635
2013			422,629
2014			429,816
2015			438,179
2016			385,608
Thereafter			306,100
Total		$	2,291,967

Rent expense for the three months ended March 31, 2012 and 2011, was $163,073 and $8,067, respectively.

12. Subsequent Events

The Company has evaluated the period after March 31, 2012 through June 8, 2012, the date the financial statements were available to be issued, noting no subsequent events or transactions that required recognition or disclosure in the financial statements, other than noted below.

On May 10, 2012, the Company’s revolving credit agreement was amended to provide for the resignation of BNP Paribas, and the appointment of Wells Fargo Bank, N.A., as administrative agent for the lenders. The amendment also permitted certain restricted payments and subordinated debt in an initial principal amount not to exceed $30.0 million.

Effective May 14, 2012, the Company entered into a subordinated note agreement with Wexford. The note allows advances in the aggregate amount up to $25,000,000. The unpaid principal balance and all accrued interest on the note, unless sooner paid, are due and payable in full on January 31, 2015. The note bears interest at a rate equal to LIBOR plus .28 percent or 8% per annum, whichever is lower. Interest is due quarterly in arrears beginning on July 1, 2012. On May 14, 2012 the company received an advance of $8,100,000 under this loan agreement.

 

F-49

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Index to Financial Statements

Report of Independent Certified Public Accountants

Members

Windsor UT LLC

We have audited the accompanying balance sheets of Windsor UT LLC (a Delaware limited liability company) as of December 31, 2011 and 2010, and the related statements of operations, changes in members’ equity and cash flows for the year ended December 31, 2011 and the period from inception (April 28, 2010) to December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America established by the American Institute of Certified Public Accountants. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Windsor UT LLC as of December 31, 2011 and 2010, and the results of its operations and its cash flows for the year ended December 31, 2011 and the period from inception (April 28, 2010) to December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.

/s/ Grant Thornton LLP

Oklahoma City, Oklahoma

May 1, 2012

 

F-50

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Index to Financial Statements

Windsor UT LLC

Balance Sheets

 

		December 31,
		2011				2010
Assets
Current assets:
Cash and cash equivalents		$	156,733			$	29,536
Accounts receivable-related party			214,633				—
Total current assets			371,366				29,536
Property and equipment
Oil and natural gas properties, at cost, based on the full cost method of accounting ($2,796,065 and $7,144,265 excluded from amortization at December 31,2011 and 2010, respectively)			14,321,344				9,458,667
Accumulated depletion, depreciation and amortization			(198,712	)			—
			14,122,632				9,458,667
Prepaid drilling costs-related party			—				251,715
Total assets		$	14,493,998			$	9,739,918
Liabilities and Members’ Equity
Current liabilities:
Accounts payable and accrued liabilities		$	395			$	1,100
Accounts payable–related party			279,988				15,849
Total current liabilities			280,383				16,949
Asset retirement obligations			24,267				14,436
Total liabilities			304,650				31,385
Commitments and contingencies (Note 6)
Members’ equity			14,189,348				9,708,533
Total liabilities and members’ equity		$	14,493,998			$	9,739,918

See accompanying notes to financial statements.

 

F-51

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Index to Financial Statements

Windsor UT LLC

Statements of Operations

 

		Year Ended December 31, 2011				Period from Inception (April 28, 2010) to December 31, 2010
Revenues:
Oil sales-related party		$	694,666			$	—
Total revenues			694,666				—
Costs and expenses:
Lease operating expenses			251,824				—
Production taxes			32,016				—
Depreciation, depletion and amortization			198,712				—
General and administrative expenses			37,044				—
Asset retirement obligation accretion expense			1,255				—
Total costs and expenses			520,851				—
Net income		$	173,815			$	—

See accompanying notes to financial statements.

 

F-52

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Index to Financial Statements

Windsor UT LLC

Statement of Changes in Members’ Equity

 

		Total members’ equity
Balance at inception (April 28, 2010)		$	—
Contributions			9,708,533
Balance at December 31, 2010			9,708,533
Contributions			4,307,000
Net income			173,815
Balance at December 31, 2011		$	14,189,348

See accompanying notes to financial statements.

 

F-53

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Index to Financial Statements

Windsor UT LLC

Statements of Cash Flows

 

		Year Ended December 31, 2011				Period from Inception (April 28, 2010) to December 31, 2010
Cash flows from operating activities:
Net income		$	173,815			$	—
Adjustments to reconcile net income to net cash provided by operating activities:
Asset retirement obligation accretion expense			1,255				—
Depreciation, depletion, and amortization			198,712				—
Changes in operating assets and liabilities:
Accounts receivable-related party			(214,633	)			—
Accounts payable and accrued liabilities			(705	)			1,100
Accounts payable and accrued liabilities-related party			55,102				15,849
Net cash provided by operating activities			213,546				16,949
Cash flows from investing activities:
Additions to oil and natural gas properties-related party			(4,393,349	)			(2,102,413	)
Net cash used in investing activities			(4,393,349	)			(2,102,413	)
Cash flows from financing activities:
Contributions by members			4,307,000				2,115,000
Net cash provided by financing activities			4,307,000				2,115,000
Net increase in cash and cash equivalents			127,197				29,536
Cash and cash equivalents at beginning of period			29,536				—
Cash and cash equivalents at end of period		$	156,733			$	29,536
Supplemental cash flow information
Asset retirement obligation incurred, including changes in estimate		$	8,576			$	14,436
Property contributed		$	—			$	7,593,533

See accompanying notes to financial statements.

 

F-54

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Index to Financial Statements

Windsor UT LLC

Notes to Financial Statements

1. Organization

Windsor UT LLC (“the Company”) is a limited liability company formed on April 28, 2010 to acquire, produce, develop and exploit oil and natural gas properties. As a limited liability company, the members of the Company are not liable for the liabilities or other obligations of the Company. The Company is wholly owned by investment funds which are controlled and managed by Wexford Capital LP (“Wexford”).

The Company is engaged in the acquisition, exploitation, development and production of oil and natural gas properties and related sale of oil, natural gas and natural gas liquids. The Company’s reserves are located in the Southern region of the United States. The Company’s results of operations are largely dependent on the difference between the prices received for its oil, natural gas and natural gas liquids and the cost to find, develop, produce and market such resources. Oil and natural gas prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond the Company’s control. These factors include worldwide political instability, quantity of natural gas in storage, foreign supply of oil and natural gas, the price of foreign imports, the level of consumer demand and the price of available alternative fuels, among others. The Company was a development stage enterprise at December 31, 2010.

2. Summary of Significant Accounting Policies

The Company’s financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America.

Use of estimates

Certain amounts included in or affecting the Company’s financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates.

The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved reserve quantities and related estimates of the present value of future net revenues, the carrying value of oil and gas properties and asset retirement obligations.

Cash and Cash Equivalents

The Company considers all highly liquid debt instruments purchased with a maturity of three months or less and money market funds to be cash equivalents.

Accounts Receivable

Accounts receivable consist primarily of receivables for oil and natural gas production delivered to purchasers. Those purchasers remit payment for production to the operator of the respective producing properties and the operator, in turn, remits payment to the Company. As discussed in Note 5, the Company’s oil and natural gas properties are contractually operated by an affiliate. Most payments are received within three months after the production date.

 

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Index to Financial Statements

Windsor UT LLC

Notes to Financial Statements-(Continued)

 

Accounts receivable are stated at amounts due from purchasers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2011 or 2010.

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, receivables and payables. The carrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of the instruments.

Oil and Natural Gas Properties

The Company accounts for its oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves. The average depletion rate per barrel equivalent unit of production was $26.11 for the year ended December 31, 2011 and because the Company did not have any production in 2010 there was no depletion for the period ended December 31, 2010. Depreciation, depletion and amortization expense for oil and natural gas properties was $198,712 for the year ended December 31, 2011, and there was no expense for the period ended December 31, 2010.

The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment exceed the discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. No impairment on proved oil and natural gas properties was recorded for the periods ended December 31, 2011 or 2010.

Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company assesses all items classified as unevaluated property on an annual basis for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within three years.

 

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Index to Financial Statements

Windsor UT LLC

Notes to Financial Statements-(Continued)

 

Revenue Recognition

Oil and natural gas revenues are recorded when title passes to the purchaser, net of royalty interests, discounts and allowances, as applicable. The Company accounts for oil and natural gas production imbalances using the sales method, whereby a liability is recorded when the Company’s overtake volumes exceed its estimated remaining recoverable reserves. No receivables are recorded for those wells where the Company has taken less than its ownership share of production. The Company did not have any gas imbalances as of December 31, 2011 and 2010.

Concentrations

During the year period ended December 31, 2011, the Company sold its production to one purchaser. Windsor Midstream LLC, an entity controlled by Wexford, accounted for 100% of the oil revenue. The Company believes there are other crude oil purchasers to whom it would be able to sell its oil if the current purchaser discontinued purchasing from the Company.

Environmental Compliance and Remediation

Environmental compliance and remediation costs, including ongoing maintenance and monitoring, are expensed as incurred. Liabilities are accrued when environmental assessments and remediation are probable, and the costs can be reasonably estimated.

Income Taxes

The operations of the Company, as a limited liability company, is not subject to federal income taxes. As appropriate, the taxable income or loss applicable to operations is included in the federal income tax returns of the respective owners and no income tax effect is included in the accompanying financial statements. The Company is subject to margin tax in the state of Texas. During the periods ended December 31, 2011 and 2010, there was no margin tax expense. The Company’s 2010 federal income tax and state margin tax returns remain open to examination by tax authorities. As of December 31, 2011 and 2010, the Company has no unrecognized tax benefits that would have a material impact on the effective rate. The Company is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the periods ended December 31, 2011 and 2010 there was no interest or penalties associated with uncertain tax positions in the Company’s financial statements.

Recently issued accounting standards

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS,” which provides a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between U.S. GAAP and International Financial Reporting Standards. This new guidance changes some fair value measurement principles and disclosure requirements, but does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. The update is effective for annual periods beginning after December 15, 2011. The adoption of this guidance will not have a significant impact on the Company’s financial position, results of operations or cash flow.

 

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Windsor UT LLC

Notes to Financial Statements-(Continued)

 

In June 2011, the FASB issued Accounting Standards Update No. 2011-05, “Comprehensive Income: Presentation of Comprehensive Income,” which provides amendments to FASB ASC Topic 220, “Comprehensive Income” (“FASB ASC 220”). The purpose of the amendments in this update is to provide a more consistent method of presenting non-owner transactions that affect an entity’s equity. The amendments eliminate the option to report other comprehensive income and its components in the statement of changes in equity and require an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. In December 2011, the FASB issued Accounting Standards Update 2011-12 which defers the requirement in Accounting Standards Update 2011-05 that companies present reclassification adjustments for each component of accumulated other comprehensive income in both net income and other comprehensive income on the face of the financial statements. Both amendments are effective for interim and annual periods beginning after December 15, 2011 and should be applied retrospectively. The adoption of this guidance will not have a significant impact on the Company’s financial position, results of operations or cash flow.

3. Property and Equipment

Property and equipment includes the following:

 

		December 31,
		2011				2010
Oil and natural gas properties:
Subject to depletion		$	11,525,279			$	2,314,402
Not subject to depletion-acquisition costs
Incurred in 2011			490,007				—
Incurred in 2010			2,306,058				7,144,265
Total not subject to depletion			2,796,065				7,144,265
Gross oil and natural gas properties			14,321,344				9,458,667
Less accumulated depreciation, depletion and amortization			(198,712	)			—
Oil and natural gas properties, net		$	14,122,632			$	9,458,667

4. Asset Retirement Obligations

The Company measures the future cost to retire its tangible long-lived assets and recognizes such cost as a liability in accordance with ASC Topic 410, Asset Retirement and Environmental Obligations (“ASC Topic 410”), which provides accounting and reporting guidance for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset.

ASC Topic 410 requires companies to record a liability relating to the retirement and removal of assets used in their businesses. For the Company, asset retirement obligations represent the future abandonment costs of tangible assets, namely wells. ASC Topic 410 requires that the fair value of a liability for an asset’s retirement obligation be recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and that the corresponding cost be capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, the difference is recorded in oil and natural gas properties.

 

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Index to Financial Statements

Windsor UT LLC

Notes to Financial Statements-(Continued)

 

A reconciliation of the asset retirement obligation is as follows:

 

		Year Ended December 31, 2011				Period from Inception (April 28, 2010) to December 31, 2010
Asset retirement obligation, beginning of period		$	14,436			$	—
Additional liability incurred			8,576				14,436
Accretion expense			1,255				—
Asset retirement obligation, end of period			24,267				14,436
Less current portion			—				—
Asset retirement obligation, long-term		$	24,267			$	14,436

5. Related Party Transactions

Administrative Services

An entity under common management provided technical, administrative and payroll services to the Company under a shared services agreement which began April 28, 2010. The reimbursement amount for indirect expenses is determined by the affiliate’s management based on estimates of office space provided and time devoted to the Company. During the periods ended December 31, 2011 and 2010, the Company incurred total costs of $90,127 and $12,879, respectively. Costs incurred unrelated to drilling activities are expensed and costs incurred in the acquisition, exploration, and development of oil and natural gas properties have been capitalized. The expensed costs were partially offset in general and administrative expenses by overhead reimbursements of $57,250 and $14,437 for the periods ended December 31, 2011 and 2010, respectively which were received through the related party operator discussed below. As of December 31, 2011 and December 31, 2010, the Company owed the administrative services affiliate $3,864 and $709, respectively and such amounts are included in accounts payable-related party in the accompanying balance sheets.

Operating Services

An entity under common management operates the oil and natural gas properties in which the Company has working and revenue interests. As operator of these properties, this entity is responsible for the daily operations, monthly operation billings and monthly revenue disbursements for the properties. As of December 31, 2011 and 2010 the Company has an accounts payable balance to this entity of $276,124 and $15,140, respectively.

As of December 31, 2010, $251,715 was prepaid to the operator for prepaid drilling costs and as of December 31, 2011 there were no amounts prepaid for drilling costs to the operator. This amount is included in prepaid drilling costs-related party in the accompanying balance sheets.

Marketing Services

An entity under common management purchases and receives all of the Company’s oil volumes. The Company’s revenues from the affiliate during year ended December 31, 2011 were $694,666. As of December 31, 2011 the Company had an accounts receivable balance with the affiliate of $214,633.

Reliance on Wexford

As discussed in Note 1, the Company is wholly owned by investment funds which are controlled and managed by Wexford. Management believes cash flows generated from operations will be sufficient to sustain the Company’s

 

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Index to Financial Statements

Windsor UT LLC

Notes to Financial Statements-(Continued)

 

operations through the end of 2012; however, if additional financing is required to continue to develop our properties management will seek additional sources which could include Wexford.

6. Commitments and Contingencies

The Company could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations.

7. Subsequent Events

The Company has evaluated the period after December 31, 2011 through May 1, 2012 the date the financial statements were available to be issued, noting no subsequent events or transactions that required recognition or disclosure in the financial statements, other than noted below.

Wexford has agreed in principle to cause all the outstanding equity interests in the Company to be contributed to Windsor Permian LLC, an entity under common control. This contribution will close prior to the initial public offering of Diamondback Energy Inc. who will be the parent of Windsor Permian LLC.

8. Supplemental Information on Oil and Natural Gas Operations (Unaudited)

The following supplemental unaudited information regarding the oil and natural gas activities of the Company is presented pursuant to the disclosure requirements promulgated by the United States Securities and Exchange Commission (the “SEC”) and the FASB ASU 2010-03, “Extractive Activities-Oil and Gas (Topic 932)”. The reserve reports were prepared in accordance with guidelines established by the SEC and, accordingly, were based on existing economic and operating conditions.

Proved oil and natural gas reserve estimates as of December 31, 2010 were prepared by Pinnacle Energy Services, LLC and as of December 31, 2011 were prepared by Ryder Scott Company L.P., both independent petroleum engineers.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

The Company’s oil and natural gas reserves are attributable solely to properties within the United States.

 

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Index to Financial Statements

Windsor UT LLC

Notes to Financial Statements-(Continued)

 

Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows:

 

		Year Ended December 31,
		2011				2010
Acquisition costs:
Proved properties		$	—			$	—
Unproved properties			490,029				7,536,554
Development costs			2,712,638				1,381,594
Exploration costs			1,651,434				526,083
Capitalized asset retirement costs			8,576				14,436
Total		$	4,862,677			$	9,458,667

Results of Operations from Oil and Natural Gas Producing Activities

The Company’s results of operations from oil and natural gas producing activities are presented below for year ended December 31, 2011. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to net operating results of our oil, natural gas and natural gas liquids operations.

 

		Year Ended December 31, 2011
Oil sales		$	694,666
Lease operating expenses			(251,824	)
Production taxes			(32,016	)
Depreciation, depletion and amortization			(198,712	)
Results of operations from oil, natural gas and natural gas liquids		$	212,114

 

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Index to Financial Statements

Windsor UT LLC

Notes to Financial Statements-(Continued)

 

Oil and Natural Gas Reserves

The changes in estimated proved reserves are as follows:

 

		Oil (Bbls)				Natural  Gas Liquids (Bbls)				Natural  Gas (Mcf)
Proved Developed and Undeveloped Reserves:
As of Inception (April 28, 2010)
Extensions and discoveries			811,110				268,989				1,032,360
Revisions of previous estimates			—				—				—
Purchase of reserves in place			—				—				—
Production			—				—				—
Sales of reserves in place			—				—				—
As of December 31, 2010			811,110				268,989				1,032,360
Extensions and discoveries			93,495				18,373				59,855
Revisions of previous estimates			486,613				(1,076	)			(159,615	)
Purchase of reserves in place			—				—				—
Production			(7,611	)			—				—
Sales of reserves in place			—				—				—
As of December 31, 2011			1,383,607				286,286				932,600
Proved Developed Reserves:
December 31, 2010			63,910				21,215				81,420
December 31, 2011			143,808				30,392				99,004
Proved Undeveloped Reserves:
December 31, 2010			747,200				247,774				950,940
December 31, 2011			1,239,799				255,894				833,596

As of December 31, 2011 and 2010 reserves were computed using the trailing 12-month unweighted average of the first-day-of-the-month prices, in accordance with the SEC guidelines applicable to reserves estimates.

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

Standardized Measure of Discounted Future Net Cash Flows

The following information has been prepared in accordance with the provisions of the FASB ASU 2010-03, “Extractive Activities—Oil and Gas (Topic 932).” As of December 31, 2011 and 2010 the standardized measure of discounted future net cash flows are based on the trailing 12-month unweighted average, first-day-of-the-month prices.

The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.

 

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Index to Financial Statements

Windsor UT LLC

Notes to Financial Statements-(Continued)

 

The Company’s investment and operating decisions are not based on the information presented, but on a wide range of reserve estimates that include probable as well as proved reserves and on different price and cost assumptions.

The standardized measure is intended to provide a better means for comparing the value of the Company’s proved reserves at a given time with those of other oil and gas producing companies than is provided by a comparison of raw proved reserve quantities.

 

		December 31,
		2011(1)				2010
Future cash inflows		$	148,561,281			$	79,406,680
Future development costs			(36,600,000	)			(22,100,000	)
Future production costs			(38,872,202	)			(19,203,120	)
Future production taxes			(7,410,910	)			(4,102,820	)
Future net cash flows			65,678,169				34,000,740
10% discount to reflect timing of cash flows			(48,085,065	)			(25,357,600	)
Standardized measure of discounted future net cash flows		$	17,593,104			$	8,643,140

 

(1)	2011 amounts have been revised from those previously reported to reflect reserve report changes, primarily relating to the timing of development of proved undeveloped reserves.

In the table below the average price for oil, natural gas and natural gas liquids is presented, all utilized in the computation of future cash inflows.

 

		December 31,
		2011				2010
Oil (per Bbl)		$	92.99			$	78.76
Natural gas (per Mcf)		$	3.92			$	4.26
Natural gas liquids (per Bbl)		$	56.74			$	41.34

 

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Index to Financial Statements

Windsor UT LLC

Notes to Financial Statements-(Continued)

 

Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows:

 

		Year Ended December 31,
		2011				2010
Standardized measure of discounted future net cash flows at the beginning of the period		$	8,643,140			$	—
Sales of oil and natural gas, net of production costs			(410,826	)			—
Net changes in prices and production costs			1,883,765				—
Purchase of minerals in place			—				—
Previously estimated development costs incurred during the period			4,364,072				1,907,677
Extensions and discoveries, net of future development costs			4,195,434				6,735,463
Change in estimated future development costs			(5,864,072	)			—
Revisions of previous quantity estimates			1,899,993				—
Sales of reserves in place			—				—
Accretion of discount			864,314				—
Net changes in timing of production and other(1)			2,017,284				—
Standardized measure of discounted future net cash flows at the end of the period(1)		$	17,593,104			$	8,643,140

 

(1)	2011 amounts have been revised from those previously reported to reflect reserve report changes, primarily relating to the timing of development of proved undeveloped reserves.

 

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Windsor UT LLC

Balance Sheets

 

		March 31, 2012				December 31, 2011
		(Unaudited)
Assets
Current assets:
Cash and cash equivalents		$	199,390			$	156,733
Accounts receivable-oil sales			123,673				—
Accounts receivable-related party			—				214,633
Total current assets			323,063				371,366
Property and equipment
Oil and natural gas properties, at cost, based on the full cost method of accounting ($2,796,065 excluded from amortization at both March 31, 2012 and December 31, 2011, respectively)			14,412,961				14,321,344
Accumulated depletion, depreciation and amortization			(290,860	)			(198,712	)
		$	14,122,101			$	14,122,632
Total assets		$	14,445,164			$	14,493,998
Liabilities and Members’ Equity
Current liabilities:
Accounts payable and accrued liabilities		$	—			$	395
Accounts payable and accrued liabilities–related party			112,820				279,988
Total current liabilities			112,820				280,383
Asset retirement obligations			24,716				24,267
Total liabilities			137,536				304,650
Commitments and contingencies (Note 6)
Members’ equity			14,307,628				14,189,348
Total liabilities and members’ equity		$	14,445,164			$	14,493,998

 

See accompanying notes to financial statements.

 

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Windsor UT LLC

Statements of Operations

(Unaudited)

 

		For the Three Months Ended March 31,
		2012				2011
Revenues:
Oil sales		$	346,900			$	—
Oil sales–related party			—				12,453
Total revenues			346,900				12,453
Costs and expenses:
Lease operating expenses			107,284				20,366
Production taxes			15,986				—
Production taxes–related party			—				574
Depreciation, depletion and amortization			92,148				2,580
General and administrative expenses			12,666				—
General and administrative expenses–related party			87				—
Asset retirement obligation accretion expense			449				268
Total costs and expenses			228,620				23,788
Net income (loss)		$	118,280			$	(11,335	)

 

 

See accompanying notes to financial statements.

 

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Windsor UT LLC

Statement of Changes in Members’ Equity

(Unaudited)

 

		Total members’ equity
Balance at January 1, 2012		$	14,189,348
Net income			118,280
Balance at March 31, 2012		$	14,307,628
Balance at January 1, 2011		$	9,708,533
Contributions			1,182,000
Net loss			(11,335	)
Balance at March 31, 2011		$	10,879,198

See accompanying notes to financial statements.

 

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Windsor UT LLC

Statements of Cash Flows

(Unaudited)

 

		For the Three Months Ended March 31,
		2012				2011
Cash flows from operating activities:
Net income (loss)		$	118,280			$	(11,335	)
Adjustments to reconcile net income (loss) to net cash (used) provided by operating activities:
Asset retirement obligation accretion expense			449				268
Depreciation, depletion, and amortization			92,148				2,580
Changes in operating assets and liabilities:
Accounts receivable			90,960				(11,879	)
Accounts payable and accrued liabilities			(395	)			—
Accounts payable and accrued liabilities-related party			(11,432	)			16,720
Net cash provided by (used in) operating activities			290,010				(3,646	)
Cash flows from investing activities:
Additions to oil and natural gas properties-related party			(247,353	)			—
Net cash used in investing activities			(247,353	)			—
Cash flows from financing activities:
Contributions by members			—				1,182,000
Net cash provided by financing activities			—				1,182,000
Net increase in cash and cash equivalents			42,657				1,178,354
Cash and cash equivalents at beginning of period			156,733				29,536
Cash and cash equivalents at end of period		$	199,390			$	1,207,890

See accompanying notes to financial statements.

 

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Windsor UT LLC

Notes to Financial Statements

(Unaudited)

1. Organization

Windsor UT LLC (“the Company”) is a limited liability company formed on April 28, 2010 to acquire, produce, develop and exploit oil and natural gas properties. As a limited liability company, the members of the Company are not liable for the liabilities or other obligations of the Company. The Company is wholly owned by investment funds which are controlled and managed by Wexford Capital LP (“Wexford”).

The Company is engaged in the acquisition, exploitation, development and production of oil and natural gas properties and related sale of oil, natural gas and natural gas liquids. The Company’s reserves are located in the Southern region of the United States. The Company’s results of operations are largely dependent on the difference between the prices received for its oil, natural gas and natural gas liquids and the cost to find, develop, produce and market such resources. Oil and natural gas prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond the Company’s control. These factors include worldwide political instability, quantity of natural gas in storage, foreign supply of oil and natural gas, the price of foreign imports, the level of consumer demand and the price of available alternative fuels, among others.

2. Summary of Significant Accounting Policies

The Company’s financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America.

The accompanying unaudited financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information. Pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, the accompanying unaudited financial statements include all adjustments (consisting of normal and recurring accruals) considered necessary to present fairly our financial position as of March 31, 2012, and our results of operations, changes in members’ equity and cash flows for the three months ended March 31, 2012 and 2011. Operating results for the three months ended March 31, 2012 are not necessarily indicative of the results that may be expected for the full year because of the impact of fluctuations in prices received for natural gas and oil, natural production declines, timing of development and exploration activities, the uncertainty of exploration and development drilling results and other factors. For a more complete understanding of our operations, financial position and accounting policies, these financial statements should be read in conjunction with our annual financial statements.

Use of estimates

Certain amounts included in or affecting the Company’s financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities at the date of the financial statements. Actual results could differ from those estimates.

The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in

 

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Windsor UT LLC

Notes to Financial Statements-(Continued)

(Unaudited)

 

which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved reserve quantities and related estimates of the present value of future net revenues, the carrying value of oil and gas properties and asset retirement obligations.

Cash and Cash Equivalents

The Company considers all highly liquid debt instruments purchased with a maturity of three months or less and money market funds to be cash equivalents.

Accounts Receivable

Accounts receivable consist primarily of receivables for oil and natural gas production delivered to purchasers. Those purchasers remit payment for production to the operator of the respective producing properties and the operator, in turn, remits payment to the Company. As discussed in Note 5, the Company’s oil and natural gas properties are contractually operated by an affiliate. Most payments are received within three months after the production date.

Accounts receivable are stated at amounts due from purchasers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary at March 31, 2012 or December 31, 2011.

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, receivables and payables. The carrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of the instruments.

Oil and Natural Gas Properties

The Company accounts for its oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration, and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves. The average depletion rate per barrel equivalent unit of production was $26.11 and $20.86 for the three months ended March 31, 2012 and 2011, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties was $92,148 and $2,580 for the three months ended March 31, 2012 and 2011, respectively.

The net capitalized costs of proved oil and natural gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the

 

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Windsor UT LLC

Notes to Financial Statements-(Continued)

(Unaudited)

 

extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment exceed the discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. No impairment on proved oil and natural gas properties was recorded for the three months ended March 31, 2012 or 2011.

Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The Company assesses all items classified as unevaluated property on an annual basis for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within three years.

Revenue Recognition

Oil and natural gas revenues are recorded when title passes to the purchaser, net of royalty interests, discounts and allowances, as applicable. The Company accounts for oil and natural gas production imbalances using the sales method, whereby a liability is recorded when the Company’s overtake volumes exceed its estimated remaining recoverable reserves. No receivables are recorded for those wells where the Company has taken less than its ownership share of production. The Company did not have any gas imbalances as of March 31, 2012 and December 31, 2011.

Concentrations

During the three months ended March 31, 2012, the Company the sold all of its production to one purchaser. During the three months ended March 31, 2011, the Company sold all of its production to one purchaser, Windsor Midstream LLC, an entity controlled by Wexford. The Company believes there are other crude oil purchasers to whom it would be able to sell its oil if the current purchaser discontinued purchasing from the Company.

Environmental Compliance and Remediation

Environmental compliance and remediation costs, including ongoing maintenance and monitoring, are expensed as incurred. Liabilities are accrued when environmental assessments and remediation are probable, and the costs can be reasonably estimated.

Income Taxes

The operations of the Company, as a limited liability company, is not subject to federal income taxes. As appropriate, the taxable income or loss applicable to operations is included in the federal income tax returns of the respective owners and no income tax effect is included in the accompanying financial statements. The Company is subject to margin tax in the state of Texas. During the three months ended March 31, 2012 and 2011, there was no margin tax expense. The Company’s 2011 and 2010 federal income tax and state margin tax returns remain open to examination by tax authorities. As of March 31, 2012 and December 31, 2011, the Company has

 

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Windsor UT LLC

Notes to Financial Statements-(Continued)

(Unaudited)

 

no unrecognized tax benefits that would have a material impact on the effective rate. The Company is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the three months ended March 31, 2012 and 2011, no interest or penalties associated with uncertain tax positions was recognized in the Company’s financial statements.

Recently issued accounting standards

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS,” which provides a consistent definition of fair value and common requirements for measurement of and disclosure about fair value between U.S. GAAP and International Financial Reporting Standards. This new guidance changes some fair value measurement principles and disclosure requirements, but does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. The update is effective for annual periods beginning after December 15, 2011. The adoption of this guidance will not have a significant impact on the Company’s financial position, results of operations or cash flow.

In June 2011, the FASB issued Accounting Standards Update No. 2011-05, “Comprehensive Income: Presentation of Comprehensive Income,” which provides amendments to FASB ASC Topic 220, “Comprehensive Income” (“FASB ASC 220”). The purpose of the amendments in this update is to provide a more consistent method of presenting non-owner transactions that affect an entity’s equity. The amendments eliminate the option to report other comprehensive income and its components in the statement of changes in equity and require an entity to present the total of comprehensive income, the components of net income and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. In December 2011, the FASB issued Accounting Standards Update 2011-12 which defers the requirement in Accounting Standards Update 2011-05 that companies present reclassification adjustments for each component of accumulated other comprehensive income in both net income and other comprehensive income on the face of the financial statements. Both amendments are effective for interim and annual periods beginning after December 15, 2011 and should be applied retrospectively. The adoption of this guidance did not have any impact on the Company’s financial position, results of operations or cash flow.

3. Property and Equipment

Property and equipment includes the following:

 

		March 31, 2012				December 31, 2011
Oil and natural gas properties:
Subject to depletion		$	11,616,896			$	11,525,279
Not subject to depletion-acquisition costs
Incurred in 2011			490,030				490,007
Incurred in 2010			2,306,035				2,306,058
Total not subject to depletion			2,796,065				2,796,065
Gross oil and natural gas properties			14,412,961				14,321,344
Less accumulated depreciation, depletion and amortization			(290,860	)			(198,712	)
Oil and natural gas properties, net		$	14,122,101			$	14,122,632

 

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Index to Financial Statements

Windsor UT LLC

Notes to Financial Statements-(Continued)

(Unaudited)

 

4. Asset Retirement Obligations

The Company measures the future cost to retire its tangible long-lived assets and recognizes such cost as a liability in accordance with ASC Topic 410, Asset Retirement and Environmental Obligations (“ASC Topic 410”), which provides accounting and reporting guidance for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset.

ASC Topic 410 requires companies to record a liability relating to the retirement and removal of assets used in their businesses. For the Company, asset retirement obligations represent the future abandonment costs of tangible assets, namely wells. ASC Topic 410 requires that the fair value of a liability for an asset’s retirement obligation be recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and that the corresponding cost be capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, the difference is recorded in oil and natural gas properties.

A reconciliation of the asset retirement obligation is as follows:

 

		For the Three Months Ended March 31,
		2012				2011
Asset retirement obligation, beginning of period		$	24,267			$	14,436
Additional liability incurred			—				—
Accretion expense			449				268
Asset retirement obligation, end of period			24,716				14,704
Less current portion			—				—
Asset retirement obligation, long-term		$	24,716			$	14,704

5. Related Party Transactions

Administrative Services

An entity under common management provided technical, administrative and payroll services to the Company under a shared services agreement which began April 28, 2010. The reimbursement amount for indirect expenses is determined by the affiliate’s management based on estimates of office space provided and time devoted to the Company. During the three months ended March 31, 2012 and 2011, the Company incurred total costs of $25,393 and $3,203, respectively. Costs incurred unrelated to drilling activities are expensed and costs incurred in the acquisition, exploration, and development of oil and natural gas properties have been capitalized. The expensed costs were partially offset in general and administrative expenses by overhead reimbursements of $12,727 and $0 for the three months ended March 31, 2012 and 2011, respectively which were received through the related party operator discussed below. As of March 31, 2012 and December 31, 2011, the Company owed the administrative services affiliate $26 and $3,864, respectively and such amounts are included in accounts payable-related party in the accompanying balance sheets.

Operating Services

An entity under common management operates the oil and natural gas properties in which the Company has working and revenue interests. As operator of these properties, this entity is responsible for the daily operations,

 

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Index to Financial Statements

Windsor UT LLC

Notes to Financial Statements-(Continued)

(Unaudited)

 

monthly operation billings and monthly revenue disbursements for the properties. As of March 31, 2012 and 2011 the Company has an accounts payable balance to this entity of $112,794 and $276,124, respectively.

Marketing Services

Through December 31, 2011 an entity under common management purchased and received all of the Company’s oil volumes. The Company’s revenues from the affiliate during three months ended March 31, 2011 were $12,453. As of December 31, 2011 the Company had an accounts receivable balance with the affiliate of $214,633. Effective January 1, 2012 the agreement with the affiliate was terminated and none of the Company’s oil volumes are sold to the affiliate.

Reliance on Wexford

As discussed in Note 1, the Company is wholly owned by investment funds which are controlled and managed by Wexford. Management believes cash flows generated from operations will be sufficient to sustain the Company’s operations through the end of 2012; however, if additional financing is required to continue to develop our properties management will seek additional sources which could include Wexford.

6. Commitments and Contingencies

The Company could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations.

7. Subsequent Events

The Company has evaluated the period after March 31, 2012 through June 8, 2012, the date the financial statements were available to be issued, noting no subsequent events or transactions that required recognition or disclosure in the financial statements, other than noted below.

Wexford has agreed in principle to cause all the outstanding equity interests in the Company to be contributed to Windsor Permian LLC, an entity under common control. This contribution will close prior to the initial public offering of Diamondback Energy Inc., who will be the parent of Windsor Permian LLC.

 

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Index to Financial Statements

Report of Independent Certified Public Accountants

Board of Directors

Gulfport Energy Corporation

We have audited the accompanying statements of revenues and direct operating expenses of working and revenue interests of certain oil and gas properties (the “Properties”) owned by Gulfport Energy Corporation (“Gulfport”) for the years ended December 31, 2011 and 2010. These statements are the responsibility of Gulfport’s management. Our responsibility is to express an opinion on these statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America established by the American Institute of Certified Public Accountants. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Properties’ internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the statements. We believe that our audits provide a reasonable basis for our opinion.

As described in Note A, the accompanying statements are prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and is not intended to be a complete financial presentation.

In our opinion, the statements referred to above present fairly, in all material respects, the revenues and direct operating expenses as described in Note A for the years ended December 31, 2011 and 2010.

/s/ Grant Thornton LLP

Oklahoma City, Oklahoma

April 24, 2012

 

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Index to Financial Statements

CERTAIN PROPERTY INTERESTS OF

GULFPORT ENERGY CORPORATION

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

 

		Year Ended December 31,
		2011				2010
Revenues:
Oil and gas sales		$	23,052,000			$	14,088,000
Direct operating expenses
Lease operating expenses			5,484,000				2,375,000
Production taxes			1,276,000				806,000
Total direct operating expenses			6,760,000				3,181,000
Revenues in excess of direct operating expenses		$	16,292,000			$	10,907,000

 

See accompanying notes to statements of revenues and direct operating expenses.

 

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Index to Financial Statements

CERTAIN PROPERTY INTERESTS OF

GULFPORT ENERGY CORPORATION

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010

NOTE A—BASIS OF PRESENTATION

The accompanying statements present the revenues and direct operating expenses of working and revenue interests of certain oil and natural gas properties located in the Permian Basin of West Texas (the “Properties”) owned by Gulfport Energy Corporation (“Gulfport”) for the years ended December 31, 2011 and 2010.

The accompanying statements of revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from the historical accounting records of Gulfport. Such amounts may not be representative of future operations. The statements do not include depreciation, depletion and amortization, general and administrative expenses, income taxes or interest expense.

Historical financial statements reflecting financial position, results of operations and cash flows required by accounting principles generally accepted in the United States of America are not presented as such information is not readily available on an individual property basis. Accordingly, the historical statements of revenues and direct operating expenses of the Properties are presented in lieu of the financial statements required under Rule 3-05 of the Securities and Exchange Commission Regulation S-X.

NOTE B—SIGNIFICANT ACCOUNTING POLICIES

Use of estimates

The preparation of the accompanying statements in conformity with generally accepted accounting principles requires making estimates and assumptions that affect the reported amounts of revenues and direct operating expenses during the reporting period. The estimates include oil and gas revenue accruals and reserve quantities. It is emphasized that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Actual results could materially differ from these estimates.

Revenue recognition

Oil and natural gas revenues are recorded when title passes to the purchaser, net of royalty interests, discounts and allowances, as applicable.

NOTE C—SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)

The proved oil and gas reserves attributable to the Properties consist of the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The weighted average prices used for reserve report purposes are $96.19 and $4.12 for December 31, 2011 and $79.43 and $4.38 at December 31, 2010, adjusted for transportation fees and regional price differentials, for oil and natural gas reserves, respectively. The following estimates of proved reserves have been made by the independent engineering firms of Ryder Scott Company L.P. and Pinnacle Energy Services, LLC based on the Gulfport’s net revenue interest for 2011 and 2010, respectively.

Oil and gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either

 

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Index to Financial Statements

CERTAIN PROPERTY INTERESTS OF

GULFPORT ENERGY CORPORATION

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010-(CONTINUED)

 

upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. Reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

 

		2011								2010
		Oil (MBbls)				Gas (MMcf)				Oil (MBbls)				Gas (MMcf)
Proved Reserves
Beginning of the period			12,465				11,926				9,763				10,894
Purchases in oil and gas reserves in place			—				—				3,566				3,341
Extensions and discoveries			981				992				3,701				3,512
Revisions of prior reserve estimates			(2,302	)			(599	)			(4,365	)			(5,565	)
Current production			(267	)			(272	)			(200	)			(256	)
End of period			10,877				12,047				12,465				11,926
Proved developed reserves			2,803				3,050				2,634				3,048
Proved undeveloped reserves			8,074				8,997				9,831				8,878

Proved developed reserves as of January 1, 2010 were 1,560 MBbls of oil and 2,009 MMcf of gas and proved undeveloped reserves as of January 1, 2010 were 8,203 MBbls of oil and 8,885 MMcf of gas.

Standardized measure of discounted future net cash flows

The standardized measure of discounted future net cash flows is computed by applying unweighted average first-of-the-month prices of oil and natural gas, adjusted for transportation fees and regional price differentials, to the estimated future production of proved oil and gas reserves less estimated future expenditures (based on certain prevailing economic conditions) to be incurred in developing and producing the proved reserves, discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. Income taxes are excluded because the property interests included represent only a portion of a business for which income taxes are not estimable.

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and gas properties. Estimates of fair value would also take into account, among other things, probable and possible reserves, anticipated future oil and natural gas prices, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.

 

		Year ended December 31,
		2011				2010
Future cash flows		$	960,918,000			$	902,221,000
Future development and abandonment costs			(236,336,000	)			(196,265,000	)
Future production costs			(166,899,000	)			(208,210,000	)
Future production taxes			(50,235,000	)			(46,605,000	)
Future net cash flows			507,448,000				451,141,000
10% discount to reflect timing of cash flows			(305,160,000	)			(289,035,000	)
Standardized measure of discounted future net cash flows		$	202,288,000			$	162,106,000

 

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Index to Financial Statements

CERTAIN PROPERTY INTERESTS OF

GULFPORT ENERGY CORPORATION

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010-(CONTINUED)

 

Changes in standardized measure of discounted future net cash flows

 

		Year ended December 31,
		2011				2010
Sales and transfers of oil and gas produced, net of production costs		$	(16,292,000	)		$	(10,907,000	)
Net changes in prices and production costs			72,822,000				49,867,000
Changes in estimated future development costs			(24,733,000	)			(12,655,000	)
Acquisition of oil and gas reserves in place			—				81,901,000
Extensions and discoveries			29,432,000				84,971,000
Revisions of previous quantity estimates, less related production costs			(71,088,000	)			(99,257,000	)
Development costs incurred that reduced future development costs			30,888,000				10,000,000
Accretion of discount			16,211,000				9,143,000
Change in production rates and other			2,942,000				(42,389,000	)
Total change in standardized measure of discounted future net cash flows		$	40,182,000			$	70,674,000
Balance at beginning of year		$	162,106,000			$	91,432,000
Balance at end of year		$	202,288,000			$	162,106,000

NOTE D—SUBSEQUENT EVENTS

Gulfport has evaluated the period after December 31, 2011 through April 24, 2012, the date the statements of revenues and direct operating expenses were available to be issued, noting no subsequent events or transactions that required recognition or disclosure in the statements of revenues and direct operating expenses.

 

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Index to Financial Statements

CERTAIN PROPERTY INTERESTS OF

GULFPORT ENERGY CORPORATION

STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

(Unaudited)

 

		3 Months Ended March 31,
		2012				2011
Revenues:
Oil and gas sales		$	7,270,000			$	4,807,000
Direct operating expenses
Lease operating expenses			2,052,000				915,000
Production taxes			376,000				262,000
Total direct operating expenses			2,428,000				1,177,000
Revenues in excess of direct operating expenses		$	4,842,000			$	3,630,000

See accompanying notes to statements of revenues and direct operating expenses.

 

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Index to Financial Statements

CERTAIN PROPERTY INTERESTS OF

GULFPORT ENERGY CORPORATION

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

FOR THE THREE MONTHS ENDED MARCH 31, 2012 AND 2011

(Unaudited)

These statements of revenues and direct operating expenses have been prepared by Gulfport Energy Corporation (“Gulfport”) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission, and reflect all adjustments which, in the opinion of management, are necessary for a fair presentation of the results for the interim periods, on a basis consistent with the annual audited statements of revenues and direct operating expenses. All such adjustments are of a normal recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. These statements of revenues and direct operating expenses should be read in conjunction with the annual statements of revenues and direct operating expenses and notes. Results for the three month period ended March 31, 2012 are not necessarily indicative of the results expected for the full year.

NOTE A—BASIS OF PRESENTATION

The accompanying statements present the revenues and direct operating expenses of working and revenue interests of certain oil and natural gas properties located in the Permian Basin of West Texas (the “Properties”) owned by Gulfport the three months ended March 31, 2012 and 2011.

The accompanying statements of revenues and direct operating expenses are presented on the accrual basis of accounting and were derived from the historical accounting records of Gulfport. Such amounts may not be representative of future operations. The statements do not include depreciation, depletion and amortization, general and administrative expenses, income taxes or interest expense.

Historical financial statements reflecting financial position, results of operations and cash flows required by accounting principles generally accepted in the United States of America are not presented as such information is not readily available on an individual property basis. Accordingly, the historical statements of revenues and direct operating expenses of the Properties are presented in lieu of the financial statements required under Rule 3-05 of the Securities and Exchange Commission Regulation S-X.

NOTE B—SIGNIFICANT ACCOUNTING POLICIES

Use of estimates

The preparation of the accompanying statements in conformity with generally accepted accounting principles requires making estimates and assumptions that affect the reported amounts of revenues and direct operating expenses during the reporting period. The estimates include oil and gas revenue accruals and reserve quantities. It is emphasized that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Actual results could materially differ from these estimates.

Revenue recognition

Oil and natural gas revenues are recorded when title passes to the purchaser, net of royalty interests, discounts and allowances, as applicable.

 

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Index to Financial Statements

CERTAIN PROPERTY INTERESTS OF

GULFPORT ENERGY CORPORATION

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES

FOR THE THREE MONTHS ENDED MARCH 31, 2012 AND 2011(CONTINUED)

(Unaudited)

 

NOTE C—SUBSEQUENT EVENTS

On May 7, 2012, Gulfport entered into a contribution agreement with Diamondback Energy, Inc., (“Diamondback”). Under the terms of the contribution agreement, Gulfport agreed to contribute to Diamondback, prior to the closing of the Diamondback initial public offering (“Diamondback IPO”), all its interests in the Properties in exchange for (i) shares of common stock representing 35% of Diamondback’s outstanding common stock immediately prior to the closing of the Diamondback IPO and (ii) $63,590,050.00 in the form of a non-interest bearing promissory note, which will be repaid in full upon the closing of the Diamondback IPO with a portion of the net proceeds from that offering. The aggregate consideration payable to Gulfport is subject to a post-closing cash adjustment based on changes in the working capital, long-term debt and other items of Windsor Permian LLC (“Windsor Permian”) referred to in the contribution agreement as of the date of the contribution. Windsor Permian, an entity controlled by Wexford, is the operator of Gulfport’s acreage to be contributed and will be a wholly-owned subsidiary of Diamondback at the time of the contribution. Gulfport’s obligation to make this contribution is contingent upon, among other things, the contribution to Diamondback of all the outstanding equity interests in Windsor Permian, Gulfport’s satisfaction with the terms of the Diamondback IPO and customary closing conditions. Under the contribution agreement, Gulfport is generally responsible for all liabilities and obligations with respect to the contributed properties arising prior to the contribution and Diamondback is responsible for such liabilities and obligations with respect to the contributed properties arising after the contribution.

In connection with the contribution, Gulfport and Diamondback will enter into an investor rights agreement in which Gulfport will have the right, for so long as it beneficially owns more than 10% of Diamondback’s outstanding common stock, to designate one individual as a nominee to serve on Diamondback’s board of directors. Such nominee, if elected to Diamondback’s board, will also serve on each committee of the board so long as he or she satisfies the independence and other requirements for service on the applicable committee of the board. So long as Gulfport has the right to designate a nominee to Diamondback’s board and there is no Gulfport nominee actually serving as a Diamondback director, Gulfport will have the right to appoint one individual as an advisor to the board who shall be entitled to attend board and committee meetings. Gulfport will also be entitled to certain information rights and Diamondback will grant Gulfport certain demand and “piggyback” registration rights obligating Diamondback to register with the SEC any shares of Diamondback common stock that Gulfport owns. If the contribution is completed, Gulfport will own a 35% equity interest in Diamondback immediately prior to the closing of the Diamondback IPO, rather than leasehold interests in Gulfport’s Permian Basin acreage.

Gulfport has evaluated the period after March 31, 2012 through June 8, 2012, the date the statements of revenues and direct operating expenses were available to be issued, noting no subsequent events or transactions that required recognition or disclosure in the statements of revenues and direct operating expenses.

 

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Index to Financial Statements

Dealer Prospectus Delivery Obligation

Until                     , 2012 (25 days after commencement of this offering), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.

 

 

 

 

 

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Index to Financial Statements

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution.

The following table sets forth the fees and expenses in connection with the issuance and distribution of the securities being registered hereunder. Except for the SEC registration fee and FINRA filing fee, all amounts are estimates.

 

SEC registration fee		$	5,730
FINRA filing fee			*
NASDAQ Global Market listing fee			25,000
Accounting fees and expenses			*
Legal fees and expenses			*
Blue Sky fees and expenses (including counsel fees)			*
Printing and Engraving expenses			*
Transfer Agent and Registrar fees and expenses			12,900
Miscellaneous expenses			*
Total		$	*

 

*	To be completed by amendment.

Item 14. Indemnification of Directors and Officers.

Limitation of Liability

Section 102(b)(7) of the Delaware General Corporation Law, or the DGCL, permits a corporation, in its certificate of incorporation, to limit or eliminate, subject to certain statutory limitations, the liability of directors to the corporation or its stockholders for monetary damages for breaches of fiduciary duty, except for liability:

 

•

for any breach of the director’s duty of loyalty to the company or its stockholders;

 

•

for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;

 

•

in respect of certain unlawful dividend payments or stock redemptions or repurchases; and

 

•

for any transaction from which the director derives an improper personal benefit.

In accordance with Section 102(b)(7) of the DGCL, Section 9.1 of our certificate of incorporation provides that that no director shall be personally liable to us or any of our stockholders for monetary damages resulting from breaches of their fiduciary duty as directors, except to the extent such limitation on or exemption from liability is not permitted under the DGCL. The effect of this provision of our certificate of incorporation is to eliminate our rights and those of our stockholders (through stockholders’ derivative suits on our behalf) to recover monetary damages against a director for breach of the fiduciary duty of care as a director, including breaches resulting from negligent or grossly negligent behavior, except, as restricted by Section 102(b)(7) of the DGCL. However, this provision does not limit or eliminate our rights or the rights of any stockholder to seek non-monetary relief, such as an injunction or rescission, in the event of a breach of a director’s duty of care.

If the DGCL is amended to authorize corporate action further eliminating or limiting the liability of directors, then, in accordance with our certificate of incorporation, the liability of our directors to us or our stockholders will be eliminated or limited to the fullest extent authorized by the DGCL, as so amended. Any repeal or amendment of provisions of our certificate of incorporation limiting or eliminating the liability of directors, whether by our stockholders or by changes in law, or the adoption of any other provisions inconsistent therewith, will (unless otherwise required by law) be prospective only, except to the extent such amendment or change in law permits us to further limit or eliminate the liability of directors on a retroactive basis.

 

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Index to Financial Statements

Indemnification

Section 145 of the DGCL permits a corporation, under specified circumstances, to indemnify its directors, officers, employees or agents against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlements actually and reasonably incurred by them in connection with any action, suit or proceeding brought by third parties by reason of the fact that they were or are directors, officers, employees or agents of the corporation, if such directors, officers, employees or agents acted in good faith and in a manner they reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reason to believe their conduct was unlawful. In a derivative action, i.e., one by or in the right of the corporation, indemnification may be made only for expenses actually and reasonably incurred by directors, officers, employees or agents in connection with the defense or settlement of an action or suit, and only with respect to a matter as to which they shall have acted in good faith and in a manner they reasonably believed to be in or not opposed to the best interests of the corporation, except that no indemnification shall be made if such person shall have been adjudged liable to the corporation, unless and only to the extent that the court in which the action or suit was brought shall determine upon application that the defendant directors, officers, employees or agents are fairly and reasonably entitled to indemnity for such expenses despite such adjudication of liability

Our certificate of incorporation provides that we will, to the fullest extent authorized or permitted by applicable law, indemnify our current and former directors and officers, as well as those persons who, while directors or officers of our corporation, are or were serving as directors, officers, employees or agents of another entity, trust or other enterprise, including service with respect to an employee benefit plan, in connection with any threatened, pending or completed proceeding, whether civil, criminal, administrative or investigative, against all expense, liability and loss (including, without limitation, attorney’s fees, judgments, fines, ERISA excise taxes and penalties and amounts paid in settlement) reasonably incurred or suffered by any such person in connection with any such proceeding. Notwithstanding the foregoing, a person eligible for indemnification pursuant to our certificate of incorporation will be indemnified by us in connection with a proceeding initiated by such person only if such proceeding was authorized by our board of directors, except for proceedings to enforce rights to indemnification.

The right to indemnification conferred by our certificate of incorporation is a contract right that includes the right to be paid by us the expenses incurred in defending or otherwise participating in any proceeding referenced above in advance of its final disposition, provided, however, that if the DGCL requires, an advancement of expenses incurred by our officer or director (solely in the capacity as an officer or director of our corporation) will be made only upon delivery to us of an undertaking, by or on behalf of such officer or director, to repay all amounts so advanced if it is ultimately determined that such person is not entitled to be indemnified for such expenses under our certificate of incorporation or otherwise.

The rights to indemnification and advancement of expenses will not be deemed exclusive of any other rights which any person covered by our certificate of incorporation may have or hereafter acquire under law, our certificate of incorporation, our bylaws, an agreement, vote of stockholders or disinterested directors, or otherwise.

Any repeal or amendment of provisions of our certificate of incorporation affecting indemnification rights, whether by our stockholders or by changes in law, or the adoption of any other provisions inconsistent therewith, will (unless otherwise required by law) be prospective only, except to the extent such amendment or change in law permits us to provide broader indemnification rights on a retroactive basis, and will not in any way diminish or adversely affect any right or protection existing at the time of such repeal or amendment or adoption of such inconsistent provision with respect to any act or omission occurring prior to such repeal or amendment or adoption of such inconsistent provision. Our certificate of incorporation also permits us, to the extent and in the manner authorized or permitted by law, to indemnify and to advance expenses to persons other that those specifically covered by our certificate of incorporation.

 

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Index to Financial Statements

Our bylaws include the provisions relating to advancement of expenses and indemnification rights consistent with those set forth in our certificate of incorporation. In addition, our bylaws provide for a right of indemnitee to bring a suit in the event a claim for indemnification or advancement of expenses is not paid in full by us within a specified period of time. Our bylaws also permit us to purchase and maintain insurance, at our expense, to protect us and/or any director, officer, employee or agent of our corporation or another entity, trust or other enterprise against any expense, liability or loss, whether or not we would have the power to indemnify such person against such expense, liability or loss under the DGCL.

Any repeal or amendment of provisions of our bylaws affecting indemnification rights, whether by our board of directors, stockholders or by changes in applicable law, or the adoption of any other provisions inconsistent therewith, will (unless otherwise required by law) be prospective only, except to the extent such amendment or change in law permits us to provide broader indemnification rights on a retroactive basis, and will not in any way diminish or adversely affect any right or protection existing thereunder with respect to any act or omission occurring prior to such repeal or amendment or adoption of such inconsistent provision.

We will enter into indemnification agreements with each of our current directors and executive officers. These agreements will require us to indemnify these individuals to the fullest extent permitted under Delaware law against liabilities that may arise by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. We also intend to enter into indemnification agreements with our future directors and executive officers.

Under the Underwriting Agreement, the underwriters are obligated, under certain circumstances, to indemnify directors and officers of the registrant against certain liabilities, including liabilities under the Securities Act of 1933, as amended, or the Securities Act. Reference is made to the form of Underwriting Agreement to be filed as Exhibit 1.1 to this Registration Statement.

Item 15. Recent Sales of Unregistered Securities.

In exchange for the contribution by DB Holdings of all of the outstanding equity interests in Windsor Permian to us prior to the completion of this offering, we will issue          shares of our common stock to DB Holdings. In addition, prior to the closing of this offering, we will issue shares of our common stock to Gulfport in connection with the Gulfport contribution.

The shares of our common stock described in this Item 15 will be issued in reliance upon the exemption from the registration requirements of the Securities Act provided by Section 4(2) of the Securities Act as sales by an issuer not involving any public offering.

Item 16. Exhibits and Financial Statement Schedules.

(A) Exhibits:

 

Exhibit Number		Number Description
1.1***		Form of Underwriting Agreement.
3.1*		Certificate of Incorporation of the Company.
3.2***		Form of proposed Amended and Restated Certificate of Incorporation to be effective immediately upon the closing of the offering made pursuant to this registration statement.
3.3*		Bylaws of the Company.
3.4***		Form of proposed Bylaws to be effective immediately upon the closing of the offering made pursuant to this registration statement.

 

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Exhibit Number		Number Description
4.1***		Specimen Certificate for shares of common stock, par value $0.01 per share, of the Company.
4.2*		Registration Rights Agreement by and among the Company and DB Energy Holdings LLC.
4.3*		Form of Investor Rights Agreement by and between the Company and Gulfport Energy Corporation.
5.1***		Opinion of Akin Gump Strauss Hauer & Feld LLP.
10.1*		Credit Agreement, dated as of October 15, 2010, by and among Windsor Permian LLC, as borrower, BNP Paribas, as administrative agent, and the lenders party thereto.
10.2*		First Amendment to Credit Agreement, dated as of January 31, 2011, by and among Windsor Permian LLC, as borrower, BNP Paribas, as administrative agent, and the lenders party thereto.
10.3*		Second Amendment to Credit Agreement, dated as of August 4, 2011, by and among Windsor Permian LLC, as borrower, BNP Paribas, as administrative agent, and the lenders party thereto.
10.4*		Third Amendment to Credit Agreement, dated as of October 13, 2011, by and among Windsor Permian LLC, as borrower, BNP Paribas, as administrative agent, and the lenders party thereto.
10.5*		Fourth Amendment to Credit Agreement, dated as of December 30, 2011, by and among Windsor Permian LLC, as borrower, BNP Paribas, as administrative agent, and the lenders party thereto.
10.6*		Shared Services Agreement, dated as of March 1, 2008, by and between Windsor Energy Resources LLC and Windsor Permian LLC.
10.7*		Lease Agreement, dated as of April 19, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC.
10.8*		Lease Amendment No. 1 to Lease Agreement, dated as of June 6, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC.
10.9*		Lease Amendment No. 2 to Lease Agreement, dated as of August 5, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC.
10.10*		Lease Amendment No. 3 to Lease Agreement, dated as of September 28, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC.
10.11*		Lease Amendment No. 4 to Lease Agreement, dated February 6, 2012, by and between Fasken Midland, LLC and Windsor Permian LLC.
10.12***†		Equity Incentive Plan.
10.13***†		Form of Stock Option Agreement.
10.14***†		Form of Restricted Stock Agreement.
10.15***†		Form of Director and Officer Indemnification Agreement.
10.16*		Form of Advisory Services Agreement by and between Diamondback Energy, Inc. and Wexford Capital LP.
10.17***		Form of Contribution Agreement by and between the Company and DB Energy Holdings LLC.
10.18*		Contribution Agreement, dated May 7, 2012, by and between the Company and Gulport Energy Corporation.
10.19*		Master Drilling Agreement, dated January 1, 2012, by and between Windsor Permian LLC and Bison Drilling and Field Services LLC.
10.20*		Gas Purchase Agreement, dated May 1, 2009, by and between Windsor Permian LLC and Feagan Gathering Company.

 

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Exhibit Number		Number Description
10.21*		Amendment to Gas Purchase Agreement, dated July 1, 2011, by and between Windsor Permian LLC and MidMar Gas LLC.
10.22*		Amendment to Gas Purchase Agreement, dated January 11, 2012, by and between Windsor Permian LLC and MidMar Gas LLC.
10.23*		Shared Services Agreement, dated January 1, 2012, by and between Windsor Permian LLC and Everest Operations Management LLC.
10.24*		Fifth Amendment to Credit Agreement, dated as of May 10, 2012, by and among Windsor Permian LLC, as borrower, Wells Fargo Bank, N.A., as administrative Agent and Amegy Bank National Association and U.S. Bank National Association, as co-syndication Agents.
10.25*		Subordinated note made by Windsor Permian LLC in favor of Lambda Investors LLC, dated May 14, 2012.
10.26***		Crude Oil Purchase Agreement, dated May 24, 2012, by and between Windsor Permian LLC and Shell Trading (US) Company.
10.27**		Office Lease Agreement, dated June 8, 2012, by and between Windsor Permian LLC and Caliber Investment Group LLC.
10.28**		Assignment and Assumption of Office Lease Agreement, effective June 1, 2012, by and between Windsor Permian LLC and Diamondback E&P LLC.
10.29**†		Amended and Restated Employment Agreement, dated as of January 1, 2012, by and between Travis Stice and Windsor Permian LLC.
10.30**†		Amended and Restated Employment Agreement, dated as of January 1, 2012, by and between Teresa Dick and Windsor Permian LLC.
10.31***†		Amended and Restated Employment Agreement, dated as of January 1, 2012, by and between Jeff White and Windsor Permian LLC.
21.1**		List of Significant Subsidiaries of the Company.
23.1**		Consent of Grant Thornton LLP.
23.2**		Consent of Pinnacle Energy Services, LLC.
23.3**		Consent of Ryder Scott Company.
23.4***		Consent of Akin Gump Strauss Hauer & Feld LLP (included in Exhibit 5.1).
24.1*		Power of Attorney.
99.1*		Consent of Michael P. Cross to being named as a director nominee.
99.2*		Consent of David L. Houston to being named as a director nominee.
99.3*		Consent of Mark L. Plaumann to being named a director nominee.

 

*	Previously filed.

**	Filed herewith.

***	To be filed by amendment.

†	Management contract, compensatory plan or arrangement.

(B) Financial Statement Schedules.

All schedules are omitted because the required information is (i) not applicable, (ii) not present in amounts sufficient to require submission of the schedule or (iii) included in our financial statements and the accompanying notes included in the prospectus to this Registration Statement.

 

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Item 17. Undertakings.

The undersigned Registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreements, certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification by the Registrant for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the Registrant pursuant to the foregoing provisions, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer, or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer, or controlling person in connection with the securities being registered hereunder, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The Registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

 

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Midland, State of Texas, on July 3, 2012.

 

Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed by the following persons in the capacities indicated on July 3, 2012.

 

Signature		Title
/s/ Travis D. Stice Travis D. Stice		Chief Executive Officer (Principal Executive Officer)
/s/ Teresa L. Dick Teresa L. Dick		Chief Financial Officer (Principal Financial and Accounting Officer)
* Steven E. West		Director

 

* By:		/s/ Travis D. Stice
		Travis D. Stice
		Attorney-in-Fact

 

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EXHIBIT INDEX

 

Exhibit Number		Number Description
1.1***		Form of Underwriting Agreement.
3.1*		Certificate of Incorporation of the Company.
3.2***		Form of proposed Amended and Restated Certificate of Incorporation to be effective immediately upon the closing of the offering made pursuant to this registration statement.
3.3*		Bylaws of the Company.
3.4***		Form of proposed Bylaws to be effective immediately upon the closing of the offering made pursuant to this registration statement.
4.1***		Specimen Certificate for shares of common stock, par value $0.01 per share, of the Company.
4.2*		Registration Rights Agreement by and among the Company and DB Energy Holdings LLC.
4.3*		Form of Investor Rights Agreement by and between the Company and Gulfport Energy Corporation.
5.1***		Opinion of Akin Gump Strauss Hauer & Feld LLP.
10.1*		Credit Agreement, dated as of October 15, 2010, by and among Windsor Permian LLC, as borrower, BNP Paribas, as administrative agent, and the lenders party thereto.
10.2*		First Amendment to Credit Agreement, dated as of January 31, 2011, by and among Windsor Permian LLC, as borrower, BNP Paribas, as administrative agent, and the lenders party thereto.
10.3*		Second Amendment to Credit Agreement, dated as of August 4, 2011, by and among Windsor Permian LLC, as borrower, BNP Paribas, as administrative agent, and the lenders party thereto.
10.4*		Third Amendment to Credit Agreement, dated as of October 13, 2011, by and among Windsor Permian LLC, as borrower, BNP Paribas, as administrative agent, and the lenders party thereto.
10.5*		Fourth Amendment to Credit Agreement, dated as of December 30, 2011, by and among Windsor Permian LLC, as borrower, BNP Paribas, as administrative agent, and the lenders party thereto.
10.6*		Shared Services Agreement, dated as of March 1, 2008, by and between Windsor Energy Resources LLC and Windsor Permian LLC.
10.7*		Lease Agreement, dated as of April 19, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC.
10.8*		Lease Amendment No. 1 to Lease Agreement, dated as of June 6, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC.
10.9*		Lease Amendment No. 2 to Lease Agreement, dated as of August 5, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC.
10.10*		Lease Amendment No. 3 to Lease Agreement, dated as of September 28, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC.
10.11*		Lease Amendment No. 4 to Lease Agreement, dated February 6, 2012, by and between Fasken Midland, LLC and Windsor Permian LLC.
10.12***†		Equity Incentive Plan.
10.13***†		Form of Stock Option Agreement.
10.14***†		Form of Restricted Stock Agreement.
10.15***†		Form of Director and Officer Indemnification Agreement.
10.16*		Form of Advisory Services Agreement by and between Diamondback Energy, Inc. and Wexford Capital LP.

 

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Index to Financial Statements

Exhibit Number		Number Description
10.17***		Form of Contribution Agreement by and between the Company and DB Energy Holdings LLC.
10.18*		Contribution Agreement, dated May 7, 2012, by and between the Company and Gulfport Energy Corporation.
10.19*		Master Drilling Agreement, dated January 1, 2012, by and between Windsor Permian LLC and Bison Drilling and Field Services LLC.
10.20*		Gas Purchase Agreement, dated May 1, 2009, by and between Windsor Permian LLC and Feagan Gathering Company.
10.21*		Amendment to Gas Purchase Agreement, dated July 1, 2011, by and between Windsor Permian LLC and MidMar Gas LLC.
10.22*		Amendment to Gas Purchase Agreement, dated January 11, 2012, by and between Windsor Permian LLC and MidMar Gas LLC.
10.23*		Shared Services Agreement, dated January 1, 2012 by and between Windsor Permian LLC and Everest Operations Management LLC.
10.24*		Fifth Amendment to Credit Agreement, dated as of May 10, 2012, by and among Windsor Permian LLC, as borrower, Wells Fargo Bank, N.A., as administrative Agent and Amegy Bank National Association and U.S. Bank National Association, as co-syndication Agents.
10.25*		Subordinated note made by Windsor Permian LLC in favor of Lambda Investors LLC, dated May 14, 2012.
10.26***		Crude Oil Purchase Agreement, dated May 24, 2012, by and between Windsor Permian LLC and Shell Trading (US) Company.
10.27**		Office Lease Agreement, dated June 8, 2012, by and between Windsor Permian LLC and Caliber Investment Group LLC.
10.28**		Assignment and Assumption of Office Lease Agreement, effective June 1, 2012, by and between Windsor Permian LLC and Diamondback E&P LLC.
10.29**†		Amended and Restated Employment Agreement, dated as of January 1, 2012, by and between Travis Stice and Windsor Permian LLC.
10.30**†		Amended and Restated Employment Agreement, dated as of January 1, 2012, by and between Teresa Dick and Windsor Permian LLC.
10.31***†		Amended and Restated Employment Agreement, dated as of January 1, 2012, by and between Jeff White and Windsor Permian LLC.
21.1**		List of Significant Subsidiaries of the Company.
23.1**		Consent of Grant Thornton LLP.
23.2**		Consent of Pinnacle Energy Services, LLC.
23.3**		Consent of Ryder Scott Company.
23.4***		Consent of Akin Gump Strauss Hauer & Feld LLP (included in Exhibit 5.1).
24.1*		Power of Attorney.
99.1*		Consent of Michael P. Cross to being named as a director nominee.
99.2*		Consent of David L. Houston to being named as a director nominee.
99.3*		Consent of Mark L. Plaumann to being named a director nominee.

 

*	Previously filed.

**	Filed herewith.

***	To be filed by amendment.

†	Management contract, compensatory plan or arrangement.

 

E-2

Exhibit 10.27

 

OFFICE LEASE AGREEMENT

This Office Lease Agreement (the “Lease”) is made and entered into on this the 8th day of June, 2012, to be effective as of January 1, 2012, (“Effective Date”) between CALIBER INVESTMENT GROUP LLC, a Delaware limited liability company (“Landlord”) and WINDSOR PERMIAN LLC, a Delaware limited liability company (“Tenant”).

W I T N E S S E T H:

 

1.

Definitions. Section 1 sets forth the definitions of some of the defined terms used in this Lease, which terms shall include the plural as well as the singular meanings thereof. The word “including”, when used in this Lease shall be construed to be followed by the words “without limitation” or “but not limited to”. The words “herein”, “hereof”, “hereunder”, “hereafter”, and other words of similar import shall refer to this Lease as a whole and not to any particular Section or other subdivision. All references to Exhibits or other attachments shall refer to the Exhibits, diagrams, and other special provisions attached to this Lease, all of which are incorporated by reference herein for all purposes. The definitions of other defined terms are found throughout this Lease.

 

A.

“Additional Provisions—Data Room Usage Agreement” shall mean that certain Data Room Usage Agreement made and entered into by Landlord and the Tenant this same date that is set forth on Exhibit “F”, which is attached hereto. By this reference, Exhibit “F” and such Additional Provisions—Data Room Usage Agreement is made an integral part of this Lease for all purposes as if fully set forth in the body of this Lease.

 

B.

“Additional Rent” shall mean Tenant’s Pro Rata Share of Basic Costs (hereinafter defined) and any other sums (exclusive of Base Rent) that are required to be paid to Landlord by Tenant hereunder, which sums are deemed to be Additional Rent under this Lease. Additional Rent and Base Rent are sometimes collectively referred to herein as “Rent.” The first monthly installment of Additional Rent shall be due and payable by the Tenant to the Landlord on the same date as payment of installments of the Base Rent by Tenant to the Landlord pursuant to Section 1.E hereof, subject to any necessary prorations thereof in accordance with the terms of Section 5.A hereof.

 

C.

“Approximate Rentable Area in the Building” is 40,865 square feet. Subject to adjustment only in the event of a reduction in space due to a casualty or condemnation, for purposes of the Lease it is agreed and stipulated by both Landlord and Tenant that the Approximate Rentable Area in the Building as of the date of this Lease is as set forth above.

 

D.

“Approximate Rentable Area in the Premises” shall mean the area contained within the demising walls of the Premises and any other area designated for the exclusive use of Tenant plus an allocation of the Tenant’s pro rata share of the square footage of the “Third Floor Common Areas” (as defined below). The Landlord is leasing to Tenant hereunder (i) three thousand nine hundred twenty-one (3,921) rentable square feet of the third (3rd) floor of the Building, commonly known as Suite 300, for Tenant’s exclusive use as depicted in the color Yellow on the floor plan of the third (3rd) floor which is attached hereto as Exhibit “B-1” and (ii) the right to use all of the Third Floor Common Areas, as depicted in the colors Grey and White on Exhibit “B-1”, which Third Floor Common Areas constitute a total of seven thousand three hundred thirty-five (7,335) square feet of the third (3rd) floor. Tenant’s pro rata share of the said Third Floor Common Areas is based on the ratio of the rentable square feet which it leases for its exclusive use on the third (3rd) floor, i.e., 3,921 rentable square feet, to the rentable square feet being leased to the only other tenant of the third (3rd) floor, i.e., Everest Operations Management LLC, for its exclusive use, i.e., 3,112 rentable square feet. The resultant ratio is fifty-five and 75/100ths percent (55.75%). Thus, the portion of the Third Floor Common Areas which are being allocated to Tenant’s Leased Premises for purposes of this Lease is Four Thousand Eighty-Nine (4,089) square feet (i.e., 55.75% x 7,335 square feet). As a result, Tenant’s Approximate Rentable Area in the Premises shall, for all purposes in this Lease, be deemed to be

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the sum of the rentable square feet for Tenant’s exclusive use on the third (3rd) floor, i.e., 3,921 rentable square feet, plus Tenant’s pro rata share of the Third Floor Common Areas, i.e., 4,089 square feet, constituting a total of Eight Thousand Ten (8,010) square feet.

 

E.

“Base Rent” shall mean the amount of Base Rent, i.e., exclusive of Additional Rent, to be paid by Tenant to Landlord on the first day of each month, commencing on the Effective Date, in advance and without prior notice or demand, in monthly installments. From and after the Effective Date, and on the first day of each month thereafter during the Term, Tenant shall pay monthly Base Rent to Landlord in the following amounts, as applicable:

 

BASE RENT SCHEDULE
MONTHLY BASE RENT SCHEDULE		AMOUNT OF MONTHLY BASE  RENT
January 1, 2012 – July 31, 2012		$15,352.50
August 1, 2012 – August 31, 2017		$16,687.50

The Base Rent is calculated based upon a rate of $23.00 per rentable square foot through July 31, 2012, and upon a rate of $25.00 per rentable square foot from August 1, 2012 until the Termination Date of August 31, 2017 (as defined below).

 

F.

“Base Year” shall mean the Calendar Year 2007.

 

G.

“Basic Costs” shall mean all direct and indirect costs and expenses incurred in connection with the Building as more fully defined in Exhibit “A” attached hereto.

 

H.

“Building” shall mean the office building at 14301 Caliber Drive, Oklahoma City, County of Oklahoma, State of Oklahoma, currently known as One Caliber Park at Quail Springs, together with the adjacent parking areas designated for the Building’s use, having the complete legal description set forth on Exhibit “B-2”.

 

I.

“Building Manager” shall mean Caliber Investment Group LLC or such other company as Landlord shall designate from time to time.

 

J.

“Building Standard” shall mean the type, brand, quality and/or quantity of materials Landlord designates from time-to-time to be the minimum quality and/or quantity to be used in the Building or the type, grade, quality and/or quantity of material to be used in the Building.

 

K.

“Business Day(s)” shall mean Mondays through Fridays exclusive of the normal business holidays of New Year’s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day and Christmas Day (“Holidays”). Landlord, from time to time during the Lease Term, shall have the right to designate additional Holidays, provided such additional Holidays are commonly recognized by other Class A office buildings in the area where the Building is located, and provided further than Tenant shall not be required to pay any charges for usage of central heat or air conditioning from the hours of 8:00 a.m. to 6:00 p.m. on any such additional Holidays (or 8:00 a.m. to 1:00 p.m. if such additional Holiday is on a Saturday).

 

L.

“Commencement Date”, “Lease Term” and “Termination Date” shall have the meanings set forth below:

 

(1)

The “Lease Term” shall mean a period of sixty-seven (67) months commencing on the Effective Date, i.e., January 1, 2012 (“Commencement Date”).

 

(2)

The “Termination Date” shall, unless sooner terminated as provided herein, mean August 31, 2017.

 

2

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M.

“Common Areas” shall mean those areas located within the Building or on the Property used for corridors, elevator foyers, mail rooms, restrooms, mechanical rooms, elevator mechanical rooms, property management office, janitorial closets, electrical and telephone closets, vending areas, and lobby areas (whether at ground level or otherwise), entrances, exits, sidewalks, skywalks, tunnels, driveways, parking areas and parking garages and landscaped areas and other similar facilities provided for the non-exclusive common use or benefit of tenants generally and/or the public.

 

N.

“Default Rate” shall mean fifteen percent (15%) per annum.

 

O.

“Normal Business Hours” for the Building shall mean 8:00 a.m. to 6:00 p.m. Mondays through Fridays, and 8:00 a.m. to 1:00 p.m. on Saturdays, exclusive of Holidays.

 

P.

“Notice Addresses” shall mean the following addresses for Tenant and Landlord, respectively:

If to Tenant:

WINDSOR PERMIAN LLC

Attn: Tracy Dick, Chief Financial Officer

14301 Caliber Drive, Suite 300

Oklahoma City, Oklahoma 73134

Telephone: 405.463.6968

Facsimile: 405.463.6997

Monthly Rent Statements shall be sent to Tenant only to:

WINDSOR PERMIAN LLC

Attn: Tracy Dick, Chief Financial Officer

14301 Caliber Drive, Suite 300

Oklahoma City, Oklahoma 73134

If to Landlord:

Caliber Investment Group LLC

14301 Caliber Drive, Suite 300

Oklahoma City, Oklahoma 73134

Attn: Matt Austin, Vice President

Telephone: 405.600.1101

Fax: 405.286.5927

With a copy to:

Wexford Capital LP

Attn: Philip Braunstein

411 West Putnam Avenue

Greenwich, CT 06830

Telephone: 203.862.7033

Fax: 203.862.7333

Any checks for payments of Rent only shall be made payable to the order of:

Caliber Investment Group LLC

At the following address:

Caliber Investment Group LLC

14301 Caliber Drive, Suite 300

Oklahoma City, Oklahoma 73134

or such other name and address as Landlord shall, from time to time, designate.

 

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Q.

“Permitted Use” shall mean an operation, consistent with a first-class office building, of offices to be utilized for general office use and administrative activities in conjunction therewith.

 

R.

“Premises” shall mean the 3,921 rentable square feet of the third (3rd) floor of the Building designated for Tenant’s exclusive use as depicted in the color Yellow on the floor plan of the third (3rd) floor attached hereto as Exhibit “B-1” and the right to use all of the Third Floor Common Areas, as depicted in the colors Gray and White on Exhibit “B-1”, which Third Floor Common Areas contain a total of 7,335 square feet. For purposes of this Lease, Tenant’s pro rata share of the Third Floor Common Areas (as determined in the manner set forth in Section 1.D., above) is deemed to be 55.75% thereof, i.e., 4,089 square feet, resulting in the Premises totaling Eight Thousand Ten (8,010) square feet of the third (3rd) floor of the Building for all purposes under this Lease.

 

S.

“Property” shall mean the Building and the parcel(s) of land on which it is located, other improvements located on such land, adjacent parcels of land that Landlord operates jointly with the Building, and other buildings and improvements located on such adjacent parcels of land.

 

T.

Security Deposit [INTENTIONALLY DELETED]

 

U.

“Service Areas” shall mean those areas within the Building used for stairs, elevator shafts, flues, vents, stacks, pipe shafts and other vertical penetrations (but shall not include any such areas for the exclusive use of a particular tenant).

 

V.

“Tenant’s Estoppel Certificate” shall mean the tenant estoppel certificate Tenant is required to provide to Landlord pursuant to the provisions of Section 28 herein which shall be substantially in the form of the Pre-Approved Tenant Estoppel Certificate attached hereto as Exhibit “C”.

 

W.

“Tenant’s Pro Rata Share” shall mean 19 and 60/100ths percent, i.e., 0.1960 (19.60%), which is the quotient (expressed as a percentage), derived by dividing the Approximate Rentable Area in the Premises by the Approximate Rentable Area in the Building.

 

2.

Lease Grant. Subject to and upon the terms herein set forth, Landlord leases to Tenant and Tenant leases from Landlord the Premises together with the right, in common with others, to use the Common Areas located on the Property and any adjacent property which the Landlord operates jointly with the Property and which provides vehicular or pedestrian access to or parking for the Building.

 

3.	Adjustment of Commencement Date/Possession.

 

A.

Commencement The Lease Term shall commence upon the Commencement Date, January 1, 2012, and terminate on the Termination Date, August 31, 2017.

 

B.

Property Condition By taking possession of the Premises on the Commencement Date, Tenant is deemed to have accepted the Premises, AS-IS, WHERE-IS, and to have agreed that the Premises are in good order and satisfactory condition, with no representation or warranty (except as expressly provided herein) of any kind or nature, whether express or implied, by Landlord as to the condition of the Premises or the Building or the suitability or fitness thereof for Tenant’s use.

 

4.

Use. Tenant will occupy the Premises for the Permitted Use and will not use or permit any portion of the Premises to be used for any purpose other than for general office space and related administrative activities consistent with the Permitted Use. Tenant agrees not to use the Premises for any purpose which is unlawful, disreputable, dangerous to life, limb or property, or which creates a nuisance or increases the risk of casualty or the rate of fire or casualty insurance covering the Building or its contents. In the event that any act of Tenant materially results in any increase in the cost of insurance covering the Building or its contents, Tenant agrees to pay to Landlord the amount of such increased cost as Additional Rent. Tenant will conduct Tenant’s business and will control Tenant’s employees and use reasonable efforts to control Tenant’s agents, licensees,

 

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and invitees in such a manner as not to create any nuisance or unreasonably interfere with, or disturb the Landlord or other tenants in the management and operation of the Building and the Property. Tenant will maintain the Premises in a clean condition, and will not cause or permit objectionable odors of an unusual or objectionable nature, to emanate from the Premises at any time. Tenant, at Tenant’s expense, shall comply with, cause Tenant’s employees to comply with, and use reasonable efforts to cause Tenant’s agents, licensees and invitees to fully comply with: (i) the Building Regulations which are attached to this Lease as Exhibit “D” hereto; (ii) all laws pertaining to Tenant’s use of the Premises; (iii) all other legal requirements, including all applicable laws pertaining to air and water quality, hazardous materials, waste and disposal, all emissions, and other environmental matters; and (iv) all zoning and land use matters and any directive of any governmental authority, pursuant to law, which shall impose any duty upon Landlord or Tenant with respect to the particular use or occupancy of the Premises by Tenant to include, without limitation, the obligation of Tenant to obtain, at its sole cost and expense, all permits or other government consents from any county, state or federal agency which are required in order for it to perform the Permitted Use on the Premises, and to otherwise comply with such other rules and regulations adopted and altered by Landlord from time-to-time. All such changes to the Building’s Regulations, i.e., Exhibit “D” hereto, will be reasonable, apply equally to all tenants in the Building and shall be sent by Landlord to Tenant in writing. Nothing contained in this Lease will be deemed or construed in any manner as creating a partnership or joint venture between Landlord and Tenant with regard to conducting the Permitted Use on the Premises or between Landlord and any other party with regard thereto, or cause the Landlord to be liable or responsible in any way for the actions, inactions, liabilities, debts or obligations of Tenant or Tenant’s agents, employees, invitees, permitted subtenants, licensees, or concessionaires. Landlord agrees to generally apply and enforce the Building Regulations and any such other rules and regulations in a uniform manner against all tenants. Notwithstanding anything herein or in the Building Regulations or any other rules and regulations to the contrary, no additional rules or regulations or any amendment, change or revision to the Building Regulations may be made that (i) diminish Tenant’s rights and privileges hereunder (including, without limitation, access to or use of the Premises) or (ii) increase Tenant’s obligations hereunder. In the event of any conflict or inconsistency between the terms and provisions of this Lease (other than the Building Regulations) and the Building Regulations or any amendments or modifications thereto, the terms and provisions of this Lease (other than the Building Regulations or such amendments or modifications) shall control.

In addition to the foregoing, Tenant specifically covenants and agrees that its use of the Premises and Common Areas shall be subject to and in full compliance with the Declaration of Protective Covenants of Quail Springs Office Park, and any current amendments thereto, including the Declaration of Protective Covenants dated as of July 27, 1983, and recorded in Book 4997 at Page 999, in the Office of the County Clerk of Oklahoma County, State of Oklahoma (“Oklahoma County Clerk”), as amended by that certain Amendment to Declaration of Protective Covenants dated as of September 20, 1984, and recorded with the Oklahoma County Clerk in Book 5230 at page 44, as further amended by that certain Second Amendment to Declaration of Protective Covenants dated as of March 17, 1998, and recorded with the Oklahoma County Clerk in Book 7269 at Page 735, as further amended by that certain Third Amendment to Declaration of Protective Covenants dated as of September 30, 2005, and recorded with the Oklahoma County Clerk in Book 9875 at Page 560 (collectively, the “Declaration”), all of which subject the Building and the Property to the terms, conditions, restrictions, and provisions therein contained, and as said Declaration is amended from time-to-time. It is expressly understood and agreed that the terms of the Declaration may vary from the terms of this Lease. Landlord represents and warrants that the Declaration does not prohibit or limit use of the Premises by Tenant for the Permitted Use.

 

5.

Rent.

 

A.

Base Rent Tenant covenants and agrees to pay to Landlord during the Lease Term, without any setoff or deduction except as otherwise expressly provided herein, the full amount of all Base Rent and Additional Rent due hereunder and the full amount of all such other sums of money as shall become due under this Lease (including, without limitation, any charges for replacement of electric lamps and ballasts in non-Building Standard light fixtures and any other services, goods or materials in excess of the services to be provided by Landlord hereunder that are furnished by Landlord at Tenant’s request), all of which hereinafter may be collectively called “Rent”. In addition Tenant shall pay and be liable for, as Additional Rent, all rent,

 

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sales and use taxes or other similar taxes, if any, levied or imposed by any city, state, county or other governmental body having authority, such payments to be in addition to all other payments required to be paid to Landlord by Tenant under the terms and conditions of this Lease. Any such payments shall be paid by Tenant directly to the taxing authority when due or thereafter upon demand by Landlord or, if not so paid, then concurrently with the payments of the Rent on which the tax is based. The Base Rent and Additional Rent for each calendar year or portion thereof during the Lease Term, shall be due and payable in advance in monthly installments on the first day of each calendar month during the Lease Term and any extensions or renewals hereof, and Tenant hereby agrees to pay such Base Rent and Additional Rent to Landlord without demand. If the obligation of the Tenant to pay the Base Rent and the Additional Rent to the Landlord, pursuant to the provisions of Sections 1.B. and 1.E., above, commences on a day other than the first day of a month or, if the Lease Term terminates on a day other than the last day of a month, then the installments of Base Rent and Additional Rent for such month or months shall be prorated on a per diem basis, based on the number of days in such month. No payment by Tenant or receipt or acceptance by Landlord of a lesser amount than the correct installment of Rent due under this Lease shall be deemed to be other than a payment on account of the earliest Rent due hereunder, nor shall any endorsement or statement on any check or any letter accompanying any check or payment be deemed an accord and satisfaction, and Landlord may accept such check or payment without prejudice to Landlord’s right to recover the balance or pursue any other available remedy. The acceptance by Landlord of an installment of Rent on a date after the due date of such payment shall not be construed to be a waiver of Landlord’s right to declare a default for any other late payment. All amounts received by Landlord from Tenant hereunder shall be applied first to the earliest accrued and unpaid Rent then outstanding. Tenant’s covenant to pay Rent shall be independent of every other covenant set forth in this Lease. Base Rent and any other Rent may be paid via check or via electronic transfer of funds (via wire transfer or ACH transfer), and Landlord agrees to cooperate with Tenant to provide any information reasonably requested by Tenant in order to permit Tenant to make Rent payments in such manner.

 

B.

Late Charges To the extent allowed by law, all installments of Rent not paid when due shall bear interest at the Default Rate from the date due until paid. In addition, if Tenant fails to pay any installment of Base Rent and Additional Rent or any other item of Rent when due and payable hereunder, a “Late Charge” equal to five percent (5%) of such unpaid amount will be due and payable immediately by Tenant to Landlord.

 

C.

Additional Rent The Additional Rent payable hereunder shall be determined, as adjusted from time-to-time, in accordance with the provisions of Exhibit “A” attached hereto and incorporated herein for all purposes.

 

6.	Security Deposit. [INTENTIONALLY DELETED]

 

7.	Services to be Furnished by Landlord.

 

A.

Standard Services Landlord agrees to furnish Tenant the following services:

 

(i)

Water for use in the lavatories on the floor(s) on which the Premises is located and to any fixtures included as part of the Initial Alterations. If Tenant desires additional water in the Premises for any reason, approved in writing by the Landlord, e.g., a private lavatory or kitchen, cold water shall be supplied from the Building water main through a line and fixtures, at Tenant’s sole cost and expense, with the prior reasonable consent of Landlord. If Tenant desires additional hot water fixtures in the Premises, Tenant, at its sole cost and expense, and subject to the prior reasonable consent of the Landlord, may install an additional hot water heater in the Premises. Tenant shall be solely responsible for the maintenance and repair of all hot water heaters located in the Premises.

 

(ii)

Central heat and air conditioning in season during Normal Business Hours, at such temperatures and in such amounts as are considered by Landlord, in its reasonable judgment, to be standard for buildings of similar class, size, age and location, or as required by governmental authority. In the

 

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event that Tenant requires central heat, ventilation or air conditioning service at times other than Normal Business Hours, such additional service shall be furnished only upon the written request of Tenant delivered to Landlord prior to 3:00 p.m. at least one Business Day in advance of the date for which such usage is requested. Tenant shall bear the entire cost of such additional service as such costs are determined by the Landlord, from time-to-time, as Additional Rent upon presentation of a statement therefor by Landlord. All additional heating, ventilating and air conditioning required (if any) to accommodate Tenant’s design, and/or any special needs of the Tenant shall be installed at the Tenant’s expense subject to Landlord’s prior written approval in accordance with the provisions of Section 10, below. The cost of operation and maintenance of such additional equipment shall be the responsibility of the Tenant and paid to Landlord as Additional Rent.

 

(iii)

Maintenance and repair of all Common Areas in the manner and to the extent reasonably deemed by Landlord to be standard for buildings of similar class, age and location.

 

(iv)

Janitorial and cleaning service in and about the Premises on Business Days; provided, however, if Tenant’s floor covering or other improvements require special treatment, Tenant shall pay the additional cleaning cost attributable thereto as Additional Rent upon presentation of a statement therefor by Landlord. Tenant shall not provide or use any other janitorial or cleaning services without Landlord’s consent, and then only subject to the supervision of Landlord and at Tenant’s sole cost and responsibility and by a janitor, cleaning contractor or employees at all times satisfactory to Landlord. Tenant shall be responsible for thoroughly cleaning any cooking and service areas of the Premises, on a daily basis.

 

(v)

Electricity to the Premises for general office use, in accordance with and subject to the terms and conditions of Section 11 of this Lease.

 

(vi)

Fluorescent bulb replacement in the Premises necessary to maintain Building Standard in the lighting as established by Landlord and fluorescent and incandescent bulb and ballast replacement in the Common Areas and Service Areas.

 

(vii)

Passenger elevator service in common with Landlord and other persons during Normal Business Hours and freight elevator service in common with the Landlord and other persons during Normal Business Hours. Such normal elevator service, passenger or freight, if furnished at other times, shall be optional with Landlord and shall never be deemed a continuing obligation.

 

(viii)

Access control to the Building during other than Normal Business Hours shall be provided in such form as Landlord deems appropriate. Tenant shall cooperate fully in Landlord’s efforts to maintain access control to the Building and shall follow all regulations promulgated by Landlord with respect thereto. Landlord agrees to allow access to the Building on a 24-hour per day, seven (7) days a week basis by use of a security card access system that Tenant will be allowed to utilize. Notwithstanding anything herein to the contrary Tenant expressly acknowledges and agrees that Landlord is not warranting the efficacy of any access personnel, service, procedures or equipment and that Tenant is not relying and shall not hereafter rely on any such personnel service, procedures or equipment. Landlord shall not be responsible or liable in any manner for failure of any access personnel, services, procedures or equipment to prevent, control, or apprehend anyone suspected of causing personal injury or damage in, on or around the Project.

 

B.

Excess Services If Tenant requests any other utilities or building services in addition to those identified above, or any of the above utilities or building services in frequency, scope, quality or quantities substantially greater than the standards set by Landlord for the Building, then Landlord shall use reasonable efforts to attempt to furnish Tenant with such additional utilities or building services. Landlord may impose a reasonable charge for such additional utilities or building services, which shall be paid monthly by Tenant as Additional Rent on the same day that the monthly installment of Base Rent is due.

 

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C.

Landlord’s Reservations Except as otherwise expressly provided herein, the failure by Landlord to any extent to furnish, or the interruption or termination of these defined services in whole or in part, resulting from adherence to laws, regulations and administrative orders, wear, use, repairs, improvements alterations or any causes beyond the reasonable control of Landlord shall not render Landlord liable in any respect nor be construed as a constructive eviction of Tenant, nor give rise to an abatement of Rent, nor relieve Tenant from the obligation to fulfill any covenant or agreement hereof. Should any of the equipment or machinery used in the provision of such defined services for any cause cease to function properly, Landlord shall use reasonable diligence to repair such equipment or machinery without delay or interruption except for events beyond the reasonable control of Landlord.

 

8.

Leasehold Improvements/Tenant’s Property. All fixtures, equipment, improvements and appurtenances attached to, or built into, the Premises at the commencement of or during the Lease Term, whether or not by, or at the expense of, Tenant (“Leasehold Improvements”), shall be and remain a part of the Premises; shall constitute part of the Premises to be utilized by Tenant during the Lease Term, but shall be the property of Landlord; and shall not be removed by Tenant except as expressly provided herein. All unattached and moveable partitions, trade fixtures, moveable equipment or furniture located in the Premises and acquired by or for the account of Tenant, without expense to Landlord, which can be removed without structural damage to the Building or Premises, and all personalty brought into the Premises by Tenant (“Tenant’s Property”) shall be owned and insured by Tenant. Landlord may, nonetheless, at any time prior to, or within one (1) month after, the expiration or earlier termination of this Lease or Tenant’s right to possession, require Tenant to remove any and all electronic, phone and data cabling which have been laid on the ceiling tile of the grid by the Tenant (the “Required Removables”) at Tenant’s sole cost. In the event that Landlord so elects, Tenant shall remove such Required Removables within ten (10) days after notice from Landlord, provided that in no event shall Tenant be required to remove such Required Removables prior to the expiration or earlier termination of this Lease or Tenant’s right to possession. In addition to Tenant’s obligation to remove the Required Removables, Tenant shall remove all of Tenant’s Property on or before the end of the Lease Term. Tenant shall repair any damage caused by such removal and perform such other work as is reasonably necessary to restore the Premises to a “move in” condition at the end of the Term. If Tenant fails to remove any specified Required Removables, or all of the Tenant’s Property, or to perform any required repairs and restoration within the respective time period specified above, Landlord, at Tenant’s sole cost and expense, may remove the Required Removables and any remaining Tenant’s Property (and repair any damage occasioned thereby) and dispose thereof or deliver the Required Removables and Tenant’s Property to any other place of business of Tenant, or warehouse the same, and Tenant shall pay the cost of such removal, repair, delivery, or warehousing of the Required Removables or Tenant’s Property, as the case may be, within five (5) days after demand therefor is made by Landlord.

 

9.

Signage. Landlord will list Tenant’s name on both the Building’s directory located in the lobby of the Building, and the Building’s monument sign located outside the Building, at Landlord’s sole cost and expense, pursuant to the Building Standard. In addition, Tenant shall have the right to place and use its logo at the entrance to the Premises, subject to Landlord’s prior review and written approval of the lettering and placement thereof.

 

10.	Repairs and Alterations by Tenant.

 

A.

Tenant’s Maintenance Obligations Except to the extent such obligations are imposed upon Landlord hereunder, Tenant shall, at its sole cost and expense, maintain the Premises in good order, condition and repair throughout the entire Lease Term, ordinary wear and tear excepted. Tenant agrees to keep the areas visible from outside the Premises in a neat, clean and attractive condition at all times. Tenant shall be responsible for all repairs replacements and alterations in and to the Premises, Building and Property and the facilities and systems thereof, the need for which arises out of (1) Tenant’s use or occupancy of the Premises, (2) the installation, removal, use or operation of Tenant’s Property (as defined in Section 8. above), (3) the moving of Tenant’s Property into or out of the Building, or (4) the act, omission, misuse or negligence of Tenant, its agents, contractors, employees or invitees. All such repairs, replacements or alterations shall be performed in accordance with Section 10.B. below and the rules, policies and procedures reasonably enacted by Landlord from time to time for the performance of work in the Building. If Tenant fails to maintain the Premises in good order, condition and repair, Landlord shall give Tenant

 

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notice to perform such acts as are reasonably required to so maintain the Premises. If Tenant fails to promptly commence such work and diligently pursue it to its completion, then Landlord may, at is option, make such repairs, and Tenant shall pay the cost thereof to Landlord on demand as Additional Rent, together with an administration charge in an amount equal to ten percent (10%) of the cost of such repairs. Landlord shall, at its expense (except as included in Basic Costs) keep and maintain in good repair and working order and make all repairs to and perform necessary maintenance upon: (a) all structural elements of the Building; and (b) all mechanical, electrical and plumbing systems that serve the Building in general; and (c) the Building facilities common to all tenants including but not limited to, the ceilings, walls and floors in the Common Areas.

 

B.

Alterations Tenant shall not make or allow to be made any alterations, additions or improvements to the Premises, without first obtaining the written consent of Landlord in each such instance, which consent, may be refused or given on such conditions as Landlord may elect, in its sole discretion. Prior to commencing any such work and as a condition to obtaining Landlord’s consent, Tenant must furnish Landlord with plans and specifications acceptable to Landlord; names and addresses of contractors reasonably acceptable to Landlord; copies of contracts; necessary permits and approvals; evidence of contractor’s and subcontractor’s insurance in accordance with Section 15 hereof; and a payment bond or other security, all in form and amount satisfactory to Landlord. Tenant shall be responsible for insuring that all such persons procure and maintain insurance coverage against such risks, in such amounts and with such companies as Landlord may require, including, but not limited to, Builder’s Risk and Worker’s Compensation insurance. All such improvements, alterations or additions shall be constructed in a good and workmanlike manner using Building Standard materials or other new materials of equal or greater quantity. Landlord, to the extent reasonably necessary to avoid any disruption to the tenants and occupants of the Building, shall have the right to designate the time when any such alterations, additions and improvements may be performed and to otherwise designate reasonable rules, regulations and procedures for the performance of work in the Building. Upon completion, Tenant shall furnish “as-built” plans, contractor’s affidavits and full and final waivers of lien and receipted bills covering all labor and materials. All improvements, alterations and additions shall comply with the insurance requirements, codes, ordinances, laws and regulations, including without limitation, the Americans with Disabilities Act. Tenant shall reimburse Landlord upon demand for all sums, if any, expended by Landlord for third party examination of the architectural, mechanical, electrical and plumbing plans for any alterations, additions or improvements. In addition, if Landlord so requests, Landlord shall be entitled to oversee the construction of any alterations, additions or improvements that may affect the structure of the Building or any of the mechanical, electrical, plumbing or life safety systems of the Building. In the event Landlord elects to oversee such work, Landlord shall be entitled to receive a fee for such oversight in an amount equal to ten percent (10%) of the cost of such alterations, additions or improvements. Landlord’s approval of Tenant’s plans and specifications for any work performed for or on behalf of Tenant shall not be deemed to be representation by Landlord that such plans and specifications comply with applicable insurance requirements, building codes, ordinances, laws or regulations or that the alterations, additions and improvements constructed in accordance with such plans and specifications will be adequate for Tenant’s use.

 

11.	Use of Electrical Services by Tenant.

 

A.

Electric Service Provider All electricity used by Tenant in the Premises shall be paid for by Tenant through inclusion in Base Rent and Basic Costs (except as provided in Section 11.B. below with respect to excess usage). Landlord shall have the right at any time and from time-to-time during the Lease Term to contract for electricity service from such providers of such services as Landlord shall elect (each being an “Electric Service Provider”). Tenant shall cooperate with Landlord, and the applicable Electric Service Provider, at all times and, as reasonably necessary, shall allow Landlord and such Electric Service Provider reasonable access to the Building’s electric lines, feeders, risers, wiring, and any other machinery within the Premises. Landlord shall in no way be liable or responsible for any loss, damage, or expense that Tenant may sustain or incur by reason of any change, failure, interference, disruption, or defect in the supply or character of the electric energy furnished to the Premises, or if the quantity or character of the electric energy supplied by the Electric Service Provider is no longer available or suitable for Tenant’s requirements, and no such change, failure, defect, unavailability, or unsuitability shall constitute an actual or constructive eviction of Tenant, in whole or in part, or, except as otherwise specifically provided in Section 7.C., entitle Tenant to any abatement or diminution of rent, or relieve Tenant from any of its obligations under the Lease.

 

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B.

Excess Usage Tenant’s use of electrical services furnished by Landlord shall not exceed in voltage, rated capacity, or overall load that which is the Building Standard. In the event Tenant shall request that it be allowed to consume electrical services in excess of the Building Standard, Landlord may refuse to consent to such usage or may consent upon such conditions as Landlord reasonably elects (including the installation of utility service upgrades, submeters, air handlers or cooling units), and all such additional usage (to the extent permitted by law), installation and maintenance thereof shall be paid for by Tenant as Additional Rent. Landlord, at any time during the Lease Term, shall have the right to separately meter electrical usage for the Premises or to measure electrical usage by survey or any other method that Landlord, in its reasonable judgment, deems appropriate.

 

12.

Entry by Landlord. Tenant shall permit Landlord or its agents or representatives to enter into and upon any part of the Premises to inspect the same, or to show the Premises to prospective purchasers, mortgagees, tenants, or insurers, or to clean or make repairs, alterations, or additions thereto, including any work that Landlord deems necessary for the safety, protection or preservation of the Building or any occupants thereof, or to facilitate repairs, alterations or additions to the Building or any other tenant’s premises. Except for any entry by Landlord in an emergency situation or to provide normal cleaning and janitorial service, Landlord shall provide Tenant with reasonable prior notice of any entry into the Premises, which notice may be given verbally. Landlord shall have the right to temporarily close the Premises or the Building to perform repairs, alterations or additions in the Premises or the Building, provided that Landlord shall use reasonable efforts to perform all such work on weekends and after Normal Business Hours. Entry by Landlord hereunder shall not constitute a constructive eviction or entitle Tenant to any abatement or reduction of Rent by reason thereof.

 

13.	Assignment and Subletting.

 

A.

General Except in connection with a Permitted Transfer (defined in Section 13.E. below), Tenant shall not assign, sublease, transfer or encumber any interest in this Lease or allow any third party to use any portion of the Premises (collectively or individually, a “Transfer”) without the prior written consent of Landlord, exercisable in its sole and absolute discretion. In no event shall any Transfer or Permitted Transfer release or relieve Tenant from any obligation under this Lease or any liability hereunder whatsoever.

 

B.

Landlord’s Election If Tenant requests Landlord’s Consent to a Transfer, Tenant shall submit to Landlord financial statements for the proposed Transferee, a complete copy of the proposed assignment, sublease and other information as Landlord may reasonably request. Landlord shall, within thirty (30) days after Landlord’s receipt of the required information and documentation, either: (1) consent or reasonably refuse consent, in its sole and absolute discretion, to the Transfer in writing; or (2) in the event of a proposed assignment of this Lease or a proposed sublease of the entire Premises for the entire remaining term of this Lease, terminate this Lease effective the first to occur of ninety (90) days following written notice of such termination or the date that the proposed Transfer would have come into effect and upon such termination, Tenant shall be released from any further obligations under this Lease. If Landlord shall fail to notify Tenant in writing of its decision within such thirty (30) days after the later of the date Landlord is notified in writing of the proposed Transfer or the date Landlord has received all required information concerning the proposed transferee and the proposed Transfer, Landlord shall be deemed to have refused to consent to such Transfer and to have elected to keep this Lease in full force and effect. Tenant shall pay Landlord a review fee of Five Hundred and No/100ths Dollars ($500.00) for Landlord’s review of any Permitted Transfer or requested Transfer. In addition, Tenant shall reimburse Landlord for its actual reasonable costs and expenses (including, without limitation, reasonable attorney’s fees) incurred by Landlord in connection with Landlord’s review of such requested Transfer or Permitted Transfer.

 

C.

Proceeds Tenant shall pay to Landlord one hundred percent (100%) of all cash and other consideration which Tenant receives as a result of the Transfer that is in excess of the rent payable to Landlord hereunder for the portion of the Premises and Term covered by the Transfer within ten (10) days following receipt thereof by Tenant. If Tenant is in Monetary Default (defined in Section 22.A.(1), below), Landlord may require that all sublease payments be made directly to Landlord, in which case Tenant shall receive a credit against Rent in the amount of any payments received (less Landlord’s share of any excess).

 

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D.

Change of Ownership Except as provided below with respect to a Permitted Transfer, if Tenant is a corporation, limited liability company, partnership or similar entity, and the entity which owns or controls a majority of the voting shares/rights at the time changes for any reason (including but not limited to an initial public offering of Tenant’s stock, a merger, consolidation or reorganization), such change of ownership or control shall constitute a Transfer. The foregoing shall not apply so long as Tenant is an entity whose outstanding stock is listed on a nationally recognized security exchange, or if at least eighty percent (80%) of its voting stock is owned by another entity, the voting stock of which is so listed.

 

E.

Common Control Tenant will assign its entire interest under this Lease in and to the Premises to its affiliated company, Diamondback E&P LLC, a Delaware limited liability company, on the same date it executes this Lease by means of a certain Assignment and Assumption of Office Lease Agreement, in form and substance approved by Landlord, to be made, executed and delivered by and between Windsor Permian LLC, as Assignor, and Diamondback E&P LLC, as Assignee, that same date. Thereafter, Tenant may assign its entire interest under this Lease or sublet the Premises, to any entity controlling or controlled by or under common control with Tenant or to any successor to Tenant by purchase, merger, consolidation or reorganization (hereinafter, collectively, referred to as “Permitted Transfer”) without the consent of Landlord, provided: (1) Tenant is not in default under this Lease; (2) if such proposed transferee is a successor to Tenant by purchase, i.e., said proposed transferee shall acquire all or substantially all of the stock or assets of Tenant’s business or, if such proposed transferee is a successor to Tenant by merger, consolidation or reorganization, the continuing or surviving corporation shall own all or substantially all of the assets of Tenant; (3) such proposed transferee shall have a net worth which is at least equal to the greater of Tenant’s net worth at the date of this Lease or Tenant’s net worth as of the day prior to the proposed purchase, merger, consolidation or reorganization as evidenced to Landlord’s reasonable satisfaction; (4) such proposed transferee operates the business in the Premises for the Permitted Use and no other purpose; and (5) Tenant shall give Landlord written notice at least thirty (30) days prior to the effective date of the proposed purchase, merger, consolidation or reorganization.

 

F.

Remedy Tenant agrees that in the event Landlord withholds its consent to any Transfer contrary to the provisions of this Section 13, Tenant’s sole remedy shall be to seek an injunction in equity or compel performance by Landlord to give its consent and Tenant expressly waives any right to damages in the event of such withholding by Landlord of its consent.

 

14.

Mechanic’s Liens. Tenant will not permit any mechanic’s liens or other liens to be placed upon the Premises, the Building, or the Property and nothing in this Lease shall be deemed or construed in any way as constituting the consent or request of Landlord, express or implied, by inference or otherwise, to any person for the performance of any labor or the furnishing of any materials to the Premises, the Building, or the Property or any part thereof, nor as giving Tenant any right, power, or authority to contract for or permit the rendering of any services or the furnishing of any materials that would give rise to any mechanic’s or other liens against the Premises, the Building, or the Property. In the event any such lien is attached to the Premises, the Building, or the Property, then, in addition to any other right or remedy of Landlord, Landlord may, but shall not be obligated to, discharge the same. Any amount paid by Landlord for any of the aforesaid purposes including, but not limited to, reasonable attorneys’ fees, shall be paid by Tenant to Landlord promptly on demand as Additional Rent. Tenant shall within ten (10) days of receiving such notice of lien or claim (a) have such lien or claim released or (b) deliver to Landlord a bond in form, content, amount and issued by surety, satisfactory to Landlord, indemnifying, protecting, defending and holding harmless the Landlord, its partners, affiliates or employees against all costs and liabilities resulting from such lien or claim and the foreclosure or attempted foreclosure thereof. Tenant’s failure to comply with the provisions of the foregoing sentence shall be deemed an Event of Default under Section 22 hereof entitling Landlord to exercise all of its remedies therefor without the requirement of any additional notice or cure period.

 

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15.	Insurance.

 

A.

Landlord’s Insurance Landlord shall maintain such insurance on the Building and the Premises (other than on Tenant’s Property or on any additional improvements constructed in the Premises by Tenant), and such liability insurance in such amounts as Landlord elects. The cost of such insurance shall be included as a part of the Basic Costs, and payments for losses thereunder shall be made solely to Landlord or the mortgagees of Landlord as their interests shall appear.

 

B.

Tenant’s Insurance Tenant shall maintain at its expense, (1) in an amount equal to full replacement cost, special form (formerly known as all risk) property insurance on all of its personal property, including removable trade fixtures and leasehold and tenant improvements, and Tenant’s Property located in the Premises and in such additional amounts as are required to meet Tenant’s obligations pursuant to Section 18 hereof and with deductibles in an amount reasonably satisfactory to Landlord, and (ii) a policy or policies of commercial general liability insurance (including endorsement or separate policy for owned or non-owned automobile liability) with respect to its activities in the Building and on the Property, with the premiums thereon fully paid on or before the due date, in an amount of not less than $2,000,000 per occurrence per person coverage for bodily injury, property damage, personal injury or combination thereof (the term “personal injury” as used herein means, without limitation, false arrest, sexual harassment, detention or imprisonment, malicious prosecution, wrongful entry, libel and slander), provided that if only single limit coverage is available it shall be for at least $2,000,000 per occurrence with an umbrella policy of at least $5,000,000 combined single limit per occurrence. Tenant’s insurance policies shall name Landlord and Building Manager as additional insureds and shall include coverage for the contractual liability of Tenant to indemnify Landlord and Building Manager pursuant to Section 16 of this Lease and shall have deductibles in an amount reasonably satisfactory to Landlord. Prior to Tenant’s taking possession of the Premises, Tenant shall furnish evidence satisfactory to Landlord of the maintenance and timely renewal of such insurance, and Tenant shall obtain and deliver to Landlord a written obligation on the part of each insurer to notify Landlord at least thirty (30) days prior to the modification, cancellation or expiration of such insurance policies. In the event Tenant shall not have delivered to Landlord a policy or certificate evidencing such insurance at least thirty (30) days prior to the expiration date of each expiring policy, Landlord may obtain such insurance as Landlord may reasonably require to protect Landlord’s interest (which obtaining of insurance shall not be deemed to be a waiver of Tenant’s default hereunder). The cost to Landlord of obtaining such policies, plus an administrative fee in the amount of fifteen percent (15%) of the cost of such policies shall be paid by Tenant to Landlord as Additional Rent upon demand.

 

C.

Evidence of Coverage The insurance requirements set forth in this Section 15 are independent of the waiver, indemnification, and other obligations under this Lease and will not be construed or interpreted in any way to restrict, limit or modify the waiver, indemnification and other obligations or to in any way limit any party’s liability under this Lease. In addition to the requirements set forth in Sections 15 and 16, the insurance required of Tenant under this Lease must be issued by an insurance company with a rating of no less than A-VIII in the current Best’s Insurance Guide, or A- in the current Standard & Poor Insurance Solvency Review, or in that is otherwise acceptable to Landlord, and admitted to engage in the business of insurance in the state in which the Building is located; be primary insurance for all claims under it and provide that any insurance carried by Landlord and Landlord’s lenders is strictly excess, secondary and noncontributing with any insurance carried by Tenant; and provide that insurance may not be cancelled, nonrenewed or the subject of material change in coverage of available limits of coverage, except upon thirty (30) days prior written notice to Landlord and Landlord’s lenders. Tenant will deliver either a duplicate original or a legally enforceable certificate of insurance on all policies procured by Tenant in compliance with Tenant’s obligations under this Lease, together with evidence satisfactory to Landlord of the payment of the premiums therefor, to Landlord on or before the date Tenant first occupies any portion of the Premises, at least thirty (30) days before the expiration date of any policy and upon the renewal of any policy. Landlord must give its prior written approval to all deductibles and self-insured retentions under Tenant’s policies. Tenant may comply with its insurance coverage requirements through a blanket policy, provided Tenant, at Tenant’s sole expense, procures a “per location” endorsement, or equivalent reasonably acceptable to Landlord, so that the general aggregate and other limits apply separately and specifically to the Premises.

 

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D.

Increase If Tenant’s business operations, conduct or use of the Premises or any other part of the Property causes an increase in the premium for any insurance policy carried by Landlord, Tenant will, within ten (10) days after receipt of notice from Landlord, reimburse Landlord for the entire increase.

 

E.

Waiver Neither Landlord nor Tenant shall be liable (by way of subrogation or otherwise) to the other party (or to any insurance company insuring the other party) for any personal injury or loss or damage to any of the property of Landlord or Tenant, as the case may be, with respect to their respective property, the Building, the Property or the Premises or any addition or improvements thereto, or any contents therein, to the extent covered by insurance carried or required to be carried by a party hereto even though such loss might have been occasioned by the negligence or willful acts or omissions of the Landlord, the Building Manager, or Tenant or their respective employees, agents, contractors or invitees. Since this mutual waiver will preclude the assignment of any such claim by subrogation (or otherwise) to an insurance company (or any other person), Landlord and Tenant each agree to give each insurance company which has issued, or on the future may issue, policies of insurance, with respect to the items covered by this waiver, written notice of the terms of this mutual waiver, and to have such insurance policies properly endorsed, if necessary, to prevent the invalidation of any of the coverage provided by such insurance policies by reason of such mutual waiver. For the purpose of the foregoing waiver, the amount of any deductible applicable to any loss or damage shall be deemed covered by, and recoverable by the insured under the insurance policy to which such deductible relates. In the event that Tenant is permitted to and self-insures any risk for which insurance is required to be carried under this Lease, or if Tenant fails to carry any insurance required to be carried by Tenant pursuant to this Lease, then all loss or damage to Tenant, its leasehold interest, its business, its property, the Premises or any additions or improvements thereto or contents thereof shall be deemed covered by and recoverable by Tenant under valid and collectible policies of insurance. Notwithstanding anything to the contrary herein, Landlord shall not be liable to the Tenant or any insurance company (by way of subrogation or otherwise) insuring the Tenant for any loss or damage to any property, or bodily injury or personal injury or any resulting loss of income or losses from worker’s compensation laws and benefits, even though such loss or damage might have been occasioned by the negligence of Landlord, its agents or employees, or Building Manager, if any such loss or damage was required to be covered by insurance pursuant to this Lease.

 

16.

Indemnity. TENANT HEREBY AGREES TO INDEMNIFY, DEFEND AND HOLD HARMLESS LANDLORD, THE BUILDING MANAGER, AND THEIR RESPECTIVE EMPLOYEES, MEMBERS, PARTNERS, AGENTS, CONTRACTORS, AND LENDERS (SAID PERSONS AND ENTITIES ARE HEREINAFTER COLLECTIVELY REFERRED TO AS THE “INDEMNIFIED PARTIES”) FROM AND AGAINST ANY AND ALL LIABILITY, LOSS, COST, DAMAGE, CLAIMS, DEMANDS, LOSS OF RENTS, LIENS, JUDGMENTS, PENALTIES, FINES, SETTLEMENT COSTS, INVESTIGATION COSTS, COST OF CONSULTANTS AND EXPERTS, ATTORNEYS FEES, COURT COSTS AND OTHER LEGAL EXPENSES, EFFECTS OF ENVIRONMENTAL CONTAMINATION, COST OF ENVIRONMENTAL TESTING, REMOVAL, REMEDIATION AND/OR ABATEMENT OF HAZARDOUS MATERIALS (AS SAID TERM IS DEFINED BELOW), INSURANCE POLICY DEDUCTIBLES AND OTHER EXPENSES (HEREINAFTER COLLECTIVELY REFERRED TO AS “DAMAGES”) ARISING OUT OF OR RELATED TO AN INDEMNIFIED MATTER (AS DEFINED BELOW), UNLESS CAUSED BY THE INDEMNIFIED PARTY’S SOLE NEGLIGENCE, GROSS NEGLIGENCE OR WILLFUL MISCONDUCT. FOR PURPOSES OF THIS SECTION, AN “INDEMNIFIED MATTER” SHALL MEAN ANY MATTER FOR WHICH ONE OR MORE OF THE INDEMNIFIED PARTIES INCURS LIABILITY OR DAMAGES IF THE LIABILITY OR DAMAGES ARISE OUT OF OR INVOLVE, DIRECTLY OR INDIRECTLY, (A) TENANT’S OR ITS EMPLOYEES’, AGENTS’, CONTRACTORS’ OR INVITEES’ (ALL OF SAID PERSONS OR ENTITIES ARE HEREINAFTER COLLECTIVELY REFERRED TO AS “TENANT PARTIES”) USE OR OCCUPANCY OF THE PREMISES, (B) ANY ACT, OMISSION OR NEGLECT OF A TENANT PARTY, (C) TENANT’S FAILURE TO PERFORM ANY OF ITS OBLIGATIONS UNDER THE LEASE, (D) THE EXISTENCE, USE OR DISPOSAL OF ANY HAZARDOUS SUBSTANCE (AS DEFINED BELOW) BROUGHT ON TO THE PREMISES BY A TENANT PARTY OR (E) ANY OTHER MATTERS FOR WHICH TENANT HAS AGREED TO INDEMNIFY LANDLORD PURSUANT TO ANY OTHER PROVISION OF THIS LEASE. TENANT’S OBLIGATIONS HEREUNDER SHALL INCLUDE, BUT SHALL NOT BE LIMITED TO (F) COMPENSATING THE INDEMNIFIED PARTIES FOR ACTUAL DAMAGES ARISING OUT OF INDEMNIFIED MATTERS

 

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WITHIN TEN (10) DAYS AFTER WRITTEN DEMAND FROM AN INDEMNIFIED PARTY AND (G) PROVIDING A DEFENSE, WITH COUNSEL REASONABLY SATISFACTORY TO THE INDEMNIFIED PARTY, AT TENANT’S SOLE EXPENSE, WITHIN TEN (10) DAYS AFTER WRITTEN DEMAND FROM THE INDEMNIFIED PARTY, OF ANY CLAIMS, ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO AN INDEMNIFIED MATTER, WHETHER OR NOT LITIGATED OR REDUCED TO JUDGMENT AND WHETHER OR NOT WELL-FOUNDED. IF TENANT IS OBLIGATED TO COMPENSATE AN INDEMNIFIED PARTY FOR DAMAGES ARISING OUT OF AN INDEMNIFIED MATTER, LANDLORD SHALL HAVE THE IMMEDIATE AND UNCONDITIONAL RIGHT, BUT NOT THE OBLIGATION, WITHOUT NOTICE OR DEMAND TO TENANT, TO PAY THE DAMAGES, AND TENANT SHALL, UPON TEN (10) DAYS’ WRITTEN NOTICE FROM LANDLORD, REIMBURSE LANDLORD FOR THE COSTS INCURRED BY LANDLORD. BY WAY OF EXAMPLE, AND NOT LIMITATION, LANDLORD SHALL HAVE THE IMMEDIATE AND UNCONDITIONAL RIGHT TO CAUSE ANY DAMAGES TO THE COMMON AREAS, ANOTHER TENANT’S PREMISES OR TO ANY OTHER PART OF THE BUILDING TO BE REPAIRED AND TO COMPENSATE OTHER TENANTS OF THE BUILDING OR OTHER PERSONS OR ENTITIES FOR DAMAGES ARISING OUT OF AN INDEMNIFIED MATTER. EXCEPT FOR, AND TO THE EXTENT OF, THE INDEMNIFIED PARTY’S SOLE NEGLIGENCE, GROSS NEGLIGENCE OR WILLFUL MISCONDUCT, THE INDEMNIFIED PARTIES NEED NOT FIRST PAY ANY DAMAGES IN ORDER TO BE INDEMNIFIED HEREUNDER. EXCEPT FOR, AND TO THE EXTENT OF, AN INDEMNIFIED PARTY’S SOLE NEGLIGENCE, GROSS NEGLIGENCE OR WILLFUL MISCONDUCT, TENANT’S OBLIGATIONS UNDER THIS SECTION SHALL NOT BE RELEASED, REDUCED OR OTHERWISE LIMITED BECAUSE ONE OR MORE OF THE INDEMNIFIED PARTIES ARE OR MAY BE ACTIVELY OR PASSIVELY NEGLIGENT WITH RESPECT TO AN INDEMNIFIED MATTER OR BECAUSE AN INDEMNIFIED PARTY IS OR WAS PARTIALLY RESPONSIBLE FOR THE DAMAGES INCURRED. THIS INDEMNITY IS INTENDED TO APPLY TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW. TENANT’S OBLIGATIONS UNDER THIS SECTION SHALL SURVIVE THE EXPIRATION OR TERMINATION OF THIS LEASE UNLESS SPECIFICALLY WAIVED IN WRITING BY LANDLORD AFTER SAID EXPIRATION OR TERMINATION. NOTWITHSTANDING ANYTHING TO THE CONTRARY CONTAINED IN THIS LEASE, NOTHING IN THIS LEASE SHALL IMPOSE ANY OBLIGATIONS ON TENANT OR LANDLORD OR THE BUILDING MANAGER TO BE RESPONSIBLE OR LIABLE FOR, AND EACH HEREBY RELEASES THE OTHER FROM ALL LIABILITY FOR, CONSEQUENTIAL DAMAGES OTHER THAN THOSE CONSEQUENTIAL DAMAGES INCURRED BY LANDLORD IN CONNECTION WITH A HOLDOVER OF THE PREMISES BY TENANT AFTER THE EXPIRATION OR EARLIER TERMINATION OF THIS LEASE OR INCURRED BY LANDLORD IN CONNECTION WITH ANY REPAIR, PHYSICAL CONSTRUCTION OR IMPROVEMENT WORK PERFORMED BY OR ON BEHALF OF TENANT IN THE BUILDING.

 

17.

Exemption of Landlord from Liability. TENANT HEREBY AGREES THAT NEITHER LANDLORD OR THE BUILDING MANAGER SHALL BE LIABLE FOR INJURY TO TENANT’S BUSINESS OR ANY LOSS OF INCOME THEREFROM OR FOR LOSS OF OR DAMAGE TO THE MERCHANDISE, TENANT IMPROVEMENTS, FIXTURES, FURNITURE, EQUIPMENT, COMPUTERS, FILES, AUTOMOBILES, OR OTHER PROPERTY OF TENANT, TENANT’S EMPLOYEES, AGENTS, CONTRACTORS OR INVITEES, OR ANY OTHER PERSON IN OR ABOUT THE BUILDING, NOR SHALL LANDLORD OR THE BUILDING MANAGER BE LIABLE FOR INJURY TO THE PERSON OF TENANT, TENANT’S EMPLOYEES, AGENTS, CONTRACTORS OR INVITEES, WHETHER SUCH DAMAGE OR INJURY IS CAUSED BY OR RESULTS FROM ANY CAUSE WHATSOEVER INCLUDING, BUT NOT LIMITED TO, THEFT, CRIMINAL ACTIVITY AT THE BUILDING, NEGLIGENT SECURITY MEASURES, BOMBINGS OR BOMB SCARES, ACTS OF WAR, TERRORIST ACTIVITIES, HAZARDOUS MATERIALS, FIRE, STEAM, ELECTRICITY, GAS, WATER OR RAIN, FLOODING, BREAKAGE OF PIPES, SPRINKLERS, PLUMBING, AIR CONDITIONING OR LIGHTING FIXTURES, OR FROM ANY OTHER CAUSE, WHETHER SAID DAMAGE OR INJURY RESULTS FROM CONDITIONS ARISING UPON THE PREMISES OR UPON OTHER PORTIONS OF THE BUILDING, OR FROM OTHER SOURCES OR PLACES, OR FROM NEW CONSTRUCTION OR THE REPAIR, ALTERATION OR IMPROVEMENT OF ANY PART OF THE BUILDING, EXCEPT IF THE CAUSE OF THE LOSS, DAMAGE OR INJURY ARISES OUT OF LANDLORD’S, THE BUILDING MANAGER’S OR THEIR RESPECTIVE EMPLOYEES’, AGENTS’ OR CONTRACTORS’ SOLE NEGLIGENCE, GROSS NEGLIGENCE, INTENTIONAL ACTS, OR WILLFUL

 

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MISCONDUCT. NEITHER THE LANDLORD NOR THE BUILDING MANAGER SHALL BE LIABLE FOR ANY DAMAGES ARISING FROM ANY ACT OR NEGLECT OF ANY EMPLOYEES, AGENTS, CONTRACTORS OR INVITEES OF ANY OTHER TENANT, OCCUPANT OR USER OF THE BUILDING, NOR FROM THE FAILURE OF LANDLORD OR BUILDING MANAGER TO ENFORCE THE PROVISIONS OF THE LEASE OF ANY OTHER TENANT OF THE BUILDING. TENANT, AS A MATERIAL PART OF THE CONSIDERATION TO LANDLORD HEREUNDER, HEREBY ASSUMES ALL RISK OF DAMAGE TO TENANT’S PROPERTY OR BUSINESS OR INJURY TO PERSONS IN, UPON OR ABOUT THE PREMISES ARISING FROM ANY CAUSE, INCLUDING LANDLORD’S OR BUILDING MANAGER’S NEGLIGENCE OR THE NEGLIGENCE OF THEIR RESPECTIVE EMPLOYEES, AGENTS OR CONTRACTORS, BUT, EXCLUDING THE SOLE NEGLIGENCE, GROSS NEGLIGENCE, INTENTIONAL ACTS OR WILLFUL MISCONDUCT OF THE LANDLORD OR BUILDING MANAGER OR THEIR RESPECTIVE EMPLOYEES, AGENTS OR CONTRACTORS, OR THE MATERIAL BREACH BY LANDLORD OF THIS LEASE, AND TENANT HEREBY WAIVES ALL CLAIMS IN RESPECT THEREOF AGAINST LANDLORD, THE BUILDING MANAGER OR THEIR RESPECTIVE EMPLOYEES, AGENTS AND CONTRACTORS. NO PARTNER, EMPLOYEE OR AGENT OF LANDLORD OR THE BUILDING MANAGER SHALL BE PERSONALLY LIABLE FOR THE PERFORMANCE OF LANDLORD’S OBLIGATIONS HEREUNDER OR BE NAMED AS A PARTY IN ANY LAWSUIT ARISING OUT OF OR RELATED TO, DIRECTLY OR INDIRECTLY, THIS LEASE AND THE OBLIGATIONS OF LANDLORD HEREUNDER.

 

18.

Casualty Damage. If the Premises or any part thereof shall be damaged by fire or other casualty, Tenant shall give prompt written notice thereof to Landlord. In case the Building shall be so damaged that substantial alteration or reconstruction of the Building shall, in Landlord’s sole opinion, be required (whether or not the Premises shall have been damaged by such casualty) or in the event Landlord’s mortgagee should require that the insurance proceeds payable as a result of a casualty be applied to the payment of the mortgage debt or in the event of any material uninsured loss to the Building, Landlord may, at its option, terminate this Lease by notifying Tenant in writing of such termination within ninety (90) days after the date of such casualty. If Landlord does not thus elect to terminate this Lease, Landlord shall commence and proceed with reasonable diligence to restore the Building, and the improvements located within the Premises, if any (except that Landlord shall not be responsible for delays not within the control of Landlord) to substantially the same condition in which it was immediately prior to the happening of the casualty. Notwithstanding the foregoing, Landlord’s obligation to restore the Building, and the improvements located within the Premises, if any, shall not require Landlord to expend for such repair and restoration work more than the insurance proceeds actually received by the Landlord as a result of the casualty and Landlord’s obligation to restore shall be further limited so that Landlord shall not be required to expend for the repair and restoration of the improvements located within the Premises, if any, more than the dollar amount it expended to construct such improvements in the Premises. When the repairs described in the preceding two sentences have been completed by Landlord, Tenant shall complete the restoration of all improvements, including furniture, fixtures and equipment, which are necessary to permit Tenant’s re-occupancy of the Premises. Tenant shall present Landlord with evidence satisfactory to Landlord of Tenant’s ability to pay such foregoing costs, prior to Landlord’s commencement of such repair and restoration to the Premises. Landlord shall not be liable for any inconvenience or annoyance to Tenant or injury to the business of Tenant resulting in any way from such damage or the repair thereof, except that, subject to the provisions of the next sentence, Landlord shall allow Tenant a fair diminution of Rent, equal to a pro rata decrease based on the then applicable Monthly Installment of Base Rent as set forth herein, during the time and in proportion to the extent the Premises are unfit for occupancy by Tenant by reason of such damage and the required repair and restoration of the Property. If the Premises or any other portion of the Property is damaged by fire or other casualty resulting from the fault or negligence of Tenant or any of Tenant’s agents, employees, or invitees, the Rent payable hereunder shall not be diminished during the repair of such damage and Tenant shall be liable to Landlord for the cost of the repair and restoration of the Property caused thereby to the extent such cost and expense is not covered by insurance proceeds.

 

19.

Condemnation. If the whole or any substantial part of the Premises or if the Building or any portion thereof which would leave the remainder of the Building unsuitable for use as an office building comparable to its use on the Commencement Date, or if the land on which the Building is located or any material

 

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portion thereof, shall be taken or condemned for any public or quasi-public use under governmental law, ordinance or regulation, or by right of eminent domain, or by private purchase in lieu thereof, then Landlord may, at its option, terminate this Lease and the rent shall be abated during the unexpired portion of this Lease, effective when the physical taking of said Premises or said portion of the Building or land shall occur. In the event this Lease is not terminated, the rent for any portion of the Premises so taken or condemned shall be abated during the unexpired term of this Lease effective when the physical taking of said portion of the Premises shall occur. All compensation awarded for any such taking or condemnation, or sale proceeds in lieu thereof, shall be the property of Landlord, and Tenant shall have no claim thereto, the same being hereby expressly waived by Tenant, except for any portions of such award or proceeds which are specifically allocated by the condemning or purchasing party for the taking of or damage to trade fixtures of Tenant, which Tenant specifically reserves to itself.

 

20.	Hazardous Substances.

 

A.

General Tenant hereby represents and covenants to Landlord the following: No toxic or hazardous substances or wastes, pollutants or contaminants (including, without limitation, asbestos, urea formaldehyde, the group of organic compounds known as polychlorinated biphenyls, petroleum products including gasoline, fuel oil, crude oil and various constituents of such products, radon, and any hazardous substance as defined in the Comprehensive Environmental Response, Compensation and Liability Act of 1980, 42 U.S.C. 9601-9657, as amended (“CERCLA”) (collectively, “Environmental Pollutants”) other than customary office supplies and cleaning supplies stored and handled within the Premises in accordance with all applicable laws, will be generated, treated, stored, released or disposed of, or otherwise placed, deposited in or located on the Property, and no activity shall be taken on the Property, by Tenant, its agents, employees, invitees or contractors, that would cause or contribute to (i) the Property or any part thereof to become a generation, treatment, storage or disposal facility within the meaning of or otherwise bring the Property within the ambit of the Resource Conservation and Recovery Act of 1976 (“RCRA”), 42 U.S.C. 5901 et. seq., or any similar state law or local ordinance, (ii) a release or threatened release of toxic or hazardous wastes or substances, pollutants or contaminants, from the Property or any part thereof within the meaning of, or otherwise result in liability in connection with the Property within the ambit of CERCLA, or any similar state law or local ordinance, or (iii) the discharge of pollutants or effluents into any water source or system, the dredging or filling of any waters, or the discharge into the air of any emissions, that would require a permit under the Federal Water Pollution Control Act, 33 U.S.C. 1251 et. seq., or the Clean Air Act, 42 U.S.C. 7401 et. seq., or any similar state law or local ordinance.

 

B.

Waiver Tenant expressly waives, to the extent allowed by law, any claims under federal, state or other law that Tenant might otherwise have against Landlord relating to the condition of such Property or the Premises or the Leasehold Improvements or personal property located thereon or the presence in or contamination of the Property or the Premises by hazardous materials. Tenant agrees to indemnify and hold Indemnitees (as defined in Section 16) harmless from and against and to reimburse Indemnitees with respect to, any and all claims, demands, causes of action, loss, damage, liabilities, costs and expenses (including attorneys’ fees and court costs) of any and every kind or character, known or unknown, fixed or contingent, asserted against or incurred by Landlord at any time and from time-to-time by reason of or arising out of the breach by Tenant of any representation or covenant contained in Section 20.A above.

 

C.

Notification Tenant shall immediately notify Landlord in writing of any release or threatened release of toxic or hazardous wastes or substances, pollutants or contaminants of which Tenant has knowledge whether or not the release is in quantities that would require under law the reporting of such release to a governmental or regulatory agency.

 

D.

Reporting Tenant shall also immediately notify Landlord in writing of, and shall contemporaneously provide Landlord with a copy of:

 

(i)

Any written notice of release of hazardous wastes or substances, pollutants or contaminants on the Property that is provided by Tenant or any subtenant or other occupant if the Premises to a governmental or regulatory agency;

 

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(ii)

Any notice of a violation, or a potential or alleged violation, of any Environmental Law (hereinafter defined) that is received by Tenant or any subtenant or other occupant of the Premises from any governmental or regulatory agency;

 

(iii)

Any inquiry, investigation, enforcement, cleanup, removal, or other action that is instituted or threatened by a governmental or regulatory agency against Tenant or any subtenant or other occupant of the Premises and that relates to the release or discharge of hazardous wastes or substances, pollutants or contaminants on or from the Property;

 

(iv)

Any claim that is instituted or threatened by any third-party against Tenant or any subtenant or other occupant of the Premises and that relates to any release or discharge of hazardous wastes or substances, pollutants or contaminants on or from the Property; and

 

(v)

Any notice of the loss of any environmental operating permit by Tenant or any subtenant or other occupant of the Premises.

 

E.

Defined Term As used herein “Environmental Laws” mean all present and future federal, state and municipal laws, ordinances, rules and regulations applicable to environmental and ecological conditions, and the rules and regulations of the U.S. Environmental Protection Agency, and any other federal, state or municipal agency, or governmental board or entity relating to environmental matters.

 

21.

Americans with Disabilities Act. Tenant agrees to comply with all requirements of the Americans with Disabilities Act (Public Law (July 26, 1990) (“ADA”) applicable to the Premises and such other current acts or other subsequent acts, (whether federal or state) addressing like issues as are enacted or amended. Tenant agrees to indemnify and hold Landlord harmless from any and all expenses, liabilities, costs or damages suffered by Landlord as a result of additional obligations which may be imposed on the Building or the Property under of such acts by virtue of Tenant’s operations and/or occupancy, unless due to the sole or gross negligence, or willful misconduct of the Landlord. Tenant acknowledges that it will be wholly responsible for any provision of the Lease, which could arguably be construed as authorizing a violation of the ADA. Any such provision shall be interpreted in a manner, which permits compliance with the ADA and is hereby amended to permit such compliance.

 

22.	Events of Default.

The following events shall be deemed to be “Events of Default” under this Lease:

 

(i)

Tenant shall fail to pay when due any Base Rent, Additional Rent or other amount payable by Tenant to Landlord under this Lease (hereinafter sometimes referred to as a “Monetary Default”).

 

(ii)

Any failure by Tenant (other than a Monetary Default) to comply with any term, provision or covenant of this Lease, which failure is not cured within twenty (20) days after delivery to Tenant of notice of the occurrence of such failure provided, however, that if the term, condition, covenant or obligation to be performed by Tenant is of such nature that the same cannot reasonably be performed within such twenty-day period, such default shall be deemed to have been cured if Tenant commences such performance within said twenty-day period and thereafter diligently undertakes to complete the same, and, in fact, completes same within forty-five (45) days after the delivery of that notice. It is expressly provided, however, that if Tenant shall fail to comply with any material term, provision or covenant of this Lease twice during any twelve (12) month Lease Term, then, and in such event, the occurrence of the second such failure within the Lease Term, shall be deemed to be an Event of Default immediately upon the Landlord’s delivery of notice to Tenant of such failure without any opportunity required to be provided by Landlord to Tenant in such instance to cure such failure. In such event, Landlord shall then be entitled to exercise any and all of the Remedies set forth in Section 23 to include, without limitation, the right to immediately terminate this Lease pursuant to Section 23(A)(2).

 

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(iii)

Any failure by Tenant to observe or perform any of the covenants with respect to (a) assignment and subletting set forth in Section 13, (b) mechanic’s liens set forth in Section 14, or (c) insurance set forth in Section 15.

 

(iv)

Tenant shall (a) become insolvent, (b) make a transfer in fraud of creditors (c) make an assignment for the benefit of creditors, (d) admit in writing its inability to pay its debts as they become due, (e) file a petition under any section or chapter of the United States Bankruptcy Code, as amended, pertaining to bankruptcy, or under any similar law or statute of the United States or any State thereof, or Tenant shall be adjudged bankrupt or insolvent in proceedings filed against Tenant thereunder; or a petition or answer proposing the adjudication of Tenant as a bankrupt or its reorganization under any present or future federal or state bankruptcy or similar law shall be filed in any court and such petition or answer shall not be discharged or denied within sixty (60) days after the filing thereof.

 

(v)

A receiver or trustee shall be appointed for all or substantially all of the assets of Tenant or of the Premises or of any of Tenant’s property located thereon in any proceeding brought by Tenant, or any such receiver or trustee shall be appointed in any proceeding brought against Tenant and shall not be discharged within sixty (60) days after such appointment or Tenant shall consent to or acquiesce in such appointment.

 

(vi)

The leasehold estate hereunder shall be taken on execution or other process of law in any action against Tenant.

 

(vii)

Tenant shall abandon or vacate any substantial portion of the Premises.

 

(viii)

Tenant shall fail to take possession of and occupy the Premises within thirty (30) days following the Commencement Date and thereafter continuously conduct its operations in the Premises for the Permitted Use as set forth in Section 4 hereof.

 

(ix)

The liquidation, termination, dissolution, forfeiture of right to do business of Tenant.

 

23.

Remedies.

 

A.

Default Upon the occurrence of any Event of Default, Landlord shall have the following rights and remedies, in addition to those allowed by law or equity, any one or more of which may be exercised without further notice to or demand upon Tenant and which may be pursued successively or cumulatively as Landlord may elect:

 

(i)

Landlord may re-enter the Premises and cure any default of Tenant, in which event Tenant shall, upon demand, reimburse Landlord as Additional Rent for any cost and expenses which Landlord may incur to cure such default; and Landlord shall not be liable to Tenant for any loss or damage which Tenant may sustain by reason of Landlord’s action, unless caused by Landlord’s sole or gross negligence or willful misconduct;

 

(ii)

Landlord may terminate this Lease by giving to Tenant notice of Landlord’s election to do so, in which event the Term shall end, and all right, title and interest of Tenant hereunder shall expire, on the date stated in such notice;

 

(iii)

Landlord may terminate the right of Tenant to possession of the Premises without terminating this Lease by giving notice to Tenant that Tenant’s right to possession shall end on the date stated in such notice, whereupon the right of Tenant to possession of the Premises or any part thereof shall cease on the date stated in such notice; and

 

(iv)

Landlord may enforce the provisions of this Lease and may enforce and protect the rights of Landlord hereunder by a suit or suits in equity or at law for the specific performance of any

 

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covenant or agreement contained herein, or for the enforcement of any other appropriate legal or equitable remedy, including recovery of all moneys due or to become due from Tenant under any of the provisions of this Lease.

Landlord shall not be required to serve Tenant with any notices or demands as a prerequisite to its exercise of any of its rights or remedies under this Lease, other than those notices and demands specifically required under this Lease. TENANT EXPRESSLY WAIVES THE SERVICE OF ANY STATUTORY DEMAND OR NOTICE, WHICH IS A PREREQUISITE TO LANDLORD’S COMMENCEMENT OF EVICTION PROCEEDINGS AGAINST TENANT. LANDLORD AND TENANT EACH HEREBY EXPRESSLY WAIVE ANY RIGHT TO TRIAL BY JURY IN ANY LAWSUIT BROUGHT BY LANDLORD TO RECOVER POSSESSION OF THE PREMISES FOLLOWING LANDLORD’S TERMINATION OF THIS LEASE PURSUANT TO SECTION 23A(ii) OR THE RIGHT OF TENANT TO POSSESSION OF THE PREMISES PURSUANT TO SECTION 23A(iii), ON ANY CLAIM FOR DELINQUENT RENT OR OTHER DAMAGE CLAIMS WHICH LANDLORD MAY JOIN IN ITS LAWSUIT TO RECOVER POSSESSION, AND/OR AS TO ANY OTHER LEGAL ACTION BROUGHT BY EITHER LANDLORD OR TENANT TO ENFORCE THE PROVISIONS OF THIS LEASE.

 

B.

Surrender If Landlord exercises either of the remedies provided in Sections 23.A.(ii) or 23.A.(iii), Tenant shall surrender possession and vacate the Premises and immediately deliver possession thereof to Landlord, and Landlord may re-enter and take complete and peaceful possession of the Premises, with process of law, full and complete license to do so being hereby granted to Landlord, and Landlord may remove all occupants and property therefrom, using such force as may be necessary to the extent allowed by law, without being deemed guilty in any manner of trespass, eviction or forcible entry and detainer and without relinquishing Landlord’s right to Rent or any other right given to Landlord hereunder or by operation of law.

 

C.

Possession If Landlord terminates the right of Tenant to possession of the Premises without terminating this Lease, Landlord shall have the right to immediate recovery of all amounts then due hereunder. Such termination of possession shall not release Tenant, in whole or in part, from Tenant’s obligation to pay Rent hereunder for the full Term, and Landlord shall have the right, from time to time, to recover from Tenant, and Tenant shall remain liable for, all Base Rent, Additional Rent and any other sums accruing as they become due under this Lease during the period from the date of such notice of termination of possession to the stated end of the Term. In any such case, Landlord may relet the Premises or any part thereof for the account of Tenant for such rent, for such time (which may be for a term extending beyond the Term) and upon such terms as Landlord shall determine and may collect the rents from such reletting. Landlord shall not be required to accept any tenant offered by Tenant or to observe any instructions given by Tenant relative to such reletting. Also, in any such case, Landlord may make repairs, alterations and additions in or to the Premises and redecorate the same to the extent reasonably deemed necessary by Landlord and in connection therewith change the locks to the Premises, and Tenant upon demand shall pay the cost of all of the foregoing together with Landlord’s expenses of reletting. The rents from any such reletting shall be applied first to the payment of the expenses of reentry, redecoration, repair and alterations and the expenses of reletting and second to the payment of Rent herein provided to be paid by Tenant. Any excess or residue shall operate only as an offsetting credit against the amount of Rent due and owing as the same thereafter becomes due and payable hereunder, and the use of such offsetting credit to reduce the amount of Rent due Landlord, if any, shall not be deemed to give Tenant any right, title or interest in or to such excess or residue and any such excess or residue shall belong to Landlord solely, and in no event shall Tenant be entitled to a credit on its indebtedness to Landlord in excess of the aggregate sum (including Base Rent and Additional Rent) which would have been paid by Tenant for the period for which the credit to Tenant is being determined, had no Event of Default occurred. No such reentry or repossession, repairs, alterations and additions, or reletting shall be construed as an eviction or ouster of Tenant or as an election on Landlord’s part to terminate this Lease, unless a written notice of such intention is given to Tenant, or shall operate to release Tenant in whole or in part from any of Tenant’s obligations hereunder, and Landlord, at any time and from time to time, may sue and recover judgment for any deficiencies remaining after the application of the proceeds of any such reletting.

 

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D.

Termination If this Lease is terminated by Landlord pursuant to Section 23.A.(ii), Landlord shall be entitled to recover from Tenant all Rent accrued and unpaid for the period up to and including such termination date, as well as all other additional sums payable by Tenant, or for which Tenant is liable or for which Tenant has agreed to indemnify Landlord under any of the provisions of this Lease, which may be then owing and unpaid, and all costs and expenses, including without limitation court costs and attorneys’ fees incurred by Landlord in the enforcement of its rights and remedies hereunder, and, in addition, Landlord shall be entitled to recover as damages for loss of the bargain and not as a penalty (i) the unamortized portion of any concessions offered by Landlord to Tenant in connection with this Lease, and the cost of all tenant improvements and alterations, if any, installed by either Landlord or Tenant pursuant to this Lease or any work letter entered into in connection with this Lease, (ii) the aggregate sum which at the time of such termination represents the excess, if any, of the present value of the aggregate rents which would have been payable after the termination date had this Lease not been terminated, including, without limitation, Base Rent at the annual rate or respective annual rates for the remainder of the Term provided for in this Lease and the amount projected by Landlord to represent Additional Rent for the remainder of the Term over the then present value of the then aggregate fair rent value of the Premises for the balance of the Term, such present worth to be computed in each case on the basis of a ten percent (10%) per annum discount from the respective dates upon which such Rents would have been payable hereunder had this Lease not been terminated, and (iii) any damages in addition thereto, including without limitation reasonable attorneys’ fees and court costs, which Landlord sustains as a result of the breach of any of the covenants of this Lease other than for the payment of Rent.

 

E.

Mitigation Landlord shall use commercially reasonable efforts to mitigate any damages resulting from an Event of Default by Tenant under this Lease. Landlord’s obligation to mitigate damages after an Event of Default by Tenant under this Lease shall be satisfied in full if Landlord undertakes to lease the Premises to another tenant (a “Substitute Tenant”) in accordance with the following criteria:

 

(i)

Landlord shall have no obligations to solicit or entertain negotiations with any other prospective tenants for the Premises until Landlord obtains full and complete possession of the Premises including, without limitation, the final and unappealable legal right to relet the Premises free of any claim of Tenant;

 

(ii)

Landlord shall not be obligated to lease or show the Premises, on a priority basis, offer the Premises to a prospective tenant when other premises in the Building suitable for that prospective tenant’s use are (or soon will be) available;

 

(iii)

Landlord shall not be obligated to lease the Premises to a Substitute Tenant for a Rent less than the current fair market Rent then prevailing for similar uses in comparable buildings in the same market area as the Building, nor shall Landlord be obligated to enter into a new lease under other terms and conditions that are unacceptable to Landlord under Landlord’s then current leasing policies for comparable space in the Building;

 

(iv)

Landlord shall not be obligated to enter into a lease with a Substitute Tenant whose use would:

 

(1)

violate any restriction, covenant, or requirement contained in the lease of another tenant of the Building;

 

(2)

adversely affect the reputation of the Building; or

 

(3)

be incompatible with the operation of the Building as an office building;

 

(v)

Landlord shall not be obligated to enter into a lease with any proposed Substitute Tenant which does not have, in Landlord’s reasonable opinion, sufficient financial resources to operate the Premises in a first class manner; and

 

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(vi)

Landlord shall not be required to expend any amount of money to alter, remodel, or otherwise make the Premises suitable for use by a proposed Substitute Tenant unless:

 

(1)

Tenant pays any such sum to Landlord in advance of Landlord’s execution of a lease with such tenant (which payment shall not be in lieu of any damages or other sums to which Landlord may be entitled as a result of Tenant’s default under this Lease); or

 

(2)

Landlord, in Landlord’s reasonable discretion, determines that any such expenditure is financially justified in connection with entering into any such substitute lease.

 

F.

Tenant Property All property of Tenant removed from the Premises by Landlord pursuant to any provision of this Lease or applicable law may be handled, removed or stored by Landlord at the cost and expense of Tenant, and Landlord shall not be responsible in any event for the value, preservation or safekeeping thereof. Tenant shall pay Landlord for all expenses incurred by Landlord with respect to such removal and storage so long as the same is in Landlord’s possession or under Landlord’s control. All such property not removed from the Premises or retaken from storage by Tenant within thirty (30) days after the end of the Term or the termination of Tenant’s right to possession of the Premises, however terminated, at Landlord’s option, shall be conclusively deemed to have been conveyed by Tenant to Landlord as by bill of sale without further payment or credit by Landlord to Tenant.

 

G.

Bankruptcy If Tenant is adjudged bankrupt, or a trustee in bankruptcy is appointed for Tenant, Landlord and Tenant, to the extent permitted by law, agree to request that the trustee in bankruptcy determine within sixty (60) days thereafter whether to assume or to reject this Lease.

 

H.

Non-Waiver of Remedies The receipt by Landlord of less than the full rent due shall not be construed to be other than a payment on account of rent then due, nor shall any statement on Tenant’s check or any letter accompanying Tenant’s check be deemed an accord and satisfaction, and Landlord may accept such payment without prejudice to Landlord’s right to recover the balance of the rent due or to pursue any other remedies provided in this lease. The acceptance by Landlord of rent hereunder shall not be construed to be a waiver of any breach by Tenant of any term, covenant or condition of this Lease. No act or omission by Landlord or its employees or agents during the term of this Lease shall be deemed an acceptance of a surrender of the Premises, and no agreement to accept such surrender shall be valid unless in writing and signed by Landlord.

 

I.

Enforcement In the event of any litigation between Tenant and Landlord to enforce any provision of this Lease or any right of either party hereto, the unsuccessful party to such litigation shall pay to the successful party all costs and expenses, including reasonable attorney’s fees, incurred therein. Furthermore, if Landlord, without fault, is made a party to any litigation instituted by or against Tenant, Tenant shall indemnify Landlord against, and protect, defend, and save it harmless from, all costs and expenses, including reasonable attorney’s fees, incurred by it in connection therewith. If Tenant, without fault, is made party to any litigation instituted by or against Landlord, Landlord shall indemnify Tenant against, and protect, defend, and save it harmless from, all costs and expenses, including reasonable attorney’s fees, incurred by it in connection therewith.

 

24.

No Waiver. Failure of Landlord to declare any default immediately upon its occurrence, or delay in taking any action in connection with an event of default, shall not constitute a waiver of such default, nor shall it constitute an estoppel against Landlord, but Landlord shall have the right to declare the default at any time and take such action as is lawful or authorized under this Lease. Failure by Landlord to enforce its rights with respect to any one default shall not constitute a waiver of its rights with respect to any subsequent default.

 

25.

Peaceful Enjoyment. Tenant shall, and may peacefully have, hold, and enjoy the Premises, subject to the other terms hereof, provided that Tenant pays the Rent and other sums herein recited to be paid by Tenant and timely performs all of Tenant’s covenants and agreements herein contained. This covenant and any and all other covenants of Landlord shall be binding upon Landlord and its successors only with respect to breaches occurring during its or their respective periods of ownership of the Landlord’s interest hereunder.

 

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26.	[INTENTIONALLY DELETED]

 

27.

Holding Over. In the event of holding over by Tenant after expiration or other termination of this Lease or in the event Tenant continues to occupy the Premises after the termination of Tenant’s right of possession pursuant to Section 23.A.(iii) hereof, occupancy of the Premises subsequent to such termination or expiration shall be that of a tenancy at sufferance and in no event for month-to-month or year-to-year. Tenant shall, throughout the entire holdover period, be subject to all the terms and provisions of this Lease and shall pay for its use and occupancy an amount (on a per month basis without reduction for any partial months during any such holdover) equal to twice the sum (or 200%) of (a) the greater of then current market rate, or (b) the Base Rent and Additional Rent which would have been applicable had the Lease Term continued through the period of such holding over by Tenant. No holding over by Tenant or payments of money by Tenant to Landlord after the expiration of the Lease Term shall be construed to extend the Lease Term or prevent Landlord from recovery of immediate possession of the Premises by summary proceedings or otherwise unless Landlord has sent written notice to Tenant that Landlord has elected to extend the Lease Term. In addition to the obligation to pay the amounts set forth above during any such holdover period, Tenant shall also be liable to Landlord for all damages, including, without limitation, any consequential damages, which Landlord may suffer by reason of any holding over by Tenant and Tenant shall also indemnify Landlord against any and all claims made by any other tenant or prospective tenant against Landlord for delay by Landlord in delivering possession of the Premises to such other tenant or prospective tenant.

 

28.

Subordination to Mortgage/Estoppel Certificate. Tenant accepts this Lease subject and subordinate to any mortgage, deed of trust or other lien presently existing or hereafter arising upon the Premises, or upon the Building and/or the Property and to any renewals, modifications, refinancings and extensions thereof, but Tenant agrees that any such mortgagee shall have the right at any time to subordinate such mortgage, deed of trust or other lien to this Lease on such terms and subject to such conditions as such mortgagee may deem appropriate in its discretion. The provisions of the foregoing sentence shall be self-operative and no further instrument of subordination shall be required. However, Landlord is hereby irrevocably vested with full power and authority to subordinate this Lease to any mortgage, deed of trust or other lien now existing or hereafter placed upon the Premises, or the Building and/or the Property. Tenant covenants and agrees that it will execute and deliver to Landlord and Landlord’s mortgagee, Legacy Bank, on the same date it executes this Lease that certain Subordination, Non-Disturbance and Attornment Agreement, substantially in the form that is attached to this Lease as Exhibit “E” hereto. Landlord will provide a fully executed copy of the Subordination, Non-Disturbance and Attornment Agreement to Tenant as soon as it receives it from the mortgagee. In addition, Tenant agrees within ten (10) days after demand therefore hereto to execute such further instruments subordinating this Lease or attorning to the holder of any such liens as Landlord may request. The terms of this Lease are subject to approval by the Landlord’s existing lender(s) and any lender(s) who, at the time of the execution of this Lease, have committed or are considering committing to Landlord to make a loan secured by all or any portion of the Property, and such approval is a condition precedent to Landlord’s obligations hereunder. In the event that Tenant should fail to execute any subordination or other agreement required by this Section promptly as requested, Tenant hereby irrevocably constitutes Landlord as its attorney-in-fact to execute such instrument in Tenant’s name, place and stead, it being agreed that such power is one coupled with an interest in Landlord and is accordingly irrevocable. Tenant agrees that it will from time-to-time upon request by Landlord execute and deliver to such persons as Landlord shall request a statement in recordable form, i.e., a Tenant Estoppel Certificate, certifying that this Lease is unmodified and in full force and effect (or if there have been modifications, that the same is in full force and effect as so modified), stating the dates to which rent and other charges payable under this Lease have been paid, stating that Landlord is not in default hereunder (or if Tenant alleges a default stating the nature of such alleged default) and further stating such other matters as Landlord shall reasonably require. Any such statement may be conclusively relied upon by any prospective purchaser or encumbrancer of the Property. Tenant has pre-approved the form of Tenant Estoppel Certificate attached as Exhibit “C” hereto. In addition, Tenant agrees periodically to furnish within ten (10) days after so requested by Landlord, to any prospective purchaser of the Building, the Property, or any interest therein, or to the holder of any deed of

 

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trust, mortgage or security agreement covering the Building, the Property, or any interest of Landlord therein, a certificate signed by Tenant certifying (a) that this Lease is in full force and effect and unmodified (or if there have been modifications, that the same is in full force and effect as modified and stating the modifications), (b) as to the Commencement Date and the date through which Base Rent and Tenant’s Additional Rent have been paid, (c) that Tenant has accepted possession of the Premises and that any improvements required by the terms of this Lease to be made by Landlord have been completed to the satisfaction of Tenant, (d) that except as stated in the certificate no rent has been paid more than thirty (30) days in advance of its due date, (e) that the address for notices to be sent to Tenant is as set forth in this Lease (or has been changed by notice duly given and is as set forth in the certificate), (f) that except as stated in the certificate, Tenant, as of the date of such certificate, has no charge, lien, or claim of offset against rent due or to become due, (g) that except as stated in the certificate, Landlord is not then in default under this Lease, (h) as to the amount of the Approximate Rentable Area of the Premises then occupied by Tenant, (i) that there are no renewal or extension options, purchase options, rights of first refusal or the like in favor of Tenant except as set forth in this Lease, (j) the amount and nature of accounts payable to Landlord under terms of this Lease, and (k) as to such other matters as may be requested by Landlord or the holder of any such deed of trust, mortgage or security agreement. Any such certificate may be relied upon by any prospective purchaser, secured party, mortgagee or any beneficiary under any mortgage, deed of trust on the Building or the Property or any part thereof or interest of Landlord therein. At Landlord’s option, the failure of Tenant to deliver such statements as required by this Section 28 shall constitute a material default of Tenant under this Lease, or it shall by reason of such failure be deemed to be conclusive upon Tenant that (a) this Lease is in full force and effect, without modification, except as may be represented by Landlord, (b) there are no uncured defaults in Landlord’s performance, (c) not more than one month’s Base Rent has been paid in advance, (d) all tenant improvements to be constructed by Landlord, if any, have been satisfactorily completed in accordance with Landlord’s obligations, and (e) Tenant has taken possession of the Premises.

 

29.

Notice. Any notice required or permitted to be given under this Lease or by law shall be deemed to have been given if it is written and delivered in person or mailed by Registered or Certified mail, postage prepaid, or sent by a nationally recognized overnight delivery service to the party who is to receive such notice at the address specified in Section l.O. of this Lease. When so mailed, the notice shall be deemed to have been given two (2) business days after the date it was mailed. When sent by overnight delivery service, the notice shall be deemed to have been given on the next business day after deposit with such overnight delivery service. The address specified in Section l.O. of this Lease may be changed from time to time by giving written notice thereof to the other party.

 

30.	[INTENTIONALLY DELETED]

 

31.

Surrender of Premises. Upon the termination, whether by lapse of time or otherwise, or upon any termination of Tenant’s right to possession without termination of the Lease, Tenant will at once surrender possession and vacate the Premises, together with all Leasehold Improvements (except those Leasehold Improvements Tenant is required to remove pursuant to Section 8 hereof), to Landlord in good condition and repair, ordinary wear and tear excepted; conditions existing because of Tenant’s failure to perform maintenance, repairs or replacements as required of Tenant under this Lease shall not be deemed “reasonable wear and tear.” Tenant shall surrender to Landlord all keys to the Premises and make known to Landlord the combination to all combination locks, which Tenant is permitted to leave on the Premises. Subject to the Landlord’s rights under Section 23 hereof, if Tenant fails to remove any of Tenant’s Property within ten (10) days after the termination of this Lease, or Tenant’s right to possession hereunder, Landlord, at Tenant’s sole cost and expenses, shall be entitled to remove and/or store such Tenant’s Property and Landlord shall, in no event, be responsible for the value, preservation or safekeeping thereof. Tenant shall pay Landlord, upon demand, any and all reasonable expenses caused by such removal and all storage charges against such property so long as the same shall be in possession of Landlord or under the control of Landlord. In addition, if Tenant fails to remove any Tenant’s Property from the Premises or storage, as the case may be, within ten (10) days after written notice from Landlord, Landlord, at its option, may deem all or any part of such Tenant’s Property to have been abandoned by Tenant and title thereof shall immediately pass to Landlord under this Lease as by a bill of sale.

 

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32.

Rights Reserved to Landlord. Landlord reserves the following rights, exercisable without notice, except as provided herein, and without liability to Tenant for damage or injury to property, person or business and without affecting an eviction or disturbance of Tenant’s use or possession or giving rise to any claim for setoff or abatement of rent or affecting any of Tenant’s obligations under this Lease: (1) upon thirty (30) days prior notice to change the name or street address of the Building; (2) to install and maintain signs on the exterior and interior of the Building; (3) to designate and approve window coverings to present a uniform exterior appearance; (4) to make any decorations, alterations, additions, improvements to the Building or Property, or any part thereof (including, with prior notice, the Premises) which Landlord shall desire, or deem necessary for the safety, protection, preservation or improvement of the Building or Property, or as Landlord may be required to do by law; (5) to have access to the Premises at reasonable hours to perform its duties and obligations and to exercise its rights under this Lease; (6) to retain at all times and to use in appropriate instances, pass keys to all locks within and to the Premises; (7) to approve the weight, size, or location of heavy equipment, or articles within the Premises; (8) to close or restrict access to the Building at all times other than Normal Business Hours subject to Tenant’s right to admittance at all times under such regulations as Landlord may prescribe from time to time, or to close (temporarily or permanently) any of the entrances to the Building;; provided Landlord shall have the right to restrict or prohibit access to the Building or the Premises at any time Landlord determines it is necessary to do so to minimize the risk of injuries or death to persons or damage to property (9) to change the arrangement and/or location of entrances of passageways, doors and doorways, corridors, elevators, stairs, toilets and public parts of the Building or Property; (10) to regulate access to telephone, electrical and other utility closets in the Building and to require use of designated contractors for any work involving access to the same; (11) if Tenant has vacated the Premises during the last six (6) months of the Lease Term, to perform additions, alterations and improvements to the Premises in connection with a reletting or anticipated reletting thereof without being responsible or liable for the value or preservation of any then existing improvements to the Premises; (12) to grant to anyone the exclusive right to conduct any business or undertaking in the Building provided Landlord’s exercise of its rights, under this clause (12) of this Section 32, shall not be deemed to prohibit Tenant from the operation of its business in the Premises and shall not constitute a constructive eviction; and (13) Landlord shall have the right to transfer all or any portion of the interest in the Building and to assign this Lease to its transferee. Tenant agrees that in the event of such a transfer Landlord shall automatically be released from all liability under this Lease; and Tenant hereby agrees to look solely to Landlord’s transferee for the performance of Landlord’s obligations hereunder after the date of such transfer.

 

33.	Miscellaneous.

 

A.

Severability If any term or provision of this Lease, or the application thereof to any person or circumstance shall, to any extent, be invalid or unenforceable, the remainder of this Lease, or the application of such term or provision to persons or circumstances other than those as to which it is held invalid or unenforceable, shall not be affected thereby, and each term and provision of this Lease shall be valid and enforced to the fullest extent permitted by law.

 

B.

Recording Tenant agrees not to record this Lease or any short form or memorandum hereof.

 

C.

Governing Law This Lease and the rights and obligations of the parties hereto shall be interpreted, construed, and enforced in accordance with the laws and decisions of the State of Oklahoma.

 

D.

Force Majeure Events of “Force Majeure” shall include strikes, riots, acts of God, shortages of labor or materials, war, governmental laws, regulations or restrictions, or any other cause whatsoever beyond the control of Landlord or Tenant, as the case may be. Whenever a period of time is herein prescribed for the taking of any action by Landlord or Tenant (other than the payment of Rent and all other such sums of money as shall become due hereunder), such party shall not be liable or responsible for, and there shall be excluded from the computation of such period of time hereunder, any delays due to events of Force Majeure.

 

E.

Time Except as expressly otherwise herein provided, with respect to all required acts of Tenant, time is of the essence of this Lease.

 

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F.

Assignment Landlord shall have the right to transfer and assign, in whole or in part, all of its rights and obligations hereunder and in the Building and Property referred to herein, and in such event and upon such transfer Landlord shall be released from any further obligations hereunder, and Tenant agrees to look first to such successor in interest of Landlord for the performance of such obligations.

 

G.

Broker Landlord and Tenant hereby indemnify and hold each other harmless against any loss, claim, expense or liability with respect to any commissions or brokerage fees claimed on account of the execution and/or renewal of this Lease due to any action of the indemnifying party. Landlord and Tenant each warrant to the other that it has not dealt with any broker or agent in connection with the negotiation or execution of this Lease. Tenant and Landlord shall each indemnify the other against all costs, expenses, attorneys’ fees, and other liability for commissions or other compensation claimed by any broker or agent claiming the same by, through or under the indemnifying party.

 

H.

Joint and Several Liability If there is more than one Tenant, or if the Tenant as such is comprised of more than one person or entity, the obligations hereunder imposed upon Tenant shall be joint and several obligations of all such parties. All notices, payments, and agreements given or made by, with or to any one of such persons or entities shall be deemed to have been given or made by, with or to all of them.

 

I.

Authority The individual signing this Lease on behalf of Tenant represents (1) that such individual is duly authorized to execute or attest and deliver this Lease on behalf of Tenant in accordance with the organizational documents of Tenant; (2) that this Lease is binding upon Tenant; (3) that Tenant is duly organized and legally existing in the state of its organization, and is qualified to do business in the state in which the Premises is located.

 

J.

Financial Reporting Tenant acknowledges that the financial capability of Tenant to perform its obligations hereunder is material to Landlord and that Landlord would not enter into this Lease but for its belief, based on its review of Tenant’s financial statements, that Tenant is capable of performing such financial obligations. Tenant hereby represents, warrants and certifies to Landlord that its financial statements previously furnished to Landlord were at the time given true and correct in all material respects and that there have been no material subsequent changes thereto as of the date of this Lease.

 

K.

Survivability Notwithstanding anything to the contrary contained in this Lease, the expiration of the Lease Term, whether by lapse of time or otherwise, shall not relieve Tenant from Tenant’s obligations accruing prior to the expiration of the Lease Term, and such obligations shall survive any such expiration or other termination of the Lease Term.

 

L.

Conditional Offer Landlord has delivered a copy of this Lease to Tenant for Tenant’s review only, and the delivery hereof does not constitute an offer to Tenant or an option. This Lease shall not be effective until an original of this Lease has been executed by both Landlord and Tenant and this Lease has been approved by Landlord’s mortgagee, if required.

 

M.

Interpretation Landlord and Tenant understand, agree and acknowledge that (i) this Lease has been freely negotiated by both parties; and (ii) in any controversy, dispute or contest over the meaning, interpretation, validity, or enforceability of this Lease or any of its terms or conditions, there shall be not inference, presumption, or conclusion drawn whatsoever against either party by virtue of that party having drafted this Lease or any portion thereof.

 

N.

Headings The headings and titles to the paragraphs of this Lease are for convenience only and shall have no effect upon the construction or interpretation of any part hereof.

 

O.

Surrender Receipt by Landlord of Tenant’s keys to the Premises shall not constitute an acceptance of surrender of the Premises.

 

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P.

Waiver of Jury Trial TO THE MAXIMUM EXTENT PERMITTED BY APPLICABLE LAW, LANDLORD AND TENANT EACH WAIVE THEIR RESPECTIVE RIGHTS TO TRIAL BY JURY IN ANY LITIGATION ARISING OUT OF, RESULTING FROM, OR WITH RESPECT TO THIS LEASE.

 

34.	Entire Agreement. This Lease, including the following Exhibits, each of which shall be fully executed, if required, by Landlord, Tenant and/or Guarantor, as applicable, on the same date this Lease is executed and shall be deemed to be an integral and essential part of this Lease, namely:

Exhibit A – Payment of Basic Costs

Exhibit B-1 – Outline and Location of Premises

Exhibit B-2 – Legal Description of the Building

Exhibit C – Pre-Approved Tenant Estoppel Certificate

Exhibit D – One Caliber Park at Quail Springs Building Regulations

Exhibit E – Subordination, Non-Disturbance and Attornment Agreement

Exhibit F – Additional Provisions—Data Room Usage Agreement

constitute the entire agreement between the parties hereto with respect to the subject matter of this Lease and supersedes all prior agreements and understandings between the parties related to the Premises, including all lease proposals, letters of intent and similar documents. Tenant expressly acknowledges and agrees that Landlord has not made and is not making, and Tenant, in executing and delivering this Lease, is not relying upon, any warranties, representations, promises or statements, except to the extent that the same are expressly set forth in this Lease. All understandings and agreements heretofore had between the parties are merged in this Lease, which alone fully and completely expresses the agreement of the parties, neither party relying upon any statement or representation not embodied in this Lease. This Lease may be amended or modified only if done in a writing executed by the Landlord and the Tenant with specific reference made therein to the clause or clauses of the Lease being so amended or modified thereby. Except for the express warranties specifically set forth in this Lease, Landlord and Tenant expressly agree that there are and shall be no implied warranties of merchantability, habitability, suitability, fitness for a particular purpose or of any other kind arising out of this Lease, all of which are hereby waived by Tenant, and that there are no other warranties of any kind or nature which extend beyond those expressly stated in this Lease.

 

35.

LIMITATION OF LIABILITY. EXCEPT TO THE EXTENT SPECIFICALLY ADDRESSED HEREIN, TENANT SHALL NOT HAVE THE RIGHT TO AN ABATEMENT OF RENT OR TO TERMINATE THIS LEASE AS A RESULT OF LANDLORD’S DEFAULT AS TO ANY COVENANT OR AGREEMENT CONTAINED IN THIS LEASE OR AS A RESULT OF THE BREACH OF ANY PROMISE OR INDUCEMENT IN CONNECTION HEREWITH, WHETHER IN THIS LEASE OR ELSEWHERE, AND TENANT HEREBY WAIVES SUCH REMEDIES OF ABATEMENT OF RENT AND TERMINATION EXCEPT AS SPECIFICALLY PROVIDED HEREIN. TENANT HEREBY AGREES THAT TENANT’S REMEDIES FOR DEFAULT BY THE LANDLORD HEREUNDER OR IN ANY WAY ARISING IN CONNECTION WITH THIS LEASE, INCLUDING ANY BREACH OF ANY PROMISE OR INDUCEMENT OR WARRANTY, WHETHER EXPRESS OR IMPLIED, SHALL BE LIMITED TO SUIT SEEKING THE RECOVERY OF DIRECT AND PROXIMATE DAMAGES, PROVIDED THAT TENANT HAS GIVEN THE NOTICES REQUIRED IN THIS LEASE. EXCEPT AS OTHERWISE EXPRESSLY PROVIDED HEREIN, NEITHER TENANT NOR LANDLORD SHALL BE ENTITLED TO SEEK TO RECOVER ANY SPECIAL, CONSEQUENTIAL OR PUNITIVE DAMAGES FROM THE OTHER BY REASON OF THE OTHER PARTY’S BREACH OF THIS LEASE. NOTWITHSTANDING ANYTHING TO THE CONTRARY CONTAINED IN THIS LEASE, THE LIABILITY OF THE LANDLORD AND OF THE BUILDING MANAGER TO TENANT FOR ANY DEFAULT BY LANDLORD UNDER THIS LEASE SHALL BE LIMITED TO THE EQUITY INTEREST OF LANDLORD IN THE BUILDING AND THE PROPERTY AND TENANT AGREES TO LOOK SOLELY TO LANDLORD’S INTEREST IN THE BUILDING AND THE PROPERTY FOR THE RECOVERY OF ANY JUDGMENT AGAINST THE LANDLORD OR THE BUILDING MANAGER, IF THEY ARE THE SAME PERSON, IT BEING INTENDED THAT NEITHER THE LANDLORD NOR THE BUILDING MANAGER, IN SUCH EVENT, SHALL BE PERSONALLY LIABLE FOR ANY JUDGMENT OR DEFICIENCY. TENANT HEREBY

 

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COVENANTS THAT, PRIOR TO THE FILING OF ANY SUIT FOR DIRECT AND PROXIMATE DAMAGES, IT SHALL GIVE LANDLORD, AND ALL MORTGAGEES WHOM TENANT HAS BEEN NOTIFIED HOLD MORTGAGES OR DEED OF TRUST LIENS ON THE PROPERTY, BUILDING OR PREMISES (“LANDLORD MORTGAGEES”), NOTICE AND REASONABLE TIME TO CURE ANY ALLEGED DEFAULT BY LANDLORD OR THE BUILDING MANAGER.

[Signature Page Follows]

 

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IN WITNESS WHEREOF, Landlord and Tenant have executed this Lease in multiple original counterparts as of the day and year first above written, to be effective as of the Effective Date.

 

LANDLORD:		CALIBER INVESTMENT GROUP LLC,
		a Delaware limited liability company
		By:		/s/ Matt Austin
		Name:		Matt Austin
		Title:		Vice President
		Date:		June 8, 2012 to be effective as of
		January 1, 2012

 

TENANT:		WINDSOR PERMIAN LLC, a Delaware limited liability company
		By:		/s/ Tracy Dick
		Name:		Tracy Dick
		Title:		Chief Financial Officer
		Date:		June 8, 2012 to be effective as of
		January 1, 2012

 

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EXHIBIT “A”

PAYMENT OF BASIC COSTS

This Exhibit “A” – Payment of Basic Costs—is attached to and made a part of the Lease executed on June             , 2012, to be effective as of the Effective Date January 1, 2012, between CALIBER INVESTMENT GROUP LLC, a Delaware limited liability company (“Landlord”) and WINDSOR PERMIAN LLC, a Delaware limited liability company (“Tenant”) for space in the Building located at 14301 Caliber Drive, Oklahoma City, Oklahoma, 73134, Suite 300, known as One Caliber Park at Quail Springs.

 

A.

During each calendar year, or portion thereof, falling within the Lease Term, Tenant shall pay to Landlord as Additional Rent hereunder Tenant’s Pro Rata Share of the amount by which (a) Basic Costs (as defined below) for the applicable calendar year exceeds Basic Costs for 2007 (the “Base Year”). In no event shall the amount required to be paid by Tenant with respect to Basic Costs for any calendar year during the Lease Term be less than zero. Prior to January 1 of each calendar year during the Lease Term, or as soon thereafter as practical, Landlord shall make a good faith estimate of Basic Costs for the applicable full or partial calendar year and Tenant’s Pro Rata Share thereof. On or before the first day of each month during such calendar year, Tenant shall pay Landlord, as Additional Rent, a monthly installment equal to one-twelfth of Tenant’s Pro Rata Share of Landlord’s estimate of the amount by which Basic Costs for such calendar year will exceed Basic Costs for the Base Year. Landlord shall have the right from time to time during any such calendar year to revise the estimate of Basic Costs for such year and provide Tenant with a revised statements therefor (provided, however, Landlord agrees that Landlord shall not issue a revised statement more than twice in any calendar year), and thereafter the amount Tenant shall pay each month shall be based upon such revised estimate. If Landlord does not provide Tenant with an estimate of the Basic Costs by January 1 of any calendar year, Tenant shall continue to pay a monthly installment based on the previous year’s estimate until such time as Landlord provides Tenant with an estimate of Basic Costs for the current year. Upon receipt of such current year’s estimate, an adjustment shall be made for any month during the current year with respect to which Tenant paid monthly installments of Additional Rent based on the previous year’s estimate. Tenant shall pay Landlord for any underpayment upon demand. Any overpayment in excess of the equivalent of one (1) month’s Base Rent shall, at Landlord’s option, be refunded to Tenant or credited against the installment(s) of Additional Rent next coming due under the Lease. Any overpayment in an amount equal to or less than the equivalent of one (1) month’s Base Rent shall, at Landlord’s option, be refunded to Tenant or credited against the installment of Additional Rent due for the month immediately following the furnishing of such estimate. Any amount paid by Tenant based on any estimate shall be subject to adjustment pursuant to Paragraph B below, when actual Basic Costs are determined for such calendar year.

 

B.

As soon as is practical following the end of the calendar year during the Lease Term, Landlord shall furnish to Tenant a statement of the actual Additional Rent that Tenant should have paid for the previous calendar year, as calculated by the Landlord after it has reasonably determined the actual Basic Costs incurred by the Landlord in operating, maintaining, repairing, owning and managing the Building (as provided in Paragraph C below) for the immediately preceding calendar year. If for any calendar year during the Lease Term, the estimated Additional Rent collected from the Tenant for the prior year, as a result of Landlord’s estimate of Basic Costs, is in excess of Tenant’s Pro Rata Share of the amount by which Basic Costs for such prior year exceeds Basic Costs for the Base Year, then Landlord shall refund to Tenant any overpayment (or, at Landlord’s option, apply such amount against Additional Rent due or to become due hereunder). Likewise, Tenant shall pay to Landlord, on demand, any underpayment of estimated Additional Rent with respect to the prior year, as a result of Landlord’s estimate of Basic Costs for that year, i.e., any amount by which the estimated Additional Rent paid by Tenant in the preceding calendar year was less than Tenant’s Pro Rata Share of the amount by which actual Basic Costs for such prior year exceeded Basic Costs for the Base Year, as so determined by the Landlord, whether or not the Lease has terminated prior to receipt by Tenant of a statement for such underpayment, it being understood that this clause shall survive the expiration of the

 

A-1

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Lease. Upon Tenant’s prior written request therefor, Landlord shall promptly provide to the Tenant a statement of Landlord’s actual total Basic Costs for the previous calendar year, which provided the basis for Landlord’s determination of the Tenant’s actual Additional Rent for that year.

 

C.

“Basic Costs” shall mean all direct and indirect costs, expenses paid and disbursements of every kind (subject to the limitations set forth below) which Landlord incurs, pays or becomes obligated to pay in each calendar year in connection with operating, maintaining, repairing, owning and managing the Building and the Property including but not limited to, the following:

 

(1)

All labor costs for all persons performing services required or utilized in connection with the operation, repair, replacement and maintenance of and control of access to the Building and the Property, including but not limited to amounts incurred for wages, salaries and other compensation for services, professional training, payroll, social security, unemployment and other similar taxes, workers’ compensation insurance, uniforms, training, disability benefits, pensions, hospitalization, retirement plans, group insurance or any other similar or like expenses or benefits.

 

(2)

All management fees, the cost of equipping and maintaining a management office at the Building, accounting services, legal fees not attributable to leasing and collection activity, and all other administrative costs relating to the Building and the Property.

 

(3)

All Rent and/or purchase costs of materials, supplies, tools and equipment used in the operation, repair, replacement and maintenance and the control of access to the Building and the Property.

 

(4)

All amounts charged to Landlord by contractors and/or suppliers for services, replacement parts, components, materials, equipment and supplies furnished in connection with the operation, repair, maintenance, replacement and control of access to any part of the Building, or the Property generally, including the heating, air conditioning, ventilating, plumbing. electrical, elevator and other systems and equipment of the Building and the garage. At Landlord’s option, major repair items may be amortized over a period of up to five (5) years.

 

(5)

All premiums and deductibles paid by Landlord for fire and extended insurance coverage, earthquake and extended coverage insurance, liability and extended coverage insurance, Rent loss insurance, elevator insurance, boiler insurance and other insurance customarily carried from time to time by landlords of comparable office buildings or required to be carried by Landlord’s mortgagee.

 

(6)

Charges for all utilities, including but not limited to water, electricity, gas and sewer, but excluding those electrical charges for which tenants are individually responsible.

 

(7)

“Taxes”, which, for purposes hereof, shall mean (a) all real estate taxes and assessments on the Property, the Building or the Premises, and taxes and assessments levied in substitution or supplementation in whole or in part of such taxes, (b) all personal property taxes for the Building’s personal property, including license expenses, (c) all taxes imposed on services of Landlord’s agents and employees, (d) all sales, use or other tax, excluding state and/or federal income tax now or hereafter imposed by any governmental authority upon Rent received by Landlord, (e) all other taxes, fees or assessments now or hereafter levied by any governmental authority on the Property, the Building or its contents or on the operation and use thereof (except as relate to specific tenants), and (f) all costs and fees incurred in connection with seeking reductions in or refunds in Taxes including, without limitation, any costs incurred by Landlord to challenge the tax valuation of the Building, but excluding income taxes. Estimates of real estate taxes and assessments for any calendar year during the Lease Term shall be determined based on

 

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Landlord’s good faith estimate of the real estate taxes and assessments. Taxes and assessments hereunder are those accrued with respect to such calendar year, as opposed to the real estate taxes and assessments paid or payable for such calendar year.

 

(8)

All landscape expenses and costs of repairing, resurfacing and striping of the parking areas and garages of the Property, if any.

 

(9)

Cost of all maintenance service agreements, including those for equipment, alarm service, window cleaning, drapery or mini-blind cleaning, janitorial services, metal refinishing, pest control, uniform supply, landscaping and any parking equipment.

 

(10)

Cost of all other repairs, replacements and general maintenance of the Property and Building neither specified above nor directly billed to tenants, including the cost of maintaining all interior Common Areas including lobbies, multi-tenant hallways, restrooms and service areas.

 

(11)

The amortized cost of capital improvements made to the Building or the Property which are (a) primarily for the purpose of reducing operating expense costs or otherwise improving the operating efficiency of the Property or Building; or (b) required to comply with any laws, rules or regulations of any governmental authority or a requirement of Landlord’s insurance carrier. The cost of such capital improvements shall be amortized over a period of five (5) years, or longer (at Landlord’s option), and shall, at Landlord’s option, include interest at a rate that is reasonably equivalent to the interest rate that Landlord would be required to pay to finance the cost of the capital improvement in question as of the date such capital improvement is performed, provided if the payback period for any capital improvement is less than five (5) years, Landlord may amortize the cost of such capital improvement over the payback period.

 

(12)

Any other charge or expense of any nature whatsoever which, in accordance with general industry practice with respect to the operation of a first class office building, would be construed as an operating expense.

 

D.

Basic Costs shall not include repairs and general maintenance paid from proceeds of insurance or by a tenant or other third parties, and alterations attributable solely to individual tenants of the Property. Further, Basic Costs shall not include the cost of capital improvements (except as above set forth), depreciation, interest (except as provided above with respect to the amortization of capital improvements), lease commissions, and principal payments on mortgage and other non-operating debts of Landlord. Capital improvements are more specifically defined as:

 

(1)

Costs incurred in connection with the original construction or renovation of the Property or with any major changes to same, including but not limited to, additions or deletions of corridor extensions, renovations and improvements of the Common Areas beyond the costs caused by normal wear and tear, and upgrades or replacement of major Property systems; and

 

(2)

Costs of correcting defects (including latent defects), including any allowances for same, in the construction of the Property or its related facilities; and

 

(3)

Costs incurred in renovating or otherwise improving, designing, redesigning, decorating or redecorating space for tenants or other occupants of the Property or other space leased or held for lease in the Property.

 

E.	If the Building is not at least ninety-five percent (95%) occupied, in the aggregate, during any calendar year of the Lease Term or if Landlord is not supplying services to at least ninety-five

 

A-3

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percent (95%) of the Approximate Rentable Area of the Building at any time during any calendar year of the Lease Term, actual Basic Costs for purposes hereof shall, at Landlord’s option, be determined as if the Building had been ninety-five percent (95%) occupied and Landlord had been supplying services to ninety-five percent (95%) of the Approximate Rentable Area of the Building during such year. If Tenant pays for its Pro Rata Share of Basic Costs based on increases over a “Base Year” and Basic Costs for any calendar year during the Lease Term are determined as provided in the foregoing sentence, Basic Costs for such Base Year shall also be determined as if the Building had been ninety-five percent (95%) occupied and Landlord had been supplying services to ninety-five percent (95%) of the Approximate Rentable Area of the Building including calculating any necessary extrapolation of Basic Costs that are affected by changes in the occupancy of the Building (including, at Landlord’s option, Taxes) to the cost that would have been incurred if the Building) had been ninety-five percent (95%) occupied and Landlord had been supplying services to ninety-five percent (95%) of the Approximate Rentable Area of the Building.

IN WITNESS WHEREOF, Landlord and Tenant have executed this Exhibit “A” this 8th day of June, 2012 to be effective as of January 1, 2012.

 

LANDLORD:		CALIBER INVESTMENT GROUP LLC,
		a Delaware limited liability company
		By:		/s/ Matt Austin
		Name:		Matt Austin
		Title:		Vice President
		Date:		June 8th, 2012 to be effective as of
		January 1, 2012

 

TENANT:		WINDSOR PERMIAN LLC, a Delaware limited liability company
		By:		/s/ Tracy Dick
		Name:		Tracy Dick
		Title:		Chief Financial Officer
		Date:		June 8th, 2012 to be effective as of
		January 1, 2012

 

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EXHIBIT “B-1”

OUTLINE AND LOCATION OF PREMISES

IN

ONE CALIBER PARK AT QUAIL SPRINGS

This Exhibit “B-1” – Outline and Location of Premises—is attached to and made a part of the Lease dated effective as of January 1, 2012, between CALIBER INVESTMENT GROUP LLC, a Delaware limited liability company (“Landlord”) and WINDSOR PERMIAN LLC, a Delaware limited liability company (“Tenant”) for space known as Suite 300 in the Building located at 14301 Caliber Drive, Oklahoma City, Oklahoma, 73134, known as One Caliber Park at Quail Springs.

 

 

B-1 Page 1

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EXHIBIT “B-2”

ONE CALIBER PARK AT QUAIL SPRINGS

14301 CALIBER DRIVE

LEGAL DESCRIPTION

A part of Lot 5, Block 1 of Quail Springs Office Park, a part of the Southeast Quarter (SE/4), Section 12, Township Thirteen North (T13N), Range Four West (R4W) I.M., Oklahoma City, Oklahoma County, Oklahoma; more particularly described as follows:

Commencing at the Northeast Corner of the Southeast Quarter of Section 12; Thence South 89°36’09” West a distance of 370.00 feet to the Northeast corner of Lot 5, Block 1, Quail Springs Office Park and the Point of Beginning; Thence from the Point of Beginning, South 00°13’06” East a distance of 213.97 feet to a point on the Right-of-Way of Caliber Drive; Thence along a non-tangent curve to the left having a radius 60.00 feet a distance of 99.17 feet, said curve having a chord length of 88.26 feet and a chord bearing South 52°02’20” West; Thence South 89°47’08” West a distance of 370.22 feet; Thence North 00°12’52” West a distance of 266.59 feet; Thence North 89°36’09” East a distance of 440.00 feet to the Point of Beginning. Area containing 2.6295 Acres, more or less.

 

 

B-2 Page 1

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EXHIBIT “C”

PRE-APPROVED

TENANT ESTOPPEL CERTIFICATE

DATE:                     

The undersigned hereby certify as follows:

 

1.

WINDSOR PERMIAN LLC, a Delaware limited liability company, as “Tenant”, and CALIBER INVESTMENT GROUP LLC, an Oklahoma limited liability company, as “Landlord”, entered into a written lease effective as of January 1, 2012, (“Lease”), in which Landlord leased to Tenant and Tenant leased from Landlord, certain “Premises” described in said Lease and located in the City of Oklahoma City, County of Oklahoma, State of Oklahoma.

 

2.	The Lease is in full force and effect and has not been amended, modified, supplemented or assigned by Tenant. The Lease represents the entire agreement between Landlord and Tenant.

 

3.	The Tenant has accepted the Premises and presently occupies them, and is paying rent on a current basis. Tenant has no setoffs, claims, or defenses to the enforcement of the Lease.

 

4.	As of the date of this certificate, Tenant is not in default in the performance of any of its obligations under the Lease, and has not committed any breach of the Lease, and no notice of default has been given to Tenant.

 

5.	As of the date of this certificate, Landlord is not in default in the performance of any of its obligations under the Lease, and has not committed any breach of the Lease, and no notice of default has been given to Landlord.

 

6.

Base Rent (as defined in the Lease) in the amount of $            is payable monthly from Tenant. Base Rent has been paid by Tenant under the Lease up to and including                     . The amount of the Additional Rent currently payable by Tenant is $            per month. No Rent has been paid under the Lease more than thirty (30) days in advance of its due date. The Security Deposit has been deposited with the Landlord.

 

7.	Tenant has no claim against Landlord for any other security deposit, prepaid fee or charge or prepaid rent. Tenant has no renewal rights or other options as to the Premises other than what is stated in the Lease.

 

8.	Tenant is executing and delivering this certificate with the understanding that a lender provided financing which affects the Building and the Property. Tenant acknowledges and agrees that Landlord and Lender shall be entitled to rely on Tenant’s certifications set forth herein.

[THE REMAINDER OF THIS PAGE IS INTENTIONALLY LEFT BLANK]

 

C-1

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IN WITNESS WHEREOF, Landlord and Tenant have executed this Lease as of the day and year first written above.

 

LANDLORD:				CALIBER INVESTMENT GROUP LLC, a Delaware limited liability company
				By:
				Name:		Matt Austin
				Title:		Vice President
				Date:		, 2012
TENANT:				WINDSOR PERMIAN LLC, a Delaware limited liability company
				By:
				Name:		Tracy Dick
				Title:		Chief Financial Officer
				Date:		, 2012

 

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EXHIBIT “D”

ONE CALIBER PARK AT QUAIL SPRINGS

BUILDING REGULATIONS

 

1.	Tenant shall at all times use, maintain and occupy the Premises on a careful, safe, proper and lawful manner, keep the Premises and its appurtenances in a clean and safe condition.

 

2.	Tenant shall at all times keep the Premises in a clean, orderly and sanitary condition, free of insects, rodents, vermin and other pest.

 

3.	Tenant shall not permit undue accumulations of garbage, trash, rubbish and other refuse in the Premises or Building, and place refuse in designated containers outside the Premises.

 

4.	Tenant shall not use, permit or suffer the use of any apparatus or instruments for musical or other sound reproduction or transmission in such manner that the sound emanating therefrom or caused thereby shall be audible beyond the interior of the Premises.

 

5.	Tenant shall, at all times, keep all mechanical apparatus free of vibrations and noise, which may be transmitted beyond the confines of the Premises.

 

6.	Tenant shall not cause or permit objectionable odors to emanate from the Premises.

 

7.	Tenant shall not overload the floors or electrical wiring and not install any additional electrical wiring or plumbing without Landlord’s prior written consent.

 

8.	Tenant shall not conduct, permit or suffer any public or private auction sale to be conducted on or from the Premises.

 

9.

Tenant shall not solicit business in the common areas of the Building or distribute handbills or other advertising materials in the common areas, and if this provision is violated, the Tenant shall pay Landlord the cost of collecting same from the common areas for trash disposal. Except with the prior written consent of Landlord, no tenant shall conduct any retail sales in or from the Premises, or any business other than that specifically provided for in the Lease.

 

10.

Landlord reserves the right to prohibit personal goods and services vendors from access to the Building except upon such reasonable terms and conditions, including but not limited to a provision for insurance coverage, as are related to the safety, care and cleanliness of the Building, the preservation of good order thereon, and the relief of any financial or other burden on Landlord occasioned by the presence of such vendors or the sale by them of personal goods or services to a tenant or its employees. If reasonably necessary for the accomplishment of these purposes, Landlord may exclude a particular vendor entirely or limit the number or vendors who may be present at any one time in the Building. The term “personal goods or services vendors” means persons who periodically enter the Building of which the Premises are a part for the purpose of selling goods or services to a tenant, other than goods or services which are used by a tenant only for the purpose of conducting its business on the Premises. “Personal goods or services” include, but are not limited to, drinking water and other beverages, food, barbering services, and shoe-shining services.

 

11.

The sidewalks, halls, passages, elevators and stairways shall not be obstructed by any tenant or used by it for any purpose other than for ingress to and egress from their respective Premises. The halls, passages, entrances, elevators, stairways, balconies, janitorial closets, and roof are not for the use of the general public, and Landlord shall in all cases retain the right to control and prevent access thereto of all persons whose presence in the judgment of Landlord shall be prejudicial to the safety, character,

 

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reputation and interests of the Building and its tenants, provided that nothing herein contained shall be construed to prevent such access to persons with whom Tenant normally deals only for the purpose of conducting its business on the Premises (such as clients, customers, office suppliers and equipment vendors, and the like) unless such persons are engaged in illegal activities. No tenant and no employees of any tenant shall go upon the roof of the Building without the written consent of Landlord.

 

12.

The sashes, sash doors, windows, glass lights, and any lights or skylights that reflect or admit light into the halls or other places of the Building shall not be covered or obstructed. The toilet rooms, water and wash closets and other water apparatus shall not be used for any purpose other than that for which they were constructed, and no foreign substance of any kind whatsoever shall be thrown therein, and the expense of any breakage, stoppage or damage, resulting from the violation of this rule shall be borne by the tenant who, or whose clerks, agents, employees, or visitors, shall have caused it.

 

13.

No sign, advertisement or notice visible from the exterior of the Premises or Building shall be inscribed, painted or affixed by Tenant on any part of the Building or the Premises without the prior written consent of Landlord. If Landlord shall have given such consent at any time, whether before or after the execution of this Lease, such consent shall in no way operate as a waiver or release of any of the provisions hereof or of this Lease, and shall be deemed to relate only to the particular sign, advertisement or notice so consented to by Landlord and shall not be construed as dispensing with the necessity of obtaining the specific written consent of Landlord with respect to each and every such sign, advertisement or notice, as the case may be, so consented to by Landlord.

 

14.

In order to maintain the outward professional appearance of the Building, all window coverings to be installed at the Premises shall be subject to Landlord’s prior reasonable approval. If Landlord, by a notice in writing to Tenant, shall object to any curtain, blind, shade or screen attached to, or hung in, or used in connection with, any window or door of the Premises, such use of such curtain, blind, shade or screen shall be forthwith discontinued by Tenant. No awnings shall be permitted on any part of the Premises.

 

15.

Tenant shall not do or permit anything to be done in the Premises, or bring or keep anything therein, which shall in any way increase the rate of fire insurance on the Building, or on the property kept therein, or obstruct or interfere with the rights of other tenants or in any way injure or annoy them; or conflict with the regulations of the Fire Department or the fire laws, or with any insurance policy upon the Building, or any part thereof, or with any rules and ordinances established by the Board of Health or other governmental authority.

 

16.

No safes or other objects larger or heavier than the elevators of the Building are limited to carry shall be brought into or installed in the Premises. Landlord shall have the power to prescribe the weight, method of installation and position of such safes or other objects. The moving of safes shall occur only between such hours as may be designated by, and only upon previous notice to the manager of the Building, and the persons employed to move safes in or out of the Building must be acceptable to Landlord. No freight, furniture or bulky matter of any description shall be received into the Building or carried into the elevators except during hours and in a manner approved by Landlord.

 

17.

Landlord shall clean the premises as provided in the Lease, and except with the written consent of Landlord, no person or persons other than those approved by Landlord will be permitted to enter the Building for such purpose, but Tenant shall not cause unnecessary labor by reason of Tenant’s carelessness and indifference in the preservation of good order and cleanliness.

 

18.

No tenant shall sweep or throw or permit to be swept or thrown from the Premises any dirt or other substances into any of the corridors of halls or elevators, or out of the doors or windows or stairways of the Building, and Tenant shall not use, keep or permit to be used or kept any foul or noxious gas or substance in the Premises, or permit or suffer the Premises to be occupied or used in a manner offensive or objectionable to Landlord or other occupants of the Building by reason of noise, odors and/or vibrations, or interference in any way with other tenants or those having business therein, nor shall any animals or birds be kept in or about the Building.

 

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19.	Except for the use of microwave ovens and coffee makers for Tenant’s personal use, no cooking shall be done or permitted by Tenant on the Premises, nor shall the Building be used for lodging.

 

20.	Tenant shall not use or keep in the Building any kerosene, gasoline, or inflammable fluid or any other illuminating material, or use any method of heating other than that supplied by Landlord.

 

21.	If Tenant desires telephone or telegraph connections, Landlord will direct electricians as to where and how the wires are to be introduced. No boring or cutting for wires or other, otherwise shall be made without directions from Landlord.

 

22.

Each Tenant, upon the termination of its tenancy, shall deliver to Landlord all the keys of offices, rooms and toilet rooms, and security access card/keys which shall have been furnished such Tenant or which such tenant shall have had made, and in the event of loss of any keys so furnished, shall pay Landlord therefor.

 

23.

No Tenant shall lay linoleum or other similar floor covering so that the same shall be affixed to the floor of the Premises in any manner except by a paste, or other material which may easily be removed with water, the use of cement or other similar adhesive materials being expressly prohibited. The method of affixing any such linoleum or other similar floor covering to the floor, as well as the method of affixing carpets or rugs to the Premises shall be subject to reasonable approval by Landlord. The expense of repairing any damage resulting from a violation of this rule shall be borne by Tenant by whom, or by those agents, clerks, employees or visitors, the damage shall have been caused.

 

24.

On Saturdays, Sundays and legal holidays, and on other days between the hours of 5:00 p.m. and 9:00 a.m. access to the Building or to the halls, corridors, elevators or stairways in the Building, or to the Premises may be refused unless the person seeking access is known to the building watchman, if any, in charge and has a pass or is properly identified. Landlord shall in no case be liable for damages for the admission to or exclusion from the Building of any person whom Landlord has the right to exclude under Rule 10 above. In case of invasion, mob, riot, public excitement, or other commotion, Landlord reserves the right but shall not be obligated to prevent access to the Building during the continuance of the same by closing the doors or otherwise, for the safety of the tenants and protection of property in the Building.

 

25.

Tenant shall see that the windows and doors of the Premises are closed and securely locked before leaving the Building and Tenant shall exercise extraordinary care and caution that all water faucets or water apparatus are entirely shut off before Tenant or Tenant’s employees leave the Building, and that all electricity, gas or air shall likewise be carefully shut off, so as to prevent waste or damage, and for any default or carelessness Tenant shall make good all injuries sustained by other tenants or occupants of the Building of Landlord.

 

26.	Tenant shall not alter any lock or install a new or additional lock or any bolt on any door of the Premises without prior written consent of Landlord. If Landlord shall give its consent, Tenant shall in each case furnish Landlord with a key for any such lock.

 

27.	Tenant shall not install equipment, such as but not limited to electronic tabulating or computer equipment, requiring electrical or air conditioning service in excess of those to be provided by Landlord under the Lease.

 

28.

Landlord shall have the right to prohibit the use of the name of the Building or Property or any other publicity by Tenant which in Landlord’s opinion tends to impair the reputation of the Building or Property or their desirability for other tenants, and upon written notice from Landlord, Tenant will refrain from or discontinue such publicity.

 

29.	Tenant shall not erect any aerial or antenna on the roof or exterior walls of the Premises, Building, or Property without the prior written consent of Landlord.

 

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30.	Neither Tenant nor any of its employees, agents, contractors, invitees or customers shall smoke in any portion of the Building except for designated smoking areas, if any. No smoking shall be allowed within twenty-five feet of the entrance or exit of the Building.

 

31.

Sidewalks, entrances, passageways, courts, corridors, vestibules, halls, elevators and stairways in and about the Building shall not be obstructed nor shall objects be placed against glass partitions, doors or windows which would be unsightly from the Building’s corridors from the exterior of the Building.

 

32.

Plumbing, fixtures and appliances shall be used for only the purpose for which they were designed and no foreign substance of any kind whatsoever shall be thrown or placed therein. Damage resulting to any such fixtures or appliances from misuse by Tenant or its agents, employees or invitees, shall be paid for by Tenant and Landlord shall not in any case be responsible therefor.

 

33.

Any sign, lettering, picture, notice, advertisement installed within the Premises which is visible from the public corridors within the Building shall be installed in such manner, and be of such character and style, as Landlord shall approve, in writing in its reasonable discretion. No sign, lettering, picture, notice or advertisement shall be placed on any outside window or door or in a position to be visible from outside the Building. No nails, hooks or screws (except for customary artwork or wall hangings) shall be driven or inserted into any part of the Premises or Building except by Building maintenance personnel, nor shall any part of the Building be defaced or damaged by Tenant.

 

34.

Tenant shall refer all contractors, contractors’ representatives and installation technicians for Landlord for Landlord’s supervision, approval and control before the performance of any contractual services. This provision shall apply to all work performed in the Building including, but not limited to installation of telephones, telegraph equipment, electrical devices and attachments, doors, entranceways, and any and all installations of every nature affecting floors, walls, woodwork, window trim, ceilings, equipment and any other physical portion of the Building. Tenant shall not waste electricity, water or air conditioning. All controls shall be adjusted only by Building personnel.

 

35.

Movement in or out of the Building of furniture or office equipment, or dispatch or receipt by Tenant of any merchandise or materials which require the use of elevators, stairways, lobby areas, or loading dock areas, shall be restricted to hours designated by Landlord. Tenant must seek Landlord’s prior approval by providing in writing a detailed listing of such activity. If approved by Landlord, such activity shall be under the supervision of Landlord and performed in the manner stated by Landlord. Landlord may prohibit any article, equipment or any other item from being brought into the Building. Tenant is to assume all risk for damage to articles moved and injury to persons resulting from such activity. If any equipment, property and/or personnel of Landlord or of any other tenant is damaged or injured as a result of or in connection with such activity, Tenant shall be solely liable for any and all damage or loss resulting therefrom.

 

36.	Canvassing, soliciting and peddling in or about the Building or Property are prohibited. Tenant shall cooperate and use its best efforts to prevent the same.

 

37.	Tenant shall not use the Premises in any manner which would overload the standard heating, ventilating or air conditioning systems of the Building.

 

38.	Tenant shall not utilize any equipment or apparatus in such manner as to create any magnetic fields or waves which adversely affect or interfere with the operation of any systems or equipment in the Building or Property.

 

39.

Tenant shall not operate or permit to be operated on the Premises any coin or token operated vending machine or similar device (including, without limitation, telephones, lockers, toilets, scales, amusements devices and machines for sale of beverages, foods, candy, cigarettes or other goods), except for those vending machines or similar devices which are for the sole and exclusive use of Tenant’s employees, and then only if such operation does not violate the lease of any other tenant in the Building.

 

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40.

To the extent permitted by law, Tenant shall not permit picketing or other union activity involving its employees or agents in the Building or on the Property, except in those locations and subject to time and other constraints as to which Landlord may give its prior written consent, which consent may be withheld in Landlord’ sole discretion.

 

41.

Tenant shall comply with all applicable laws, ordinances, governmental orders or regulations and applicable orders or directions from any public office or body having jurisdiction, with respect to the Premises, the Building, the Property and their respective use or occupancy thereof. Tenant shall not make or permit any use of the Premises, the Building or the Property, respectively, which is directly or indirectly forbidden by law, ordinance, governmental regulation or order, or direction of applicable public authority, or which may be dangerous to person or property.

 

42.

Tenant shall not use or occupy the Premises in any manner or for any purpose which would injure the reputation or impair the present or future value of the Premises, the Building or the Property; without limiting the foregoing, Tenant shall not use or permit the Premises or any portion thereof to be used for lodging, sleeping or for any illegal purpose.

 

43.

All deliveries to or from the Premises shall be made only at times, in the areas and through the entrances and exits designated for such purposes by Landlord. Tenant shall not permit the process of receiving deliveries to or from the Premises outside of said areas or in a manner which may interfere with the use by any other tenant of its premises or any common areas, any pedestrian use of such area, or any use which is inconsistent with good business practice.

 

44.	Tenant shall carry out Tenant’s permitted repair, maintenance, alterations, and improvements in the Premises only during times agreed to in advance by Landlord and in a manner which will not interfere with the rights of other tenants in the Building.

 

45.	Landlord may from time to time adopt appropriate systems and procedures for the security or safety of the Building, its occupants, entry and use, or its contents. Tenant, Tenant’s agents, employees, contractors, guests and invitees shall comply with Landlord’s reasonable requirements thereto.

 

46.

Landlord shall have the right to prohibit the use of the name of the Building or any other publicity by Tenant that in Landlord’s opinion may tend to impair the reputation of the Building or its desirability for Landlord or its other tenants. Upon written notice from Landlord, Tenant will refrain from and/or discontinue such publicity immediately.

Landlord reserves the right to make such other Building rules and regulations applicable to all tenants in the Building, as, in its reasonable judgment, may from time to time be needed for the safety, care and cleanliness of the Premises and/or Building, and for the preservation of good order therein. In the case of any express conflict between the Lease and these Regulations, the Lease shall be controlling.

 

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EXHIBIT “E”

SUBORDINATION, NON-DISTURBANCE AND ATTORNMENT AGREEMENT

This Subordination, Non-Disturbance, and Attornment Agreement (this “Agreement”) dated                    , 2012, is made among WINDSOR PERMIAN LLC, a Delaware limited liability company (“Tenant”), under Office Lease Agreement effective as of January 1, 2012, (“Lease”), CALIBER INVESTMENT GROUP LLC, a Delaware limited liability company or its assigns (“Landlord”), and LEGACY BANK (“Mortgagee”).

WHEREAS, Mortgagee is the owner of a promissory note (herein, as it may have been or may be from time to time renewed, extended, amended or supplemented, called the “Note”) executed by Landlord and payable to the order of Mortgagee, bearing interest and payable as therein provided, secured by, among other things, a Mortgage (herein, as it may have been or may be from time to time renewed, extended, amended or supplemented, called the “Mortgage”), recorded in the real property records of Oklahoma County, Oklahoma, covering, among other property, the land (the “Land”) described in Schedule “A” which is attached hereto and incorporated herein by reference, and the improvements (“Improvements”) thereon (such land and Improvements being herein together called the “Property”);

WHEREAS, Tenant is the tenant under the Lease referenced above, including all amendments and supplements thereto, as it may from time to time be renewed, extended, amended, or supplemented, covering a portion of the property (said portion being herein referred to as the “Premises”); and

WHEREAS, the term “Landlord” as used herein means the present landlord under the Lease or, if the landlord’s interest is transferred in any manner, the successor(s) or assign(s) occupying the position of landlord under the Lease at the time in question;

THEREFORE, in consideration of the mutual agreements herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties agree as follows:

1. Subordination. Tenant agrees and covenants that the Lease and the rights of Tenant thereunder, are and shall be subordinate and inferior to (a) the lien of the Mortgage and the rights of Mortgagee thereunder, and all right, title and interest of Mortgagee in the Property, and (b) all other security documents now or hereafter securing payment of any indebtedness of the Landlord (or any prior landlord) to Mortgagee which cover or affect the Property (the “Security Documents”).

2. Non-Disturbance. Mortgagee agrees that so long as the Lease is in full force and effect and Tenant is not in default in the payment of rent, additional rent, or other payments or in the performance of any of the other terms, covenants or conditions of the Lease on Tenant’s part to be performed (beyond the period, if any, specified in the Lease within which Tenant may cure such default),

(a) Tenant’s possession of the Premises under the Lease shall not be disturbed or interfered with by Mortgagee in the exercise of any of its rights under the Mortgage, including any foreclosure or conveyance in lieu of foreclosure; and

(b) Mortgagee will not join Tenant as a party defendant for the purpose of terminating Tenant’s interest and estate under the Lease in any proceeding for foreclosure of the Mortgage.

3. Attornment.

(a) Tenant covenants and agrees that in the event of foreclosure of the Mortgage, whether by power of sale or by court action, or upon a transfer of the Property by conveyance in lieu of foreclosure (the purchaser at foreclosure or the transferee in lieu of foreclosure, including Mortgagee if it is such purchaser or transferee, being herein called “New Owner”), Tenant shall

 

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attorn to the New Owner as Tenant’s new landlord, and agrees that the Lease shall continue in full force and effect as a direct lease between Tenant and New Owner upon all of the terms, covenants, conditions and agreements set forth in the Lease and this Agreement, except for provisions which are impossible for Mortgagee to perform; provided, however, that in no event shall the New Owner be:

 

(i) liable for any act, omission, default, misrepresentation, or breach of warranty, of any previous landlord (including Landlord) or obligations accruing prior to New Owner’s actual ownership of the property;

(ii) subject to any offset, defense, claim or counterclaim which Tenant might be entitled to assert against any previous landlord (including Landlord);

(iii) bound by any payment of rent, additional rent or other payments, made by Tenant to any previous landlord (including Landlord) for more than (1) month in advance;

(iv) bound by any amendment, or modification of the Lease hereafter made, or consent by any previous landlord (including Landlord) under the Lease to any assignment or sublease hereafter granted, without the written consent of Mortgagee; or

(v) liable for any deposit that Tenant may have given to any previous landlord (including Landlord) which has not, as such, been transferred to New Owner.

(b) The provisions of this Agreement regarding attornment by Tenant shall be self-operative and effective without the necessity of execution of any new lease or other document on the part of any party hereto or the respective heirs, legal representatives, successors or assigns of any such party.

4. Estoppel Certificate. Hereafter, Tenant agrees to execute and deliver from time to time, upon the request of Landlord or of any holder(s) of the indebtedness or other obligations secured by the Mortgage, a certificate regarding the status of the Lease, consisting of statements, if true (or if not, specifying why not), (a) that the Lease is in full force and effect, (b) the date through which rentals have been paid, (c) the date of the commencement of the term of the Lease, (d) the nature of any amendments or modifications of the Lease, (e) that no default, or state of facts which with the passage of time or notice (or both) would constitute a default, exists under the Lease, and (f) such other matters as may be reasonably requested.

5. Acknowledgment and Agreement by Tenant. Tenant acknowledges and agrees as follows:

(a) Tenant consents to the assignment of the Lease to Mortgagee as security for a loan. Tenant will not amend, alter, or terminate the Lease, without obtaining Mortgagee’s prior written consent thereto. Tenant shall not prepay any rents or other sums due under the Lease for more than one (1) month in advance of the due date therefor.

(b) From and after the date hereof, in the event of any act or omission by Landlord which would give Tenant the right, either immediately or after the lapse of time, to terminate the Lease or to claim a partial or total eviction, Tenant will not exercise any such right (i) until it has given written notice of such act or omission to the Mortgagee; and (ii) until the same period of time as is given to Landlord under the Lease to cure such act or omission shall have elapsed following such giving of notice to Mortgagee, after the time when Mortgagee shall have become entitled under the Mortgage to remedy the same.

 

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(c) In the event that the Mortgagee notifies Tenant of a default under the Mortgage, Note, or Security Documents and demands that Tenant pay its rent and all other sums due under the Lease directly to Mortgagee, Tenant shall honor such demand and pay the full amount of its rent and all other sums due under the Lease directly to Mortgagee or as otherwise required pursuant to such notice beginning with the payment next due after such notice of default, without inquiry as to whether a default actually exists under the Mortgage, Security Documents or otherwise in connection with the Note, and notwithstanding any contrary instructions of or demands from Landlord.

(d) Mortgagee and any New Owner shall have no obligation nor incur any liability with respect to the erection or completion of the improvements in which the Premises are located or for completion of the Premises or any improvements for Tenant’s use and occupancy, either at the commencement of the term of the Lease or upon any renewal or extension thereof or upon the addition of additional space, pursuant to any expansion rights contained in the Lease.

(e) Mortgagee and any New Owner shall have no obligation nor incur any liability with respect to any warranties of any nature whatsoever, whether pursuant to the Lease or otherwise, including, without limitation, any warranties respecting use, compliance with zoning, Landlord’s title, Landlord’s authority, habitability, fitness for purpose or possession.

(f) Nothing herein contained is intended, nor shall it be construed, to abridge or adversely affect any right or remedy of Landlord under the Lease in the event of any default by Tenant in the payment of rent and/or any other sums due under the Lease or in the performance of any of the other terms, covenants or conditions of the Lease on Tenant’s part to be performed.

6. Acknowledgement and Agreement by Landlord. Landlord, as landlord under the Lease and Mortgagor under the Mortgage, acknowledges and agrees for itself and its successors and assigns, that: (a) this Agreement does not constitute a waiver by Mortgagee of any of its rights under the Mortgage, Note, or Security documents, or in any way release Landlord from its obligations to comply with the terms, provisions, conditions, covenants, agreements and clauses of the Mortgage, Note, and Security Documents; (b) the provisions of the Mortgage, Note, or Security Documents remain in full force and effect and must be complied with by Landlord; and (c) Tenant is hereby authorized to pay its rent and all other sums due under the Lease directly to Mortgagee upon receipt of a notice as set forth in paragraph 5(e) above from Mortgagee. Landlord hereby releases and discharges Tenant of and from any liability to Landlord resulting from Tenant’s payment to Mortgagee in accordance with this Agreement. Landlord represents and warrants to Mortgagee that a true and complete copy of the Lease has been delivered by Landlord to Mortgagee.

7. Lease Status. Landlord and Tenant certify to Mortgagee that neither Landlord nor Tenant has knowledge of any default on the part of the other under the Lease, that the Lease is bona fide and contains all of the agreements of the parties thereto with respect to the letting of the Premises and that all of the agreements and provisions therein contained are in full force and effect.

8. Notices. All notices, requests, consents, demands and other communications required or which any party desires to give hereunder shall be in writing and shall be deemed sufficiently given or furnished if delivered by personal delivery, by telegram, telex, or facsimile, by expedited delivery service with proof of delivery, or by registered or certified United States mail, postage prepaid, at the addresses specified at the end of this Agreement (unless changed by similar notice in writing given by the particular party whose address is to be changed). Any such notice or communication shall be deemed to have been given either at the time of personal delivery or, in the case of delivery service or mail, as of the date of first attempted delivery at the address and in the manner provided herein, or, in the case of telegram, telex or facsimile, upon receipt. Notwithstanding the foregoing, no notice of change of address shall be effective except upon receipt. This Paragraph 8 shall not be construed in any way to affect or impair any waiver of notice or demand provided in this Agreement or in the lease or in any document evidencing, securing or pertaining to the loan evidenced by the Note or to require giving of notice or demand to or upon any person in any situation or for any reason.

 

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4. Miscellaneous.

(a) This Agreement supersedes any inconsistent provision of the Lease.

(b) This Agreement shall inure to the benefit of the parties hereto, their respective successors and permitted assigns, and any New Owner, and its heirs, personal representatives, successors and assigns; provided, however, that in the event of the assignment or transfer of the interest of Mortgagee, all obligations and liabilities of the assigning Mortgagee under this Agreement shall terminate, and thereupon all such obligations and liabilities shall be the responsibility of the party to whom Mortgagee’s interest is assigned or transferred; and provided further that the interest of Tenant under this Agreement may not be assigned or transferred without the prior written consent of Mortgagee.

(c) THIS AGREEMENT AND ITS VALIDITY, ENFORCEMENT AND INTERPRETATION SHALL BE GOVERNED BY THE LAWS OF THE STATE OF OKLAHOMA AND APPLICABLE UNITED STATES FEDERAL LAW.

(d) This Agreement may not be modified orally or in any manner other than by an agreement in writing signed by the parties hereto or their respective successors in interest.

(e) If any provision of the Agreement shall be held to be invalid, illegal, or unenforceable in any respect, such invalidity, illegality or unenforceability shall not apply to or affect any other provision hereof, but his Agreement shall be construed as if such invalidity, illegality, or unenforceability did not exist.

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed as of the date first above written.

 

ADDRESS OF TENANT: WINDSOR PERMIAN LLC 14301 Caliber Drive, Suite 300 Oklahoma City, Oklahoma 73134 Attn: Tracy Dick, Chief Financial Officer				TENANT: WINDSOR PERMIAN LLC a Delaware limited liability company
				By:
				Name:		Tracy Dick
				Title:		Chief Financial Officer
				Date:		, 2012
ADDRESS OF LANDLORD: Caliber Investment Group LLC 14301 Caliber Drive, Suite 300 Oklahoma City, Oklahoma 73134 Attn: Matt Austin, Vice President				LANDLORD: CALIBER INVESTMENT GROUP LLC a Delaware limited liability company
				By:
				Name:		Matt Austin
				Title:		Vice President
ADDRESS OF MORTGAGEE: Legacy Bank 2801 West Memorial Road Oklahoma City, OK 73134 Attn: Jon Dodson, Vice President				MORTGAGEE LEGACY BANK
				By:
				Name:		Jon Dodson
				Title:		Vice President

 

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SCHEDULE “A”

TO

SUBORDINATION, NON-DISTURBANCE AND ATTORNMENT AGREEMENT

LEGAL DESCRIPTION OF REAL PROPERTY

A part of Lot 5, Block 1 of Quail Springs Office Park, a part of the Southeast Quarter (SE/4), Section 12, Township Thirteen North (T13N), Range Four West (R4W) I.M., Oklahoma City, Oklahoma County, Oklahoma; more particularly described as follows:

Commencing at the Northeast Corner of the Southeast Quarter of Section 12; Thence South 89°36’09” West a distance of 370.00 feet to the Northeast corner of Lot 5, Block 1, Quail Springs Office Park and the Point of Beginning; Thence from the Point of Beginning, South 00°13’06” East a distance of 213.97 feet to a point on the Right-of-Way of Caliber Drive; Thence along a non-tangent curve to the left having a radius 60.00 feet a distance of 99.17 feet, said curve having a chord length of 88.26 feet and a chord bearing South 52°02’20” West; Thence South 89°47’08” West a distance of 370.22 feet; Thence North 00°12’52” West a distance of 266.59 feet; Thence North 89°36’09” East a distance of 440.00 feet to the Point of Beginning. Area containing 2.6295 Acres, more or less.

 

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EXHIBIT “F”

ADDITIONAL PROVISIONS—DATA ROOM USAGE AGREEMENT

This Exhibit “F” – Additional Provisions—Data Room Usage Agreement is attached to and made an integral part of the Office Lease Agreement effective as of January 1, 2012, between CALIBER INVESTMENT GROUP LLC, a Delaware limited liability company (“Landlord”) and WINDSOR PERMIAN LLC, a Delaware limited liability company (“Tenant”) for lease of the Premises consisting of Suite 300 in the Building located at 14301 Caliber Drive, Oklahoma City, Oklahoma, 73134, known as One Caliber Park at Quail Springs.

1. Agreement for Usage of Landlord’s Data Room. Landlord operates and maintains a data room facility in the first floor of the Building for use by its tenants in the Building and in Landlord’s adjacent office building known as Two Caliber Park at Quail Springs, 14201 Caliber Drive, Oklahoma City, Oklahoma 73134, for use and storage of their data processing servers. The purpose of this Data Room Usage Agreement, which is being attached as Exhibit “F” to this Lease, is to establish the terms and conditions of Tenant’s usage of the Data Room, as that term is defined below, and the costs to be charged by Landlord to Tenant for its use of the Data Room during the Term of this Lease. Accordingly, Landlord and Tenant are setting forth the terms, conditions and costs of Tenant’s use of the Data Room in the following agreement (“Data Room Agreement”) to be an integral part of the Lease.

2. Definitions. In addition to the definitions contained in the Lease, which shall remain in full force and effect as currently stated, Landlord and Tenant agree that the following terms used in this Data Room Agreement shall have the meanings set forth below and shall include the plural as well as singular.

2.1 Data Room shall mean the room located on the first (1st) floor of the Building and designated by the Landlord as the Data Room. Tenant hereby acknowledges and agrees that the Landlord may, from time-to-time, lease vacant Racks in the Data Room to any other Person or third party for any rental amount, it deems appropriate, in its sole discretion, regardless of whether that Person or third party is an existing tenant of the Building, or is a tenant in Landlord’s adjoining office building known as Two Caliber Park at Quail Springs, 14201 Caliber Drive, Oklahoma City, Oklahoma 73134 (“Two Caliber Park”).

2.2 Rack(s) shall mean each of the segregated areas within the Data Room that are designated by Landlord as a “Rack”. Each particular Rack in the Data Room shall be further designated by Landlord with a Rack Number assigned thereto (i.e., Rack Number 1, Rack Number 2, Rack Number 3, Rack Number 4, etc.).

2.3 Occupied Racks shall mean the total number of specific Racks, excluding the Demarc Rack which is shared by all of the tenants of the Data Room, which are actually being leased to and utilized by any Person in the Data Room for any day during any particular calendar month.

2.4 Tenant Racks shall mean those of the Occupied Racks in the Data Room that are being utilized by the Tenant on the first day of any calendar month during the Lease Term. The number of Racks utilized by Tenant may be added to or reduced by Tenant, as it shall see fit, during the Lease Term, as provided below, with a corresponding adjustment to the Data Room Rent to be paid by Tenant to Landlord as provided below in Section 5 of this Data Room Agreement. Tenant’s obligation to pay the Monthly Data Room Rent pursuant to this Data Room Agreement shall be in addition to and cumulative of any and all other sums due and owing by Tenant to the Landlord pursuant to the Lease (including, without limitation, the Base Rent, the Additional Rent, and any other sums owing by Tenant to Landlord under the terms and conditions of the Lease).

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2.5 Monthly Data Room Rent shall mean, as specifically provided in Section 5, below, the amount of rent to be paid on the first day of each calendar month of the Lease Term, by Tenant for the utilization of the Tenant Racks by Tenant.

3. Lease to Tenant of the Tenant Racks. In consideration of Tenant’s payment to Landlord of the Monthly Data Room Rent in the applicable amount as set forth in Section 5, below, and Tenant’s payment of the Rent to Landlord and the performance of its other obligations under the Lease. Landlord hereby covenants and agrees to lease the Tenant Racks to Tenant, together with its right in common with others to use the Data Room and the Demarc Rack, for the duration of the Lease Term. Tenant hereby covenants and agrees to lease the Tenant Racks from the Landlord and to pay the Monthly Data Room Rent to Landlord, in the applicable amount, pursuant to Section 5, below, and to otherwise comply with the other terms and conditions set forth in this Data Room Agreement during the Lease Term.

4. Term. Subject to the provisions of the Lease pertaining to termination of the Lease in the event of Tenant’s default under the Lease, and to the provisions of Section 8.2 of this Data Room Agreement, below, pertaining to Landlord’s option to terminate Tenant’s rights to utilize the Tenant Racks under this Data Room Agreement, only, and not terminate the Lease, in the event of Tenant’s default under this Data Room Agreement, while not being in breach or default under any other provisions of the Lease, Landlord and Tenant agree that the term of the lease of the Tenant Racks to Tenant being granted by the provisions of this Data Room Agreement shall be coterminous with the Lease Term. Accordingly, Tenant’s lease of the Tenant Racks and access to the Data Room being made pursuant to this Data Room Agreement shall terminate and cease on the same date as the Lease Term terminates, for whatever reason, under the terms of the Lease. It is expressly provided, however, that if Tenant hereafter cease to have any need for or utilization of any of the Tenant Racks that Tenant can, upon thirty (30) days prior written Notice to Landlord to be delivered pursuant to the Notice provisions of the Lease, completely terminate this Data Room Agreement and its tenancy of any and all Tenant Racks. Any such termination by Tenant of its right to lease the Tenant Racks under this Data Room Agreement shall not be deemed to modify, release or terminate in any respect the Lease Term as to the Premises, or to cause any adjustment to the Tenant’s payment of the Base Rent, the Additional Rent, or any other sums owing by Tenant under the Lease, and/or Tenant’s performance of all of Tenant’s other obligations under the Lease.

5. Monthly Data Room Rent Payable From and After May 1, 2012. Landlord and Tenant covenant and agree that Tenant has previously caused to be paid to Landlord all of the Monthly Data Rent that was due and owing for the period January 1, 2012 to April 30, 2012 and that, accordingly, the rental obligations of Tenant under this Data Room Agreement shall only be applicable to the Monthly Data Room Rent that will be due and owing by Tenant to Landlord from and after May 1, 2012 for the remainder of the Lease Term. Commencing on May 1, 2012, and continuing for every calendar month thereafter during the remaining Lease Term, Tenant agrees to pay Landlord, and Landlord agrees to accept, the amount for Monthly Data Room Rent that is equal to the product of the sum of Six Hundred Seventy-Five and No/100ths Dollars ($675.00) multiplied times the number of Tenant Racks being utilized by Tenant as will be determined by the Landlord on May 1, 2012, and thereafter as of the first day of each subsequent calendar month during the Lease Term. Landlord shall issue an invoice to Tenant stating the amount of the Monthly Data Room Rent that is owing by Tenant for the ensuing month, determined in the foregoing manner. Tenant shall have the right to add to or reduce the number of Tenant Racks being utilized by Tenant at any time, and from time-to-time, during the Lease Term, as Tenant shall elect unless Tenant is prevented from adding to the number of Tenant Racks by the provisions of Section 6, below. Tenant shall promptly notify Landlord when it makes any such reduction or increase in the number of Tenant Racks. Landlord shall verify the adjusted number of Tenant Racks being so utilized by Tenant on the first day of the following calendar month during the Lease Term and the amount of Monthly Data Room Rent payable for the ensuing month, and thereafter, shall be determined on the basis of the adjusted number of Tenant Racks as so verified by Landlord. If Tenant discontinues the use of one or more Tenant Racks after the first day of a calendar month, Tenant shall not be entitled to any proration, reduction or adjustment of any kind in the amount of Monthly Data Room Rent Tenant paid Landlord for

 

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that calendar month. If, on the other hand, Tenant increases the number of Tenant Racks it is utilizing during a month by one or more, then Tenant will be required to pay, in addition to the Monthly Data Room Rent owing for the following month, a prorated amount equal to the product of the percentage of the days of the preceding calendar month during which Tenant utilized such additional Tenant Rack(s) multiplied times the sum of Six Hundred Seventy-Five and No/100ths Dollars ($675.00) for each such additional Tenant Rack it began utilizing during such month. The Monthly Data Room Rent payable pursuant to this Section 7 shall be payable by Tenant to Landlord at the same time that it pays its Base Rent and Additional Rent to Landlord as required by the Lease and it shall be in addition to those rent payments.

6. Landlord’s Option to Reduce the Number of Tenant Racks. Upon thirty (30) days’ prior written Notice to the Tenant provided by Landlord pursuant to the Notice provisions of the Lease, Landlord shall have the right and option, in sole and absolute discretion, at any time, and from time-to-time, during the Lease Term, to reduce the number of Tenant Racks being utilized and leased by the Tenant under this Data Room Agreement, except and provided, however, so long as Tenant remains in compliance with its obligations under the Lease and this Data Room Agreement, Landlord shall not have the right and option to reduce the number of Tenant Racks being utilized by Tenant below the number of Tenant Racks which Tenant was utilizing on May 1, 2012, unless the Tenant otherwise consents thereto in writing. After the exercise of Landlord’s option under this Section 8, and as of the effective date of the Tenant’s resultant reduced number of Tenant Rack(s), the Tenant’s Monthly Data Room Rent shall be reduced accordingly to reflect pro tanto that reduction in the number of the Tenant Rack(s). Landlord’s option to reduce the number of Tenant Rack(s), as set forth in this Section 8, shall not be applicable to, or affect in any manner, Tenant’s Leased Premises, its Base Rent, its Additional Rent, any other sums owing by Tenant under the Lease, or its occupancy of the Building, and shall only be applicable to Tenant’s use of the Data Room and the Tenant Racks under this Data Room Agreement. Landlord may exercise its option under this Section 8 as many times as Landlord deems appropriate during the Lease Term in accordance with and subject to the provisions of this Section 8.

7. Exculpation of Landlord’s Liability. Tenant, with regard to its utilization of the Tenant Racks and the Data Room, in addition to and cumulative of the specific protections and limitations on liability accorded to Landlord by the provisions of Sections 16, 17 and 34 of the Lease, hereby expressly acknowledges and agrees that the Landlord shall not be liable to Tenant or Tenant’s affiliates, or any other Person, for any damage or destruction of whatsoever kind or nature that might occur to the Tenant Racks, for any reason whatsoever, including without limitation, Landlord’s negligence, and/or to the information and data contained therein, at any time during the Lease Term. Tenant expressly acknowledges and agrees that it will be its sole responsibility to obtain sufficient insurance to adequately compensate Tenant for any potential damage or destruction of the information or data contained on the Tenant Racks which results from any damage, destruction or casualty of any kind or nature that may occur to the Data Room and, specifically, to the Tenant Racks during the Lease Term. Notwithstanding anything to the contrary in the Lease and this Data Room Agreement, Landlord shall also not be liable to Tenant, its affiliates, or any other Person, for any inconvenience, annoyance or injury, of any kind or nature to the business of Tenant resulting in any way, or to any extent, from any stoppage or interruption in the ability of Landlord to provide services to the Leased Premises, in general, and to the Data Room, in particular, including, without limitation, electrical or HVAC service, unless otherwise expressly provided in the Lease. To the extent Tenant seeks to be protected from any such business interruption or other issues, Tenant agrees that its sole remedy and obligation shall be to obtain, at Tenant’s sole cost and expense, business interruption and other types of insurance coverage in order to protect Tenant against such losses and to make any such claim only on Tenant’s insurance carrier. Additionally, any such stoppage or interruption in Landlord’s said services to the Leased Premises, and to the Data Room, in particular, shall not constitute or be construed in any manner as an eviction of Tenant, or entitle Tenant to any abatement of the payment of its Rent, or the Monthly Data Room Rent, or relieve Tenant in any other manner from performing any obligation contained in the Lease or in this Data Room Agreement, unless otherwise expressly provided in the Lease.

 

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8. Miscellaneous Provisions. Landlord and Tenant agree as follows:

8.1 Authority. The individual signing this Data Room Agreement on behalf of Tenant represents: (i) that such individual is duly authorized to execute or attest and deliver this Data Room Agreement on behalf of Tenant in accordance with the organizational documents of Tenant; (ii) that this Data Room Agreement is binding upon Tenant and its successors and permitted assigns; (iii) that Tenant is duly organized and legally existing in the state of its organization, and is qualified to do business in the State of Oklahoma.

8.2 Tenant’s Default. Landlord and Tenant acknowledge and agree that, as the Data Room Agreement is an integral part of the Lease, any default by Tenant under the provisions of this Data Room Agreement shall be deemed to be a default under the provisions of the Lease, and all of the rights and remedies accorded to Landlord in the event of a default by Tenant under the Lease, as set forth in Sections 22 and 23 of the Lease, shall be fully applicable to a default by Tenant under this Data Room Agreement. In addition to such rights and remedies of the Landlord under the Lease, Landlord shall also have the right and option, in the event of Tenant’s default under this Data Room Agreement and its failure to cure such fault within thirty (30) days after Tenant has been provided written Notice of such default by Landlord hereunder, to only terminate Tenant’s right to use the Data Room and any of the Tenant Racks hereunder and/or to bring appropriate legal action against Tenant in order to obtain full payment of any Monthly Data Room Rent which is owing and unpaid by Tenant to Landlord under the terms of this Data Room Agreement. In the event Landlord elects to pursue the foregoing remedy only as to this Data Room Agreement, the Lease of the Leased Premises by Tenant shall otherwise stay in full force and effect and such actions shall have no effect on Tenant’s obligations to pay all Rent and any other sums owing under the Lease and to otherwise perform all of its obligations under the Lease with regard to the Leased Premises.

8.3 Binding Effect and Interpretation. The provisions of this Data Room Agreement will be binding upon and inure to the benefit of Landlord and Tenant and their respective successors and permitted assigns. Landlord and Tenant understand, agree and acknowledge that (i) this Data Room Agreement has been freely negotiated by both parties; and (ii) in any controversy, dispute or contest over the meaning, interpretation, validity or enforceability of this Data Room Agreement, or any of its terms or conditions, there shall not be any inference, presumption or conclusion drawn whatsoever against either party by virtue of that party having drafted this Data Room Agreement, or any portion thereof.

8.4 Waiver of Jury Trial. TO THE MAXIMUM EXTENT PERMITTED BY LAW, LANDLORD AND TENANT EACH WAIVE THEIR RESPECTIVE RIGHTS TO TRIAL BY JURY AND ANY LITIGATION ARISING OUT OF OR WITH RESPECT TO THIS DATA ROOM AGREEMENT.

8.5 Entire Agreement. This Data Room Agreement is deemed to be an integral part of the Lease and is incorporated therein in all respects. All the terms and conditions of the Lease, except to the extent expressly amended by the provisions of this Data Room Agreement, shall be deemed to remain in full force and effect and fully applicable to the subject matter of this Data Room Agreement. This Data Room Agreement and the Lease, including the Exhibits to the Lease, constitute the entire agreement between the Parties hereto with regard to the subject matter of this Lease and the Data Room Agreement, and supersede all prior agreements and understandings between the Parties relating to the Data Room. Tenant expressly acknowledges and agrees that Landlord has not made and is not making, and Tenant, in executing and delivering this Data Room Agreement, is not relying upon, any warranties, representations, promises or statements of Landlord, whether express or implied, whether of merchantability, or of fitness for a particular purpose, except to the extent expressly stated in the Lease. All understandings and agreements heretofore had between the parties, as to the use of the Data Room, are merged in this Data Room Agreement, which alone shall fully and completely express

 

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the agreement of the parties with regard to the utilization of the Data Room by the Tenant. The terms of this Data Room Agreement can only be amended by a writing executed by both Landlord and Tenant which expressly states that it constitutes an amendment hereof and the specific terms herein that are being so amended thereby.

8.6 Counterparts; Attorney Fees. This Data Room Agreement may be executed in one or more counterparts, each of which shall be deemed an original, and all of which taken together, shall constitute one and the same instrument, binding on all parties who have executed this Data Room Agreement, notwithstanding that all of those parties are not signatory to the original or same counterpart. In the event of any dispute or litigation between Tenant and Landlord to enforce any provision of this Data Room Agreement, or to construe or interpret any right of either party hereunder, the unsuccessful party to any such dispute or litigation shall pay to the successful party therein all costs and expenses of such dispute or litigation, including reasonable attorney fees incurred by the successful party in connection with such dispute or litigation.

IN WITNESS WHEREOF, Landlord and Tenant have executed this Exhibit F – Additional Provisions—Data Room Usage Agreement as of the Effective Date of January 1, 2012.

 

LANDLORD:				CALIBER INVESTMENT GROUP LLC, a Delaware limited liability company
				By:		/s/ Matt Austin
				Name: Matt Austin Title: Vice President
				Date: June 8th, 2012 to be effective as of January 1, 2012
TENANT:				WINDSOR PERMIAN LLC, a Delaware limited liability company
				By:		/s/ Tracy Dick
				Name: Tracy Dick Title: Chief Financial Officer
				Date: June 8th, 2012 to be effective as of January 1, 2012

 

F-5

Exhibit 10.28

ASSIGNMENT AND ASSUMPTION OF OFFICE LEASE AGREEMENT

This ASSIGNMENT AND ASSUMPTION OF OFFICE LEASE AGREEMENT (this “Assignment”) is made effective as of the 1st day of June, 2012 (“Effective Date”), by and between WINDSOR PERMIAN LLC, a Delaware limited liability company (“Assignor”), DIAMONDBACK E&P LLC, a Delaware limited liability company (Assignee”), and CALIBER INVESTMENT GROUP LLC, A Delaware limited liability company (“Landlord”).

R E C I T A L S :

A. Assignor is presently the holder of the tenant’s interest under the provisions of that certain Office Lease Agreement by and between Landlord and Assignor, with effective date of January 1, 2012, pursuant to which Assignor is leasing from Landlord portions of Suite 300 on the third (3rd) floor of the office building located at 14301 Caliber Drive, Oklahoma City, County of Oklahoma, State of Oklahoma, known as One Caliber Park at Quail Springs (the Approximate Rentable Area in the Premises consists of 8,010 square feet) for the Lease Term commencing January 1, 2012, terminating on August 31, 2017, and in consideration of the rent and of the other terms and conditions set forth therein (“Lease”). A true and complete copy of the Lease and all Exhibits thereto is attached to this Assignment as Exhibit “A” hereto and by this reference made an integral part of this Assignment for all purposes. Capitalized terms used in this Assignment and not otherwise specifically defined herein shall have the same meanings ascribed to those terms in the Lease.

B. Assignor is desirous, as of the Effective Date, of assigning all of its right, title and interest in and to the Lease to Assignee provided Landlord consents to this Assignment and Assignee agrees to assume and be fully responsible for all of the obligations of the Assignor, as Tenant under the Lease, from and after the Effective Date. Assignee is willing to accept Assignor’s assignment to it of the Lease and to assume all of the Tenant’s obligations under the Lease from and after the Effective Date for the remainder of the Lease Term.

C. Landlord is willing to enter into this Assignment to grant its prior written consent to Assignor’s assignment of the Lease to Assignee, as provided in Section 13A of the Lease.

D. Accordingly, Assignor, Assignee and Landlord are desirous of executing and entering into this Assignment in order to evidence and accomplish the purposes set forth in the above Recitals as of the Effective Date.

NOW, THEREFORE, for and in consideration of the foregoing Recitals, and the mutual covenants contained herein, and for such other good and valuable consideration, the receipt, adequacy and legal sufficiency of which are hereby expressly acknowledged by each of Assignor, Assignee, and Landlord, and intending to be legally bound hereby, Assignor, Assignee, and Landlord do hereby specifically covenant and agree as follows:

 

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AGREEMENT

1. Recitals.

The above and foregoing Recitals are made an integral part of this Assignment and the parties hereto do hereby expressly acknowledge and agree that this Assignment is intended to effect the purposes of those Recitals.

2. Assignment.

Assignor hereby assigns, conveys, transfers and sets over unto Assignee, all of Assignor’s right, title and interest, as Tenant, in, to and under the Lease, expressly subject to the rights and privileges of the Landlord under the Lease. Assignor represents and warrants to Assignee that Assignor’s right, title and interest in and to the Lease is free of any and all liens, charges, or encumbrances of any kind or nature whatsoever and that Assignor has not previously assigned, transferred or conveyed any part or all of its right, title or interest under the Lease to any other person.

3. Assumption.

Assignee hereby assumes and agrees to pay, perform, fulfill and comply with all covenants and obligations (including, without limitation, all rent covenants) to be paid, performed, fulfilled or complied with by the Tenant under the Lease arising from and after the Effective Date of this Assignment.

4. Liability.

(a) It is specifically agreed between Assignor and Assignee that Assignee shall be responsible to the Landlord under the Lease for the discharge and performance of any and all duties and obligations to be performed and/or discharged by the Tenant under the Lease arising from and after (but not prior to) the Effective Date of this Assignment. By accepting this Assignment and by its execution hereof, Assignee hereby assumes and agrees to save, defend, indemnify and hold harmless Assignor from and against any and all demands, claims, causes of action, actions, losses, liabilities, obligations, costs and expenses (including reasonable attorneys’ fees and court costs) arising or accruing as a result of Assignee’s failure to discharge or perform any and all duties and obligations to be performed and/or discharged by the Tenant under the Lease arising from and after (but not prior to) the Effective Date of this Assignment, including, without limitation, claims of the Landlord, contractors, other business invitees, licensees and tort claimants or indemnity claims, arising from and after (but not prior to) the Effective Date of this Assignment.

(b) It is specifically agreed between Assignor and Assignee that Assignor shall remain fully liable to the Landlord for the performance of all of the terms, covenants and conditions to be performed and/or discharged by the Tenant under the Lease arising prior to (but not from and after) the Effective Date of this Assignment, and Assignor hereby agrees to save, defend, indemnify and hold harmless Assignee from and against any and all demands, claims, causes of action, actions, losses, liabilities, obligations, costs and expenses (including reasonable attorneys’ fees and court costs) arising or accruing as a result of Assignor’s failure to discharge or perform the terms, covenants and conditions to be performed and/or discharged by the Tenant under the Lease arising prior to (but not from and after) the Effective Date hereof, including

 

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without limitation, claims of the Landlord, contractors, other business invitees, licensees, tort claimants, and pursuant to any indemnification obligations arising prior to (but not from and after) the Effective Date of this Assignment.

5. Landlord’s Consent to Assignment and Release of Assignor from the Tenant’s Obligations Under the Lease From and After the Effective Date.

Landlord, by its execution below, hereby expressly consents to the assignment of the Lease by Assignor to Assignee, and the assumption by Assignee of the Tenant’s interest in the Lease, as set forth in Sections 2 and 3 of this Assignment, above. Further, Landlord hereby expressly releases Assignor from any and all covenants and obligations of the Tenant to be paid, performed, fulfilled or complied with by the Tenant under the Lease arising from and after the Effective Date of this Assignment. It is expressly provided, however, that:

(a) Such consent will not release Assignor from any obligations accruing or arising under the Lease prior to the Effective Date of this Assignment;

(b) The consent to this Assignment shall not be deemed to be consent by Landlord to any subsequent assignment, sublease, subcontract, license or other transfer of the Lease or any rights, responsibilities, obligations, interests or benefits thereunder, except as otherwise expressly provided by the terms of Section 13 of the Lease;

(c) This consent by the Landlord shall not be valid or effective unless and until this Assignment has been fully executed by Assignor, Assignee and the Landlord;

(d) This consent of the Landlord shall not be construed to modify, waive or affect any of the terms, conditions, provisions or agreements of the Lease, or any of the rights of the Landlord under Lease, or to enlarge or increase the obligations of the Landlord under the Lease as currently stated; and

(e) Under no circumstances shall Landlord be liable for any brokerage commission(s) or any other charge or expense in connection with this consent or this Assignment whatsoever. By their acceptance of this consent, Assignor and Assignee each hereby jointly and severally agree to indemnify, defend and hold Landlord harmless from and against the same, and against any cost or expense (including, but not limited to reasonable attorneys’ fees and court costs) incurred by Landlord in resisting any claim for any such brokerage commission.

 

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6. Ratification and Confirmation.

Landlord hereby ratifies and confirms all of the terms, covenants and conditions of the Lease and acknowledges that the Lease shall continue to remain in full force and effect in all respects from and after the assignment of the Lease from Assignor to Assignee being effected by this Assignment. Assignor acknowledges and agrees that: (a) to its knowledge, Landlord is not in default of any of its obligations or requirements under the Lease whatsoever, and (b) Assignor has no offset, claim, recoupment, or defense against the payment of rent and other sums due and owing under the Lease and/or the performance of all of its obligations as Tenant under the Lease. Landlord acknowledges and agrees that, to its knowledge, Tenant is not in default of any of its obligations under the Lease prior to the Effective Date of this Assignment.

7. Miscellaneous.

(a) Authority. Each party to this Assignment represents and warrants to the other parties to this Assignment that it is duly authorized to enter into this Assignment and/or to execute the applicable assignment, assumption and/or consent provisions set forth herein and perform its respective obligations hereunder without the consent or approval of any other person or party, and that the person signing this Assignment on its respective behalf is duly authorized to sign on behalf of such party.

(b) Disclaimer. The transfer and assignment set forth herein is made by Assignor without any express or implied representation or warranty of any kind or nature, except as expressly set forth in this Assignment.

(c) No Third Party Beneficiaries. Nothing in this Assignment, express or implied, is intended or shall be construed to confer upon, or give to, any person, corporation or other entity, other than the named parties to this Assignment, any rights, remedies, obligations or liabilities.

(d) Binding Effect and Interpretation. This Assignment shall be binding upon and inure to the benefit of the Assignor, the Assignee and the Landlord, and their respective successors and permitted assigns. Assignor, Assignee, and Landlord understand, agree and acknowledge that (i) this Assignment has been freely negotiated by all of the parties hereto; and (ii) in any controversy, dispute or contest over the meaning, interpretation, validity or enforceability of this Assignment, or any of its terms or conditions, there shall not be any inference, presumption or conclusion drawn whatsoever against any party by virtue of that party having drafted this Assignment, or any portion thereof.

(e) Counterparts. This Assignment may executed in two or more counterparts, each of which shall be deemed an original copy, and all of which together will constitute one and the same instrument.

(f) Entire Agreement. This Assignment represents the entire understanding and agreement between the Assignor, Assignee and the Landlord with respect to the subject matter hereof, and no amendment or modification of this Assignment shall be effective unless it is set forth in a writing specifically stating that it is intended to be an amendment hereof, specifying what provision hereof is being amended thereby, and signed by each of the Assignor, Assignee and the Landlord.

 

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(g) Severability. If any term or provision of this Assignment is invalid, illegal, or incapable of being enforced by virtue of any federal or state law, or public policy, all other terms and provisions of this Assignment shall nevertheless remain in full force and effect so long as the legal substance of the transaction contemplated hereby is not affected in any manner materially adverse to any of the parties to this Assignment. Upon such determination that any such term or provision is invalid, illegal, or incapable of being enforced, the parties hereto shall negotiate in good faith to modify this Assignment so as to effect the original intent of the parties as closely as possible in an acceptable manner in order that the transactions contemplated hereby are consummated as originally contemplated to the greatest extent possible.

[Signature Page Follows]

 

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IN WITNESS WHEREOF, the Assignor, Assignee and Landlord have each caused this Assignment to be duly executed by their respective authorized representatives as of the date first written above.

 

ASSIGNOR:				WINDSOR PERMIAN LLC A Delaware limited liability company
				By:		/s/ Tracy Dick
				Name: Tracy Dick Title: Chief Financial Officer
ASSIGNEE:				DIAMONDBACK E&P LLC
				a Delaware limited liability company
				By:		/s/ Tracy Dick
				Name: Tracy Dick Title: Chief Financial Officer
LANDLORD:				CALIBER INVESTMENT GROUP LLC
				a Delaware limited liability company
				By:		/s/ Matt Austin
				Name: Matt Austin Title: Vice President

 

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ACKNOWLEDGMENTS

 

STATE OF OKLAHOMA		)
		)		:ss
COUNTY OF OKLAHOMA		)

Before me, the undersigned, a Notary Public in and for said County and State on this 8th day of June, 2012, personally appeared Tracy Dick, to me known to be the identical person who executed the name of the maker thereof to the within and foregoing instrument as Chief Financial Officer of Windsor Permian LLC, a Delaware limited liability company, and acknowledged to me that she executed the same as the free and voluntary act and deed of said limited liability company, on behalf of the limited liability company, for the uses and purposes therein set forth.

Given under my hand seal the date and year last above written.

 

(SEAL)						/s/ Kimberly L. Swan
						Notary Public
My Commission expires: 6/18/12						Commission No. 08006302

 

STATE OF OKLAHOMA		)
		)		:ss
COUNTY OF OKLAHOMA		)

Before me, the undersigned, a Notary Public in and for said County and State on this 8th day of June, 2012, personally appeared Tracy Dick, to me known to be the identical person who executed the name of the maker thereof to the within and foregoing instrument as Chief Financial Officer of Diamondback E&P LLC, a Delaware limited liability company, and acknowledged to me that she executed the same as the free and voluntary act and deed of said limited liability company, by and on behalf of the limited liability company, for the uses and purposes therein set forth.

Given under my hand seal the date and year last above written.

 

(SEAL)						/s/ Kimberly L. Swan
						Notary Public
My Commission expires: 6/18/12						Commission No. 08006302

 

STATE OF OKLAHOMA		)
		)		:ss
COUNTY OF OKLAHOMA		)

Before me, the undersigned, a Notary Public in and for said County and State on this 8th day of June, 2012, personally appeared Matt Austin, to me known to be the identical person who executed the name of the maker thereof to the within and foregoing instrument as Vice President of Caliber Investment Group LLC, a Delaware limited liability company, and acknowledged to me that he executed the same as the free and voluntary act and deed of said limited liability company, on behalf of the limited liability company, for the uses and purposes therein set forth.

Given under my hand seal the date and year last above written.

 

(SEAL)						/s/ Kimberly L. Swan
						Notary Public
My Commission expires: 6/18/12						Commission No. 08006302

 

7

Exhibit 10.29

Windsor Permian, LLC

14301 Caliber Drive, Suite 300

Oklahoma City, Oklahoma 73134

As of January 1, 2012

Travis Stice

4906 Rustic Trail

Midland, TX 79707

Dear Mr. Stice:

Windsor Permian, LLC, a Delaware limited liability company (the “Company”), hereby agrees to employ you and you hereby agree to accept such employment under the terms and conditions of this employment agreement, which amends and restates your employment agreement dated as of April 1, 2012:

1. Term of Employment. Except for earlier termination as provided in Section 9 below, your employment with the Company shall be for a term commencing as of April 18, 2011 (the “Effective Date”) and terminating on the third (3^rd) anniversary of the Effective Date. The period of time between the Effective Date and the third (3^rd) anniversary of the Effective Date shall be referred to herein as the “Term.”

2. Compensation.

(a) During the Term, you shall be compensated for all services rendered by you under this agreement at the rate of $300,000 per annum (the “Base Salary”). The Base Salary shall be payable in such manner as is consistent with the Company’s payroll practices for executive employees.

(b) During the Term, you shall be eligible to receive an annual bonus in accordance with the Company’s bonus policy to be established by the Manager of the Company if a limited liability company or Board of Directors of the Company if a corporation (the “Board”) from time to time (the “Annual Bonus”). The Annual Bonus shall be determined by the Board based upon your achievement of performance goals as determined by the Board for each fiscal year of the Company. You shall be eligible to receive a target Annual Bonus of $300,000 upon achievement of your performance goals. You shall receive a minimum Annual Bonus of $200,000 and be eligible to receive an Annual Bonus of up to $400,000 based upon your achievement of stretch goals as determined by the Board. The Annual Bonus shall be paid within fifteen (15) business days after (i) completion and release of the audited financial statements for the applicable fiscal year or (ii) the close and approval by the Board of the Company’s books for the applicable fiscal year if the Board determines that an audit is not required.

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(c) The Company hereby grants to you the option to acquire a one percent (1%) membership interest in the Company for the total amount of $3,600,000.00, (the “Purchase Option”). If the Company sells a portion of its oil and gas properties before you exercise the Purchase Option, the exercise price will be reduced by an amount equal to one percent (1%) of the net proceeds from such sale(s). In order to exercise the Purchase Option, you shall give the Board written notice of your desire to acquire a one percent (1%) membership interest in the Company, which notice shall be given on or before the earlier of (i) the fifth (5^th) anniversary date of the Effective Date; and (ii) the termination of your employment (the “Expiration Date”). If you fail to notify the Board in writing on or before the Expiration Date, then the Purchase Option shall terminate and you shall have no further right to acquire a membership interest in the Company. In the event such Expiration Date is due to provision 2(c)(ii) above and the Company does not complete the initial public offering within 365 days from the date of such initial filing, the Purchase Option shall then again be available to you subject to the terms and conditions hereof. In the event the Purchase Option is exercised by you, the Company and you, within ten (10) days from the day the Purchase Option is exercised, shall enter into a definitive acquisition agreement containing typical terms of a transaction of this type, which shall also provide for a closing within fifteen (15) days from the day the Purchase Option is exercised and a company agreement containing restrictions on transfer, drag-along rights, capital calls, dilution and such other terms as the Company may require. The Purchase Option shall vest in four (4) equal amounts commencing on the anniversary date of the Effective Date following such grant and each of the next following three (3) anniversary dates of the Effective Date. In the event more than fifty percent (50%) of the membership interests or stock in the Company is owned by one or more third parties other than a Wexford Party (defined below), then the Purchase Option shall vest immediately. If you exercise the Purchase Option you will not be eligible for the Stock Option defined below.

(d) It is currently contemplated that the Company will participate in an initial public offering (the “IPO”). The IPO will be accomplished through the sale of common stock of a new Delaware corporation formed for that purpose (“Diamondback”), and an affiliate of the Company, pursuant to a registration statement filed with and declared effective by the United States Securities and Exchange Commission. Prior to the completion of the IPO, all of the membership interests in the Company will be contributed to Diamondback in exchange for common stock of Diamondback (the “Contribution”) and the Company will become a wholly-owned subsidiary of Diamondback. If the Contribution occurs, your Company Option to acquire membership interests of the Company will be canceled and your rights to acquire membership interests in the Company and all your rights under the Company Option will terminate. If you continue to be employed at the time of the Contribution, you will be entitled to receive the following: (i) a cash bonus in the amount of $1,000,000.00 (the “Transaction Bonus”), less applicable tax withholdings, of which two-thirds will be payable at the time of the IPO and one-third will be payable upon the first anniversary of the closing of the IPO if you are still employed by the Company or if you were terminated by the Company prior to that date other than for “Cause” as defined in Section 9(b); (ii) the grant of Restricted Stock Units (the “RSU Award”) in an amount equal to $1,000,000.00 divided by the initial price per share of the common stock to the public in the IPO (the “IPO Price”), rounded up or down to the closest whole number of Restricted Stock Units, upon the terms and subject to the conditions set forth in the Diamondback Energy, Inc. 2012 Equity Incentive Plan (the “Plan”) and the RSU award

 

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agreement granted under the Plan, including the vesting commencement and vesting schedule date applicable to the Company Option (provided that the first settlement date on which vested shares will be transferred to you will not be earlier than the expiration of any lock-up agreements entered into in connection with the IPO); and (iii) the grant of an option to purchase 300,000 shares of Diamondback common stock (the “Diamondback Option”) upon the terms and subject to the conditions set forth in the Plan. The Diamondback Option will be granted effective as of the date of the Contribution, will have an exercise price equal to the fair market value of the Diamondback common stock on the grant date (which will be the IPO Price) and will be exercisable in accordance with the vesting commencement and vesting schedule date applicable to the Company Option. In order to exercise any vested portion of the Diamondback Option, you shall give the Board written notice of your desire to exercise the Diamondback Option on or before the Expiration Date in the manner specified in the Plan and the option agreement. Payment of the Transaction Bonus and delivery of the RSU Award and the Diamondback Option are intended to occur promptly after the closing of the IPO, but in no event later than thirty (30) days after the closing of the IPO.

(e) During the Term, you shall be paid a monthly vehicle allowance in the amount of $900.

3. Duties.

(a) You shall serve as President and Chief Operating Officer of the Company, shall be subject to the general supervision and control of the Board and/or such other officers or individuals as it may designate, and shall provide such services customarily expected of such office and as may be reasonably requested by the Board (or its designee) from time to time. Your principal office shall be located in Midland, Texas.

(b) During the Term, you shall devote your full business time, energies and attention to the business and affairs of the Company, and its subsidiaries (collectively, the “Windsor Group” or the “Windsor Companies” and each of them, individually, a “Windsor Company”), and you shall not be engaged in any other business activities; provided, however, that you shall be permitted to engage in such charitable activities and other limited business activities as both do not interfere with the performance of your duties under this agreement and are approved in writing by the Board.

(c) You shall: (i) provide services hereunder to the best of your skills or ability and in an efficient manner and devote such time and effort to the business and affairs of the Company as necessary or advisable to perform your duties hereunder; (ii) act in a manner which you in good faith believe is in the best interests of the Company; (iii) implement any business plan adopted by the Company and then in effect; (iv) perform your duties hereunder in good faith; (v) keep the Company reasonably informed on all matters that are material to the Company; (vi) be subject to, and comply with, the Company’s and the Windsor Group’s rules, practices and policies applicable to executive employees as reflected in the employee handbook, codes of conduct, compliance policies or otherwise; and (vii) cause the Company to comply with all applicable laws and regulations and monitor the development, maintenance, operation and management of the business of the Company to ensure such development, maintenance, operation and management complies with all applicable laws.

 

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4. Benefits. You shall be entitled to twenty-five (25) paid vacation days per annum. You also shall have the benefit of such life and medical insurance plans and other similar plans as the Windsor Group may have or may establish from time to time for its executive employees generally, subject to satisfaction of applicable eligibility requirements. The foregoing, however, shall not be construed to require any Windsor Company to establish any such plans or to prevent any Windsor Company from modifying or terminating any such plans, and no such action or failure thereof shall affect this agreement.

5. Expenses. The Company shall reimburse you, in accordance with Company policy, for reasonable expenses incurred by you in the ordinary course in connection with the business of the Windsor Group upon the presentation by you of appropriate substantiation for such expenses. All expenses or other reimbursements under this agreement shall be made in accordance with the Company’s policies.

6. Restrictive Covenants.

(a) Subject to Section 6(b) below, from the date hereof until the termination of your employment with, engagement as a consultant of, or other affiliation with, any Windsor Company, and for a period ending on the later of six (6) months thereafter (such period, the “Restricted Period”), you shall not, nor shall any of your affiliates, without the written consent of the Board, at any time or in any manner, either directly or indirectly, become associated with, render services to, invest in, represent, advise or otherwise participate as an officer, employee, director, stockholder, partner, member, agent of or consultant for any business or organization that engages or participates in the Restricted Business; provided, however, that nothing herein shall prevent you from acquiring up to two percent (2%) of the securities of any company listed on a national securities exchange or quoted on the NASDAQ quotation system, provided your involvement with any such company is solely that of a passive stockholder. For purposes of this agreement, “Restricted Business” means the oil and gas exploration and production business in Texas, Oklahoma and New Mexico and each other area, location or field in which the Windsor Companies conduct business, and any other business or operation that is in competition with any business or operations under consideration or in development by any Windsor Company before the termination of your employment with, engagement as a consultant of, or other affiliation with, any Windsor Company or any subsidiary of a Windsor Company.

(b) The parties hereto intend that the covenant contained in this Section 6 shall be deemed a series of separate covenants for each state, county and city in which the Windsor Group’s business is conducted or is preparing to be conducted. If, in any judicial proceeding, a court shall refuse to enforce all of the separate covenants deemed included in this Section 6 because, taken together, they cover too extensive a geographic area, the parties intend that those covenants (taken in order of the states, counties and cities therein which are least populous), which if eliminated would permit the remaining separate covenants to be enforced in such proceeding, shall, for the purpose of such proceeding, be deemed eliminated from the provisions of this Section 6.

 

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7. Confidentiality, Non-Interference, Proprietary Information and Non-Solicitation.

(a) Confidentiality. In the course of your employment by the Windsor Companies, you have had, and/or shall have, access to confidential or proprietary data or information of the Windsor Group, Wexford Capital LP (“Wexford”), any affiliates of the foregoing, the investment funds and managed accounts for which Wexford or its affiliates serves as general partner or acts as investment manager (the “Funds”), entities managed by Wexford or served by the Windsor Group, including without limitation entities in which the Funds have invested, directly or indirectly and their respective businesses (collectively the “Wexford Parties” and each of them individually, a “Wexford Party”). You shall not at any time divulge or communicate to any person (which term, for purposes of this agreement, includes both persons or entities) nor shall you direct any Windsor Group employee to divulge or communicate to any person (other than to a person bound by confidentiality obligations similar to those contained herein and other than as necessary in performing your duties hereunder), or use to the detriment of the Wexford Parties or for the benefit of any other person, any of such data or information. No business conducted by you or any organization of which you, directly or indirectly, are an owner, partner, manager, joint venturer, director, officer, manager or otherwise a participant in or connected with in any locality, state or country in which the Wexford Parties conduct business shall use any name, designation or logo which is substantially similar to that presently used by any Wexford Party. The term “confidential or proprietary data or information” as used in this agreement shall mean information not generally available to the public or generally known within the applicable Wexford Party’s industry, including, without limitation, personnel information, financial information, customer lists or contacts, supplier lists, strategy and plans, information regarding operations, systems, services, know-how, computer and any other processed or collated data, trade secrets (including, without limitation, software), computer programs, pricing, marketing and advertising data.

(b) Non-Interference. You agree that, during the Restricted Period, you shall not, at any time or in any manner, either directly or indirectly, for your own account or for the account of any other person, interfere with any Wexford Party’s relationship with any of its employees, suppliers or regulators.

(c) Proprietary Information and Disclosure. You agree that you shall at all times promptly disclose to the Company, in such form and manner as the Company may require, any inventions, improvements or procedural or methodological innovations, program methods, forms, systems, services, designs, marketing ideas, products or processes (whether or not capable of being trademarked, copyrighted or patented) conceived or developed or created by you during or in connection with your employment hereunder and which relate to the business of any Wexford Party (“Intellectual Property”). You agree that all such Intellectual Property constitutes a work-for-hire and shall be the sole property of the applicable Wexford Party. You further agree that you shall execute such instruments and perform such acts as may be requested by the Company to transfer to and perfect in the entity designated by the Company all legally protectable rights in such Intellectual Property.

 

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(d) Return of Property. All materials, records and documents in any medium made by you or coming into your possession during your employment concerning any products, processes or services, manufactured, used, developed, investigated, provided or considered by any Wexford Party or otherwise concerning the business or affairs of the Wexford Parties, shall be the sole property of the applicable Wexford Party, and upon termination of your employment, or upon request of the Company during your employment, you shall promptly deliver the same to the Wexford Party designated by the Company. In addition, upon termination of your employment, or upon request of the Company during your employment, you shall deliver to the Wexford Party designated by the Company all other property of the Wexford Parties in your possession or under your control, including, but not limited to, financial statements, marketing and sales data, drawings, documents and electronic records.

(e) No Solicitation of Customers. Notwithstanding any other provision of this agreement, you agree that, during the Restricted Period, you shall not at any time or in any manner, on your own behalf, or on behalf of any other individual, sole proprietorship, business, firm, partnership, company, corporation or other entity other than the Company, directly solicit, or ask anyone else to solicit, the sale of goods, services or a combination of goods and services, which are the same or similar to those provided by the Windsor Group, from Established Customers. You further agree that for the same period, you will not in any way interfere or attempt to interfere with the Windsor Group’s relationships with any of their Established Customers. “Established Customers” means a customer that the Windsor Group has actually done business with during the twelve (12) months preceding the date of termination of your employment with, engagement as a consultant of, or other affiliation with, any Windsor Company.

(f) Non Solicitation of Employees. Notwithstanding any other provision of this agreement, you agree that, during the Restricted Period, you shall not at any time or in any manner, either directly or indirectly, either on your behalf or on behalf of any person (other than the Windsor Group), solicit, divert or otherwise encourage or attempt to solicit, divert or otherwise encourage any officer or employees or agents of any Windsor Company to enter into any employment, consulting or advisory arrangement or contract with or to perform any services for or on your behalf or on behalf of any person (other than the Windsor Group), or to enter into any kind of business, including, without limitation, the business of any Windsor Company or any business similar to that of a Windsor Company, or hire any such officer or key employee or agent.

(g) Non-Disparagement. You agree not to make public statements, negative comments or otherwise disparage any Wexford Party or any Wexford Party’s officers, directors, employees, agents, shareholders or other equity holders in any manner likely to be harmful to them or their business, business reputation or personal reputation. The foregoing shall not be violated by truthful statements in response to legal process, required governmental testimony or filings, or administrative or arbitral proceedings (including, without limitation, depositions in connection with such proceedings).

(h) Cooperation. Upon the receipt of reasonable notice from the Company (including outside counsel), you agree that while employed by any Windsor Company and thereafter, you shall provide reasonable assistance to any Wexford Party and their respective representatives in defense of any claims that may be made against any Wexford Party, and shall assist any Wexford Party in the prosecution of any claims that may be made by any Wexford

 

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Party, to the extent that such claims relate to the period of your employment with a Windsor Company. You agree to promptly inform the Company if you become aware of any lawsuits involving such claims that may be filed or threatened against any Wexford Party. You also agree to promptly inform the Company (to the extent legally permitted to do so) if you are asked to assist in any investigation of any Wexford Party (or its actions), regardless of whether a lawsuit or other proceeding has then been filed against any Wexford Party with respect to such investigation. Upon presentation of appropriate documentation, the Company shall pay or reimburse you for all reasonable out-of-pocket expenses incurred by you in complying with this Section 7(h). If at the time of compliance you are no longer an employee, officer or director (or functional equivalent) of any Windsor Company, the Company shall provide a reasonable per diem to you.

8. Interpretation, Enforcement and Construction

(a) Equitable Relief. With respect to the covenants contained in Sections 6 and 7 of this agreement, you agree that any remedy at law for any breach of said covenants may be inadequate and that the Company shall be entitled to specific performance or any other mode of injunctive and/or other equitable relief to enforce its rights hereunder or any other relief a court might award. In the event of a violation by you of Section 6 or Section 7 hereof, any compensation being paid to you pursuant to this agreement or otherwise shall immediately cease, and any Base Salary previously paid to you after termination of your employment shall be immediately repaid to the Company. The amount of any earned Base Salary paid for the period prior to termination of your employment shall be retained by you.

(b) Reformation. The agreements made in Sections 6 and 7 are material inducements for you to enter into this agreement and the Company would not have made this agreement with you without such assurances. You understand and agree that the geographic area applicable to Section 6 is based on the nature of the products and services provided by the Windsor Group and the broad distribution of their customers, and that the limitations set forth therein are reasonable in geographic area and time and necessary for the protection of the Windsor Group and its goodwill. However, if any court shall determine that the time, geographic area or scope of activity of any restriction contained in Section 6 is unenforceable, it is our intention that such limitation set forth herein shall not be terminated but shall be amended to the extent required to render it valid and enforceable. A court hearing any such dispute is empowered and authorized by the parties to reform this agreement to the maximum time, scope or geographic limitations permitted by applicable law

9. Earlier Termination. Your employment shall terminate prior to the expiration of the Term on the following terms and conditions:

(a) Death or Disability. Your employment shall terminate automatically on the date of your death or immediately upon the Company’s sending you a notice of termination for “Disability”, which shall mean your inability to perform your duties hereunder for ninety (90) days (whether or not continuous) during any period of three hundred sixty-five (365) consecutive days by reason of physical or mental disability. Upon termination of your employment for death or Disability pursuant to this Section 9(a), the Company’s sole obligation to you shall be, subject to your compliance with the provisions of Sections 6 and 7 hereof, to pay the amount of any earned but unpaid Base Salary for the period prior to the effective date of such termination and the prorated portion of the minimum Annual Bonus for the period of the applicable fiscal prior to the effective date of such termination.

 

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(b) Resignation; Cause. Your employment shall terminate (x) no less than thirty (30) days after you send the Company written notice of such termination or (y) immediately upon the Company’s sending you written notice terminating your employment hereunder for “Cause,” which shall mean (A) your willful and knowing refusal or failure (other than during periods of illness, physical or mental incapacity) to perform your duties in any material respect under this agreement; (B) your willful misconduct or gross negligence in the performance of your duties; (C) your material breach of this agreement, any other agreement entered into by you related to the Company or its affiliates, or any Company or WINDSOR Group policy (including any applicable code of conduct); (D) your breach of Sections 6 or 7 of this agreement; (E) your conviction of, entry of a guilty plea or a plea of nolo contendere to any criminal act that constitutes a felony or involves, fraud, dishonesty, or moral turpitude; (F) your indictment for any felony involving embezzlement or theft or fraud; (G) your filing of a voluntary petition in bankruptcy or your consent to an involuntary petition in bankruptcy (or your failure to vacate, within ninety (90) days of the entry thereof, any order approving an involuntary petition in bankruptcy) or the entry of an order, judgment or decree by any court of competent jurisdiction, on the application of a creditor, adjudicating you as bankrupt or insolvent or the appointment of a receiver, trustee, or liquidator of all or a substantial part of your assets, and such order, judgment or decree’s continuing unstayed and in effect for any period of ninety (90) days; or (H) your failure to comply with any lawful directive of the Board after five (5) business days written notice to you. Upon termination of your employment pursuant to this Section 9(b), the Company shall have no obligations hereunder. If you terminate your employment pursuant to clause (x) of the preceding sentence, the Company shall be entitled to accelerate the effectiveness of the termination of your employment to whatever time and date as it shall designate in a writing to you in its sole discretion.

(c) Without Cause. Your employment shall terminate immediately upon the Company’s sending you written notice terminating your employment hereunder (without Cause therefor having been given by you) for any reason or for no reason. Upon any such termination, the Company’s sole obligation to you shall be, subject to your compliance with the provisions of Sections 6 and 7 hereof and executing a general release in a form as reasonably requested by the Company, to pay you at a per annum rate equal to your Base Salary in effect at the time of such termination for a period equal to the Term and the prorated portion of the minimum Annual Bonus for the period of the applicable fiscal year prior to the effective date of such termination, which shall be paid as and when such amounts would have been due had your employment continued. Payments provided in this Section 9(c) shall be in lieu of any termination or severance payments or benefits for which you may be eligible under any of the plans, policies or programs of the Company or its affiliates or under the WARN Act or any similar state statute or regulation.

(d) Continuation of Employment. Any continued employment with the Company after the Term is “at-will”, meaning you have the right at any time, and for any reason or not, to terminate your employment with or without notice, and the Company has the same right. You understand and agree the Company shall not be obligated to continue your employment prior to the expiration of the Term. Any continuation of employment after the Term shall be on such terms and conditions as the Company shall then offer.

 

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(e) No Other Obligation. Except as specifically set forth in Section 9(c) above, upon termination of your employment under this agreement, the Company’s obligations hereunder shall cease and neither the Company nor, for the avoidance of doubt, any other Windsor Company, shall have any further obligations to you whatsoever.

10. Representation and Warranty. You represent that you do not have any contractual or other obligations that would conflict with your employment by the Company. In particular, you represent that you are not bound by any agreement, understanding or other obligation with or to any person or entity (including, without limitation, any confidentiality, non-competition or non-solicitation agreement) that prohibits you from accepting or continuing your employment by the Company and fully performing all of your duties for the Company. You also acknowledge that it is the Company’s policy to respect the legal rights of others to protect their confidential information. You therefore represent that you have not taken or retained any confidential information (or other property) belonging to a prior employer and shall not use or disclose any such confidential information in connection with your work for the Company. Any inaccuracy of any of the statements set forth in this Section 10 shall constitute “Cause” for purposes of this agreement, in which event we would be entitled to terminate your employment under Section 9(b) above with the effect set forth therein.

11. Dealings with Related Parties. You shall not engage in any dealings on behalf of any Windsor Company with any party in which you or any person or entity affiliated with you, or members of your or their respective immediate families, has a financial interest, without first disclosing same to the Company in a writing specifically describing the nature of the interest and obtaining the Company’s prior written approval.

12. Entire Agreement; Modification. This agreement constitutes the full and complete understanding of the parties with respect to your employment arrangements with the Company and any of its affiliates and shall, on the Effective Date, supersede all prior agreements and writings between you, on the one hand, and the Company or any other Windsor Company (or any of their respective predecessors), on the other hand, with respect to your employment arrangements with the Company or any of its affiliates (the “Prior Agreements”). You and the Company hereby respectively release each other and the Company’s affiliates, effective as of the Effective Date, from all obligations to the other party under the Prior Agreements. No representations, inducements, promises, agreements or understandings, oral or otherwise, have been made by either party to this agreement, or anyone acting on behalf of either party, which are not set forth herein, and any others are specifically waived. This agreement may not be amended or modified in any manner nor may any of its provisions be waived except by written amendment executed by the parties. A waiver, modification or amendment by a party shall only be effective if (a) it is in writing and signed by the parties, (b) it specifically refers to this agreement and (c) it specifically states that the party, as the case may be, is waiving, modifying or amending its rights hereunder. Any such amendment, modification or waiver shall be effective only in the specific instance and for the specific purpose for which it was given.

 

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13. Severability. The terms and provisions of this agreement shall be deemed severable, and the invalidity or unenforceability of any one or more of the provisions hereof shall not affect the validity or enforceability of any one or more of the other provisions hereof. In the event any term or provision of this agreement which is invalid or unenforceable in any jurisdiction shall, as to such jurisdiction, shall be ineffective to the extent of such invalidity or unenforceability without rendering invalid or unenforceable the remaining terms and provisions of this agreement or affecting the validity or enforceability of any of the terms or provisions of this agreement in any other jurisdiction and the parties agree the conflicting term or provision shall be modified to conform.

14. Notices. All notices and other communications given or made pursuant to this agreement shall be in writing and shall be deemed effectively given upon the earlier of actual receipt or: (a) personal delivery to the party to be notified, (b) when sent, if sent by electronic mail or facsimile during normal business hours of the recipient, and if not sent during normal business hours, then on the recipient’s next business day, (c) five (5) days after having been sent by registered or certified mail, return receipt requested, postage prepaid, or (d) one (1) business day after deposit with a nationally recognized overnight courier, freight prepaid, specifying next business day delivery, with written verification of receipt, if to you, to your residence as listed in the Company’s records, and if to the Company, c/o Wexford Capital LP, 411 West Putnam Avenue, Greenwich, Connecticut 06830, attention of General Counsel, with a copy to Windsor Energy, Inc., 14301 Caliber Drive, Suite 300, Oklahoma City, Oklahoma 73134, attention of General Counsel.

15. Assignability; Binding Effect. This agreement shall not be assignable by you without the written consent of the Board. This agreement shall be binding upon and inure to the benefit of you, your legal representatives, heirs and distributees, and shall be binding upon and inure to the benefit of the Company, its affiliates and their respective successors and assigns, including, without limitation, any successor or assign by merger or operation of law.

16. Governing Law; Venue; Waiver of Trial by Jury.

(a) This agreement and the rights of the parties hereunder shall be governed by, interpreted, and enforced in accordance with the internal laws of the State of Texas without giving effect to any choice of law or conflicts of law rules or provisions thereof.

(b) Each party irrevocably agrees that any action or proceeding involving any dispute or matter arising under this agreement may only be brought in the federal courts of the State of Texas, or if such court does not have jurisdiction or shall not accept jurisdiction, in any court of general jurisdiction in the State of Texas. All parties hereby irrevocably consent to the exclusive jurisdiction by any such court with respect to any such proceeding and hereby irrevocably waives, and agrees not to assert, by way of motion, as a defense, counterclaim or otherwise (i) any claim that it is not personally subject to the jurisdiction of the above-named courts for any reason other than by failure to lawfully serve process, (ii) that it or its property is exempt or immune from the jurisdiction of any such court or from any legal process commenced in such courts, and (iii) to the fullest extent permitted by applicable law, that (x) the action or proceeding is brought in an inconvenient forum, (y) the venue of such action or proceeding is improper and (z) this agreement or the subject matter thereof may not be enforced in or by such courts.

 

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(c) To the extent not prohibited by applicable law, each party to this agreement hereby waives, and covenants that it shall not assert (whether as plaintiff, defendant or otherwise), its respective right to a jury trial of any permitted claim or cause of action arising out of this agreement, any of the transactions contemplated hereby, or any dealings between any of the parties hereto relating to the subject matter of this agreement or any of the transactions contemplated hereby. The scope of this waiver and covenant is intended to be all encompassing of any and all disputes that may be filed in any court and that relate to the subject matter of this agreement or any of the transactions contemplated hereby, including, contract claims, tort claims and all other common law and statutory claims. This waiver and covenant is irrevocable and shall apply to any subsequent amendments, supplements or other modifications to this agreement.

17. Prevailing Party Expenses. In the event that litigation or other legal action is instituted between you and the Company or any of its affiliates to enforce the rights under this agreement, the successful party in such litigation or other legal action shall be entitled to reimbursement from the unsuccessful party in such litigation or other legal action of all reasonable fees, costs and expenses (including court costs and reasonable attorneys’ fees) incurred by such successful party in connection with such litigation or other legal action.

18. Third Party Beneficiaries. Wexford and its successors and assigns, as an express third party beneficiary of this agreement, shall be entitled, in its sole and absolute discretion, to enforce any of the provisions hereof from time to time, including, but not limited to, enforcing the restrictions set forth in Sections 6 and 7 of this agreement.

19. Titles and Subtitles. The titles and subtitles used in this agreement are used for convenience only and are not to be considered in construing or interpreting this agreement.

20. Counterparts; Facsimile. This agreement may be executed and delivered by facsimile signature and in two or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same instrument.

21. Review of this Agreement. You acknowledge that you have (a) carefully read this agreement, (b) consulted with independent counsel with respect to this agreement and (c) entered into this agreement of your own free will.

22. Tax Matters; Code Section 409A Compliance.

(a) Deferred Compensation Exceptions. Payments under this Agreement will be administered and interpreted to maximize the short-term deferral exception to and the involuntary separation pay exception under Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”), and the regulations thereunder (collectively “Section 409A”). The portion of any payment under this Agreement that is paid within the short-term deferral period (within the meaning of Code Section 409A and Treas. Regs. §1.409A-1(b)(4)) or that is paid within the involuntary separation pay safe harbor (as described in Code Section 409A and Treas. Regs. §1.409A-1(b)(9)(iii)) will not be treated as nonqualified deferred compensation and will not be aggregated with other nonqualified deferred compensation plans or payments.

 

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(b) Separate Payments and Payment Timing. Any payment or installment made under this Agreement and any amount that is paid as a short-term deferral, within the meaning of Treas. Regs. §1.409A-1(b)(4), will be treated as separate payments. Employee will not, directly or indirectly, designate the taxable year of a payment made under this Agreement. Payment dates provided for in this Agreement will be deemed to incorporate grace periods that are treated as made upon a designated payment date within the meaning of Code Section 409A and Treas. Regs. §1.409A-3(d).

(c) General 409A Provisions. If for any reason, the short-term deferral or involuntary separation pay plan exception is inapplicable, payments and benefits payable to Employee under this Agreement are intended to comply with the requirements of Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”). To the extent the payments and benefits under this Agreement are subject to Section 409A of the Code, this Agreement will be interpreted, construed and administered in a manner that satisfies the requirements of Sections 409A(a)(2), (3) and (4) of the Code and the Treasury Regulations thereunder (and any applicable transition relief under Section 409A of the Code). The Company does not guaranty or warrant the tax consequences of this Agreement and, except as specifically provided to the contrary in this Agreement, Employee will, in all cases, be liable for any taxes due as a result of this Agreement. Neither the Company nor any of its affiliates shall have any obligation to indemnify or otherwise hold you harmless from any or all such taxes, interest or penalties, or liability for any damages related thereto. Employee acknowledges that he has been advised to obtain independent legal, tax or other counsel in connection with Section 409A.

(i) If Employee or the Company determines that any payments or benefits payable under this Agreement intended to comply with Sections 409A(a)(2), (3) and (4) of the Code do not comply with Section 409A of the Code, Employee and the Company agree to amend this Agreement, or take such other actions as Employee and the Company deem reasonably necessary or appropriate, to comply with the requirements of Section 409A of the Code, the Treasury Regulations thereunder (and any applicable relief provisions) while preserving the economic agreement of the parties. If any provision of the Agreement would cause such payments or benefits to fail to so comply, such provision will not be effective and will be null and void with respect to such payments or benefits, and such provision will otherwise remain in full force and effect.

(ii) All payments considered nonqualified deferred compensation under Section 409A and the regulations thereunder will be made on the date(s) provided herein and no request to accelerate or defer any payment under this Section will be considered or approved for any reason whatsoever, except as permitted under Section 409A. The Base Salary continuation payments will commence on the first payroll date that is on or after the eighth day following receipt by the Company of Employee’s executed release; provided, however, if the Base Salary continuation payments are deferred compensation subject to Code Section 409A and if the period during which Employee has discretion to execute or revoke the release straddles two taxable years of Employee, then the Company will commence the Base Salary continuation payments in

 

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the second of such taxable years. Notwithstanding the foregoing, subject to the release requirement, the Base Salary continuation payments will in all events be paid no later than 60 days following Executive’s termination of employment, regardless of which taxable year Executive actually delivers the executed Release to the Company. Once such Base Salary continuation payments commence, the first installment thereof will include all amounts that would have been paid had such payments commenced on the first payroll date occurring on or after the termination of employment date. Executive may not, directly or indirectly, designate the calendar year of the commencement of any payment hereunder. Notwithstanding the foregoing, amounts payable hereunder which are not nonqualified deferred compensation, or which may be accelerated pursuant to Section 409A, such as distributions for applicable tax payments, may be accelerated, but not deferred, at the sole discretion of Company.

(iii) All references in this Agreement to termination of employment or termination mean Employee’s “separation from service” as that term is defined in Section 1.409A-1(h) of the Treasury Regulations.

(iv) All reimbursements and in-kind benefits provided under this agreement that constitute deferred compensation within the meaning of Section 409A of the Code shall be made or provided in accordance with the requirements of Section 409A of the Code, including that (i) in no event shall reimbursements by the Company under this agreement be made later than the end of the calendar year next following the calendar year in which the applicable fees and expenses were incurred, provided that you shall have submitted an invoice for such fees and expenses at least 10 days before the end of the calendar year next following the calendar year in which such fees and expenses were incurred; (ii) the amount of in-kind benefits that the Company is obligated to pay or provide in any given calendar year (other than medical reimbursements described in Treas. Reg. § 1.409A-3(i)(1)(iv)(B)) shall not affect the in-kind benefits that the Company is obligated to pay or provide in any other calendar year; (iii) your right to have the Company pay or provide such reimbursements and in-kind benefits may not be liquidated or exchanged for any other benefit; and (iv) in no event shall the Company’s obligations to make such reimbursements or to provide such in-kind benefits apply later than your remaining lifetime or, if longer, through the 20th anniversary of the Effective Date.

(d) Specified Employee Status. If Employee is a specified employee (within the meaning of Code Section 409A) on the date of his separation from service, any payments made with respect to such separation from service under this Agreement, and other payments or benefits under this Agreement that are subject to Section 409A of the Code, will be delayed in order to comply with Section 409A(a)(2)(B)(i) of the Code, and such payments or benefits will be paid or distributed to you during the five-day period commencing on the earlier of: (i) the expiration of the six-month period measured from the date of your separation from service, or (ii) the date of your death. Upon the expiration of the applicable six-month period under Section 409A(a)(2)(B)(i) of the Code, all payments deferred pursuant to this Section (e) will be paid to Employee (or Employee’s estate, in the event of Employee’s death) in a lump sum payment. Any remaining payments and benefits due under the Agreement will be paid as otherwise provided in the Agreement.

 

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(e) Withholding Taxes. To the extent any payments under this Agreement are wages subject to income and employment tax withholding, the Company has the right to withhold or otherwise require Executive to pay to the Company the amount of any taxes that the Company may be required to withhold before delivery of such payment to Executive.

23. Background Verification. You hereby authorize the Company to conduct one or more Background Verifications prior to and during your actual employment. “Background Verification” includes, without limitation, information regarding your employment and other experience, educational background and any criminal, credit or regulatory history. You further authorize, without reservation, any law enforcement agency, administrator, court, governmental body, federal or provincial agency, institution, school or university (public or private), information service bureau, employer or insurance company contacted by the Company or any agent of the Company to furnish the information set forth in the preceding sentence as part of the employment application process. You hereby consent to and understand that the Company will only use the information collected for the purposes of (if and as applicable) establishing or continuing your employment, including without limitation, evaluating your employment application, determining employment eligibility under the Company’s employment policies, assessing property and business risks to the Company, and otherwise as may be permitted or required by law. You authorize and consent to the release of records obtained through such checks to the authorized representatives of the Company or its agents, and to the Company’s affiliates, for the purposes described above. You acknowledge and agree that any information relating to a Background Verification may be shared with any Wexford Party and stored on the respective servers.

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If this letter correctly sets forth our understanding, please sign the enclosed copy in the space provided below and return it to the Company, whereupon this shall constitute the employment agreement between you and the Company effective and for the term as stated herein.

 

						Windsor Permian, LLC
Date:     July 3, 2012						By:		/s/ Steven E. West
								Steve E. West Vice President
Date:     July 3, 2012						/s/ Travis Stice
						Travis Stice

Exhibit 10.30

WINDSOR PERMIAN, LLC

TERESA DICK EMPLOYMENT AGREEMENT

This Amended and Restated Employment Agreement (this “Agreement”) is entered into as of January 1, 2012 by and between Windsor Permian, LLC, a Delaware limited liability company (the “Company”), and Teresa Dick (“you” or “Employee”).

1. Term of Employment. Except for earlier termination as provided in Section 9 below, your employment under this Agreement shall be for a term (the “Term”) commencing as of September 1, 2011 (the “Effective Date”) and terminating on the first anniversary of the Effective Date.

2. Compensation.

(a) During the Term, you shall be compensated for all services rendered by you under this Agreement at the rate of $250,000.00 per annum (the “Base Salary”). The Base Salary shall be payable in such manner as is consistent with the Company’s payroll practices for executive employees and subject to the usual, required withholding.

(b) During the Term, you shall be eligible to receive an annual bonus in accordance with the Company’s bonus policy as established by the Manager of the Company (as such term is defined in its limited liability company agreement) or Board of Directors of the Company, if constituted (the “Board”) from time to time (the “Annual Bonus”). The Annual Bonus shall be determined by the Board based upon your achievement of performance goals as determined by the Board for each fiscal year of the Company. You shall be eligible to receive a target Annual Bonus of 50% of your Base Salary subject to your achievement of such performance goals. The Annual Bonus shall be paid within fifteen (15) business days after (i) completion and release of the audited financial statements for the applicable fiscal year or (ii) if the Board determines that an audit is not required, the close and approval by the Board of the Company’s books for the applicable fiscal year; provided, however, you must still be employed by the Company on the payment date to receive the Annual Bonus. The Company shall have the right to condition the payment of any Bonus amounts on your execution of a document reasonably acceptable to the Company pursuant to which you confirm, ratify and agree that this Agreement and all of its provisions are valid and binding and are enforceable against you in accordance with their terms.

(c) On the Effective Date, you were granted an option to acquire a one quarter of one percent (0.25%) membership interest in the Company for an exercise price of $900,000.00 (or a pro rata portion thereof, for any partial exercise of such option) (the “Company Option”), subject to vesting and the other conditions set forth in this Section 2. If the Company sells all or a material portion of its oil and gas properties owned by the Company as of the Effective Date (the “Assets”) before you exercise the Company Option, the exercise price will be reduced by an amount equal to one quarter of one percent (0.25%) of the net cash proceeds from such sale(s) but only to the extent that such net proceeds have actually been distributed to the holders of the Company’s membership interests prior to the Contribution (as defined in Section 2(d) below) or to the stockholders of Diamondback (as defined below) after the Contribution (as defined below) (the “Reduction Amount”). However, in no event will the Reduction Amount exceed an

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amount that will cause the exercise price to be less than the fair market value of the membership interests subject to the Company Option on the date the Reduction Amount becomes applicable. In order to exercise any vested portion of the Company Option, you will give the Board written notice of your desire to exercise same on or before the earlier of (i) the fifth (5^th) anniversary date of the Effective Date and (ii) the termination of your employment with the Company for any reason or no reason other than your death, Disability or No Cause Termination (each as defined below) (the “Expiration Date”); provided, however, that your right to exercise the Company Option shall be suspended commencing on the date a registration statement relating to an IPO (as defined below) is filed with the Securities and Exchange Commission and such suspension shall continue until the earliest of: (x) December 31, 2013, (y) the date the registration statement is withdrawn and (z) the date a definitive agreement for the sale of the Company or all or substantially all of its assets is entered into (the “Exercise Suspension Period”). In the event your employment with the Company terminates on account of your death, Disability or No Cause Termination, the Expiration Date will be the earlier of the fifth (5^th) anniversary date of the Effective Date or the 90^th day following your death, Disability or No Cause Termination; provided, however, if the period of time between your death, Disability or No Cause Termination and the Expiration date at all times is subject to Exercise Suspension Period, the Expiration Date will be the earlier of the fifth (5^th) anniversary date of the Effective Date or the 30^th day following the end of the Exercise Suspension Period. If you fail to notify the Board in writing on or before the Expiration Date of your desire to exercise the Company Option, then the Company Option shall terminate and you shall have no further right to acquire membership interests in the Company under this Section 2(c). The Company Option shall vest in four (4) equal amounts on the first four anniversary dates of the Effective Date, subject to your continued employment on each such date; provided that if your employment terminates for any reason other than your death, Disability or No Cause Termination, the Company Option shall cease vesting as of the date of such termination, and any unvested portion of the Company Option shall immediately be forfeited and become void. In the event you exercise the Company Option, then within ten (10) days of such exercise you shall enter into a definitive acquisition agreement with the Company containing typical terms of a transaction of this type, which shall also provide for a closing within fifteen (15) days of such exercise, and an agreement containing, for example, restrictions on transfer, drag-along rights, capital calls, dilution and such other terms as the Company may require in its discretion. In the event that either (i) more than fifty percent (50%) of the combined voting power of the Company’s then outstanding securities is controlled by one or more parties that are not either a Wexford Party (defined below), any employee benefit plan sponsored or maintained by a Wexford Party, any employee or group of persons including an employee of a Wexford Party or an underwriter temporarily holding securities pursuant to an offering of securities and there is either (a) a material diminution in your position, duties, or authority or (b) your required relocation by the Company to a location that is outside a 50-mile radius of Midland, Texas (an “Option Event”) or (ii) your death, Disability or No Cause Termination, then the Company Option shall vest immediately. Notwithstanding anything to the contrary herein, if you exercise all or part of the Company Option under this Section 2(c), you will not be eligible to receive a Diamondback Option (as defined below) in substitution of such exercised Company Option or portion thereof.

(d) It is currently contemplated that the Company will participate in an initial public offering (the “IPO”). The IPO will be accomplished through the sale of common stock of a new Delaware corporation formed for that purpose (“Diamondback”), and an affiliate of the

 

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Company, pursuant to a registration statement filed with and declared effective by the United States Securities and Exchange Commission. Prior to the completion of the IPO, all of the membership interests in the Company will be contributed to Diamondback in exchange for common stock of Diamondback (the “Contribution”) and the Company will become a wholly-owned subsidiary of Diamondback. If the Contribution occurs, your Company Option to acquire membership interests of the Company will be canceled and your rights to acquire membership interests in the Company and all your rights under the Company Option will terminate. If you continue to be employed at the time of the Contribution, you will be entitled to receive the following: (i) a cash bonus in the amount of $300,000.00 (the “Transaction Bonus”), less applicable tax withholdings; (ii) the grant of Restricted Stock Units (the “RSU Award”) in an amount equal to $300,000.00 divided by the initial price per share of the common stock to the public in the IPO (the “IPO Price”), rounded up or down to the closest whole number of Restricted Stock Units, upon the terms and subject to the conditions set forth in the Diamondback Energy, Inc. 2012 Equity Incentive Plan (the “Plan”) and the RSU award agreement granted under the Plan, including the vesting commencement date and the vesting schedule, including the Option Event and other vesting events, applicable to the Company Option (provided that the first settlement date on which vested shares will be transferred to you will not be earlier than the expiration of any lock-up agreements entered into in connection with the IPO); and (iii) the grant of an option to purchase 50,000 shares of Diamondback common stock (the “Diamondback Option”) upon the terms and subject to the conditions set forth in the Plan. The Diamondback Option will be granted effective as of the date of the Contribution, will have an exercise price equal to the fair market value of the Diamondback common stock on the grant date (which will be the IPO Price) and will be exercisable in accordance with the vesting commencement date and the vesting schedule, including the Option Event and other vesting events, applicable to the Company Option. In order to exercise any vested portion of the Diamondback Option, you shall give the Board written notice of your desire to exercise the Diamondback Option on or before the Expiration Date in the manner specified in the Plan and the option agreement. Payment of the Transaction Bonus and delivery of the RSU Award and the Diamondback Option are intended to occur promptly after the closing of the IPO, but in no event later than thirty (30) days after the closing of the IPO.

3. Duties.

(a) You shall serve as Vice President – CFO of the Company, shall be subject to the general supervision and control of the Board and/or such other officers or individuals as it may designate, and shall provide such services customarily expected of such office and as may be reasonably requested by the Board (or its designee) from time to time. Your principal office shall be located in Oklahoma City, Oklahoma.

(b) During the Term, you shall devote your full business time, energies and attention to the business and affairs of the Company, and its subsidiaries (collectively, the “Windsor Group” or the “Windsor Companies” and each of them, individually, a “Windsor Company”), and you shall not engage in any other business activities; provided, however, that you shall be permitted to engage in such charitable and other activities as do not interfere with the performance of your duties under this Agreement and are approved in writing by the Board.

 

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(c) You shall: (i) provide services hereunder to the best of your skills and ability and in an efficient manner and devote such time and effort to the business and affairs of the Company as necessary or advisable to perform your duties hereunder; (ii) act in a manner which you in good faith believe is in the best interests of the Company; (iii) implement any business plan adopted by the Company and then in effect; (iv) perform your duties hereunder, including without limitation any duties reasonably assigned to you by the Company, in good faith; (v) keep the Company reasonably informed on all matters that are material to the Company; (vi) be subject to, and comply with, the Company’s and the Windsor Group’s rules, practices and policies applicable to executive employees as reflected in the employee handbook, codes of conduct, compliance policies or otherwise, as may be amended from time to time; and (vii) cause the Company to comply with all applicable laws and regulations and monitor the development, maintenance, operation and management of the business of the Company to ensure such development, maintenance, operation and management complies with all applicable laws.

4. Benefits. You shall be entitled to twenty-five (25) paid vacation days per annum. You also shall have the benefit of such life and medical insurance plans and other similar plans as the Windsor Group may have or may establish from time to time for its executive employees generally, subject to satisfaction of applicable eligibility requirements. The foregoing, however, shall not be construed to require any Windsor Company to establish any such plans or to prevent any Windsor Company from modifying or terminating any such plans, and no such action or failure thereof shall affect this Agreement.

5. Expenses. The Company shall reimburse you, in accordance with the Company’s policies, for reasonable expenses incurred by you in the ordinary course in connection with the business of the Windsor Group upon the presentation by you of appropriate substantiation for such expenses.

6. Restrictive Covenants.

(a) Subject to Section 6(b) below, from the Effective Date until the later of the termination of your employment with, engagement as a consultant of, or other affiliation with, any Windsor Company, and for a period ending on the date that is six (6) months thereafter (such period, the “Restricted Period”), neither you nor any of your affiliates shall, without the written consent of the Board, at any time or in any manner, either directly or indirectly, become associated with, render services to, invest in, represent, advise or otherwise participate as an officer, employee, director, stockholder, partner, member, agent of or consultant for any company, business, organization or other legal or natural person that engages or participates in the Restricted Business; provided, however, that nothing herein shall prevent you from acquiring up to two percent (2%) of the securities of any company listed on a national securities exchange or quoted on the NASDAQ quotation system, provided your involvement with any such company is solely that of a passive stockholder. For purposes of this Agreement, “Restricted Business” means (i) the oil and gas exploration and production business in Texas, Oklahoma and New Mexico and each other area, location or field in which the Windsor Group conducts or is preparing to conduct business during the term or (ii) any other business or operation that is in competition with any business or operations managed or operated by or under consideration or in development by any Windsor Company.

 

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(b) The parties hereto intend that the covenant contained in this Section 6 shall be deemed a series of separate covenants for each state, county and city in which the Windsor Group’s business is conducted or is preparing to be conducted. If, in any judicial proceeding, a court shall refuse to enforce all of the separate covenants deemed included in this Section 6 because, taken together, they cover too extensive a geographic area, the parties intend that those covenants (taken in order of the states, counties and cities therein which are least populous), which if eliminated would permit the remaining separate covenants to be enforced in such proceeding, shall, for the purpose of such proceeding, be deemed eliminated from the provisions of this Section 6.

7. Confidentiality, Non-Interference, Proprietary Information and Non-Solicitation.

(a) Confidentiality. In the course of your employment by the Windsor Companies, you have had, and/or shall have, access to confidential or proprietary data or information of the Windsor Group, Wexford Capital LP (“Wexford”), any affiliates of the foregoing, the investment funds and managed accounts for which Wexford or its affiliates serves as general partner or acts as investment manager (the “Funds”), entities managed by Wexford or served by the Windsor Group, including without limitation entities in which the Funds have invested, directly or indirectly and their respective businesses (collectively the “Wexford Parties” and each of them individually, a “Wexford Party,” which for the avoidance of doubt shall include the Windsor Group). You shall not at any time during or after your employment divulge or communicate to any person (which term, for purposes of this Agreement, includes both persons or entities) nor shall you direct any Windsor Group employee to divulge or communicate to any person (other than to a person bound by confidentiality obligations similar to those contained herein and other than as necessary in performing your duties hereunder), or use to the detriment of the Wexford Parties or for the benefit of any other person, any of such data or information. No business conducted by you or any organization of which you, directly or indirectly, are an owner, partner, manager, joint venturer, director, officer, manager or otherwise a participant in or connected with in any locality, state or country in which the Wexford Parties conduct business shall use any name, designation or logo which is substantially similar to that presently used by any Wexford Party. The term “confidential or proprietary data or information” as used in this Agreement shall mean any information not generally available to the public or generally known within the applicable Wexford Party’s industry, including, without limitation, personnel information, financial information, customer lists or contacts, supplier lists, strategy and plans, information regarding operations, systems, services, know-how, computer and any other processed or collated data, trade secrets (including, without limitation, software), computer programs, pricing, marketing and advertising data.

(b) Non-Interference. You agree that, during the Restricted Period, you shall not, at any time or in any manner, either directly or indirectly, for your own account or for the account of any other person, interfere with any Wexford Party’s relationship with any of its employees, suppliers or regulators.

(c) Proprietary Information and Disclosure. You agree that you shall at all times promptly disclose to the Company, in such form and manner as the Company may require, any inventions, improvements or procedural or methodological innovations, program methods, forms, systems, services, designs, marketing ideas, products or processes (whether or not capable

 

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of being trademarked, copyrighted or patented) conceived or developed or created by you during or in connection with your employment hereunder and which relate to the business of any Wexford Party (“Intellectual Property”). You agree that all such Intellectual Property constitutes a work-for-hire and shall be the sole property of the applicable Wexford Party. You further agree that you shall execute such instruments and perform such acts as may be requested by the Company to transfer to and perfect in the entity designated by the Company all legally protectable rights in such Intellectual Property.

(d) Return of Property. All materials, records and documents in any medium made by you or coming into your possession during your employment concerning any products, processes or services, manufactured, used, developed, investigated, provided or considered by any Wexford Party or otherwise concerning the business or affairs of the Wexford Parties, shall be the sole property of the applicable Wexford Party, and upon termination of your employment, or upon request of the Company during your employment, you shall promptly deliver the same to the Wexford Party designated by the Company. In addition, upon termination of your employment, or upon request of the Company during your employment, you shall deliver to the Wexford Party designated by the Company all other property of the Wexford Parties in your possession or under your control, including, but not limited to, financial statements, marketing and sales data, drawings, documents and electronic records.

(e) Non Solicitation of Customers. Notwithstanding any other provision of this Agreement, you agree that, during the Restricted Period, you shall not at any time or in any manner, on your own behalf, or on behalf of any other individual, sole proprietorship, business, firm, partnership, company, corporation or other entity other than the Company, directly solicit, or ask anyone else to solicit, the sale of goods, services or a combination of goods and services, which are the same or similar to those provided by the Windsor Group, from Established Customers. You further agree that for the same period, you will not in any way interfere or attempt to interfere with the Windsor Group’s relationships with any of their Established Customers. “Established Customers” means any customer that the Windsor Group has actually done business with during the twelve (12) months preceding the last date of the Restricted Period.

(f) Non Solicitation, Non Hire of Employees. Notwithstanding any other provision of this Agreement, you agree that, during the Restricted Period, you shall not at any time or in any manner, either directly or indirectly, either on your behalf or on behalf of any person (other than the Windsor Group), recruit, solicit, hire, divert or otherwise encourage or attempt to recruit, solicit, hire, divert or otherwise encourage any officer or employees or agents of any Windsor Company to enter into any employment, consulting or advisory arrangement or contract with or to perform any services for or on your behalf or on behalf of any person (other than the Windsor Group), or to enter into any kind of business with you or any other person, including, without limitation, any Restricted Business.

(g) Non-Disparagement. You agree not to make public statements, negative comments or otherwise disparage any Wexford Party or any Wexford Party’s officers, directors, employees, agents, shareholders or other equity holders in any manner harmful to them or their business, business reputation or personal reputation. The foregoing shall not be violated by truthful statements in response to legal process, required governmental testimony or filings, or administrative or arbitral proceedings (including, without limitation, depositions in connection with such proceedings).

 

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(h) Cooperation. Upon the receipt of reasonable notice from the Company (including outside counsel), you agree that while employed by any Windsor Company and thereafter, you shall provide reasonable assistance to any Wexford Party and their respective representatives in defense of any claims that may be made against any Wexford Party and shall assist any Wexford Party in the prosecution of any claims that may be made by any Wexford Party, to the extent that such claims relate to the period of your employment with a Windsor Company. You agree to promptly inform the Company if you become aware of any lawsuits involving such claims that may be filed or threatened against any Wexford Party. You also agree to promptly inform the Company (to the extent legally permitted to do so) if you are asked to assist in any investigation of any Wexford Party (or its actions), regardless of whether a lawsuit or other proceeding has then been filed against any Wexford Party with respect to such investigation. Upon presentation of appropriate documentation, the Company shall pay or reimburse you for all reasonable out-of-pocket expenses incurred by you in complying with this Section 7(h). If at the time of compliance you are no longer an employee, officer or director (or functional equivalent) of any Windsor Company, the Company shall provide a reasonable per diem to you.

8. Interpretation, Enforcement and Construction.

(a) Equitable Relief. With respect to the covenants contained in Sections 6 and 7 of this Agreement, you agree that any remedy at law for any breach of said covenants may be inadequate and that the Company shall be entitled to specific performance or any other mode of injunctive and/or other equitable relief to enforce its rights hereunder or any other relief a court might award. In the event of a violation by you of Section 6 or Section 7 hereof, any compensation being paid to you pursuant to this Agreement or otherwise shall immediately cease, and any Base Salary previously paid to you after termination of your employment shall be immediately repaid to the Company. The amount of any earned Base Salary paid for the period prior to termination of your employment shall be retained by you.

(b) Reformation. The agreements made in Sections 6 and 7 are material inducements for you to enter into this Agreement and the Company would not have made this Agreement with you without such assurances. You understand and agree that the geographic area applicable to Section 6 is based on the nature of the products and services provided by the Windsor Group and the broad distribution of their customers, and that the limitations set forth therein are reasonable in geographic area and time and necessary for the protection of the Windsor Group and its goodwill. However, if any court shall determine that the time, geographic area or scope of activity of any restriction contained in Section 6 is unenforceable, it is our intention that such limitation set forth herein shall not be terminated but shall be amended to the extent required to render it valid and enforceable. A court hearing any such dispute is empowered and authorized by the parties to reform this Agreement to the maximum time, scope or geographic limitations permitted by applicable law.

 

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9. Earlier Termination. Your employment shall terminate prior to the expiration of the Term on any of the following terms and conditions:

(a) Death or Disability. Your employment shall terminate automatically on the date of your death or immediately upon the Company’s sending you a notice of termination for “Disability”, which shall mean your inability to perform your duties hereunder for ninety (90) days (whether or not continuous) during any period of three hundred sixty-five (365) consecutive days by reason of physical or mental disability. Upon termination of your employment for death or Disability pursuant to this Section 9(a), the Company’s sole obligations to you shall be, subject to your compliance with the provisions of Sections 6 and 7 hereof, to (i) pay your Base Salary for the remainder of the Term, which shall be paid as and when such amounts would have been due had your employment continued and (ii) honor any obligations of the Company with respect to the Company Option or Diamondback Option, as applicable, under Sections 2(c) and (d) hereof.

(b) Resignation Not for Good Reason; Termination for Cause. Your employment shall terminate (x) no less than thirty (30) days after you send the Company written notice of resignation or (y) immediately upon the Company’s sending you written notice terminating your employment hereunder for Cause (as defined below), and you and the Company shall have no further obligations hereunder other than your obligations under Sections 6 and 7 hereof and the Company’s obligation to pay you any of your accrued but unpaid Base Salary through the date of termination and honor any of its obligations with respect to the vested portion of any Company Option or Diamondback Option, as applicable, under Sections 2(c) and (d) hereof. “Cause” shall mean (A) your willful and knowing refusal or failure (other than during periods of illness, physical or mental incapacity) to perform your duties in any material respect under this Agreement; (B) your willful misconduct or gross negligence in the performance of your duties; (C) your material breach of this Agreement, any other agreement entered into by you related to the Company or its affiliates, or any Company or Windsor Group policy (including any applicable code of conduct); (D) your breach of Sections 6 or 7 of this Agreement; (E) your conviction of, entry of a guilty plea or a plea of nolo contendere to any criminal act that constitutes a felony or involves, fraud, dishonesty, or moral turpitude; (F) your indictment for any felony involving embezzlement or theft or fraud; (G) your filing of a voluntary petition in bankruptcy or your consent to an involuntary petition in bankruptcy (or your failure to vacate, within ninety (90) days of the entry thereof, any order approving an involuntary petition in bankruptcy) or the entry of an order, judgment or decree by any court of competent jurisdiction, on the application of a creditor, adjudicating you as bankrupt or insolvent or the appointment of a receiver, trustee, or liquidator of all or a substantial part of your assets, and such order, judgment or decree’s continuing unstayed and in effect for any period of ninety (90) days; (H) your dishonesty in connection with your responsibilities as an employee; or (I) your failure to comply with any lawful directive of the Board after five (5) business days’ written notice to you thereof. If you terminate your employment pursuant to clause (x) of the preceding sentence, the Company shall be entitled to accelerate the effectiveness of the termination of your employment to whatever time and date as it shall designate in writing to you in its sole discretion.

(c) Resignation for Good Reason; Termination Without Cause. Your employment shall terminate immediately upon the Company’s sending you written notice terminating your employment hereunder without Cause for any reason or for no reason (a “No Cause Termination”) or upon your resignation in the event of any (i) material breach by the Company hereunder or (ii) material diminution in the your position, duties, or authority, which in either case is not cured within thirty (30) business days after written notice thereof by you to the

 

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Board (which notice must be provided by you to the Company within 90 days following the initial occurrence of such event) and an opportunity to cure within the notice period (collectively, “Good Reason Resignation”). Any termination on account of a Good Reason Resignation must occur within two years following the initial occurrence of such event. Upon any such No Cause Termination or Good Reason Resignation, as the case may be, the Company’s sole obligation(s) to you shall be (x) in the case of a No Cause Termination or your Good Reason Resignation under this Section 9(c), to pay you your Base Salary for the remainder of the Term, which shall be paid as and when such amounts would have been due had your employment continued and (y) in the case of a No Cause Termination, to honor any obligations of the Company with respect to the Company Option or Diamondback Option, as applicable, under Sections 2(c) and (d) hereof; provided that any such payment shall be subject to your continued compliance with the provisions of Sections 6 and 7 hereof and your executing (and not revoking) a full general release in a form as requested by the Company, releasing all claims, known or unknown, that you may have against any Wexford Party, their officers, directors, employees and agents, arising out of or any way related to your employment or termination of employment with the Company; provided further that, for the purposes of this Section 9(c) only, the Restricted Period under Section 6 shall end on the last day of the Term. Payments provided under this Section 9(c) shall be in lieu of any termination or severance payments or benefits for which you may be eligible under any of the plans, policies or programs of the Company or its affiliates or under the WARN Act or any similar state statute or regulation. If you accept other employment or engages in your own business prior to the last date of the Term, you shall promptly notify the Company.

(d) “At-Will” Employment. Any continued employment with the Company during and after the Term is “at-will”, meaning you have the right at any time, and for any reason or no reason, to terminate your employment with or without notice, and the Company has the same right. You understand and agree the Company shall not be obligated to continue your employment prior to the expiration of the Term. Any continuation of employment after the Term shall be on such terms and conditions as the Company shall then offer in its discretion.

(e) No Other Obligation. Except as specifically set forth in Sections 9(a) and (c) above, upon termination of your employment under this Agreement, the Company’s obligations hereunder shall cease and neither the Company nor, for the avoidance of doubt, any other Windsor Company, shall have any further obligations to you whatsoever.

10. Representation and Warranty. You represent that you do not have any contractual or other obligations that would conflict with your employment by the Company. In particular, you represent that you are not bound by any agreement, understanding or other obligation with or to any person or entity (including, without limitation, any confidentiality, non-competition or non-solicitation agreement) that prohibits you from accepting or continuing your employment by the Company and fully performing all of your duties for the Company. You also acknowledge that it is the Company’s policy to respect the legal rights of others to protect their confidential information. You therefore represent that you have not taken or retained any confidential information (or other property) belonging to a prior employer and shall not use or disclose any such confidential information in connection with your work for the Company. Any inaccuracy of any of the statements set forth in this Section 10 shall constitute “Cause” for purposes of this Agreement, in which event we would be entitled to terminate your employment under Section 9(b) above with the effect set forth therein.

 

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11. Dealings with Related Parties. You shall not engage in any dealings on behalf of any Windsor Company with any party in which you or any person or entity affiliated with you, or members of your or their respective immediate families, has a financial interest, without first disclosing same to the Board in a writing specifically describing the nature of the interest and obtaining the Company’s prior written approval.

12. Entire Agreement; Modification. This Agreement constitutes the full and complete understanding of the parties with respect to your employment arrangements with the Company and any of its affiliates and shall, on the Effective Date, supersede all prior agreements and writings between you, on the one hand, and the Company or any other Windsor Company (or any of their respective predecessors), on the other hand, with respect to your employment arrangements with the Company or any of its affiliates (the “Prior Agreements”). No representations, inducements, promises, agreements or understandings, oral or otherwise, have been made by either party to this Agreement, or anyone acting on behalf of either party, which are not set forth herein, and any others are specifically waived. This Agreement may not be amended or modified in any manner nor may any of its provisions be waived except by written amendment executed by the parties. A waiver, modification or amendment by a party shall only be effective if (a) it is in writing and signed by the parties, (b) it specifically refers to this Agreement and (c) it specifically states that the party is waiving, modifying or amending its rights hereunder. Any such amendment, modification or waiver shall be effective only in the specific instance and for the specific purpose for which it was given.

13. Severability. The terms and provisions of this Agreement shall be deemed severable, and the invalidity or unenforceability of any one or more of the provisions hereof shall not affect the validity or enforceability of any one or more of the other provisions hereof. In the event any term or provision of this Agreement which is invalid or unenforceable in any jurisdiction shall, as to such jurisdiction, shall be ineffective to the extent of such invalidity or unenforceability without rendering invalid or unenforceable the remaining terms and provisions of this Agreement or affecting the validity or enforceability of any of the terms or provisions of this Agreement in any other jurisdiction and the parties agree the conflicting term or provision shall be modified to conform.

14. Notices. All notices and other communications given or made pursuant to this Agreement shall be in writing and shall be deemed effectively given upon the earlier of actual receipt or: (a) personal delivery to the party to be notified, (b) when sent, if sent by electronic mail or facsimile during normal business hours of the recipient, and if not sent during normal business hours, then on the recipient’s next business day, (c) five (5) days after having been sent by registered or certified mail, return receipt requested, postage prepaid, or (d) one (1) business day after deposit with a nationally recognized overnight courier, freight prepaid, specifying next business day delivery, with written verification of receipt, if to you, to your residence, email or facsimile, as applicable, as listed in the Company’s records, and if to the Company, c/o Wexford Capital LP, 411 West Putnam Avenue, Greenwich, Connecticut 06830, attention of General Counsel, email: aamron@wexford.com, facsimile: 203-862-7312, with a copy to Windsor Permian, LLC, 14301 Caliber Drive, Suite 300, Oklahoma City, Oklahoma 73134, attention of General Counsel.

 

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15. Assignability; Binding Effect. This Agreement shall not be assignable by you without the written consent of the Board. Any other attempted assignment, transfer, conveyance or other disposition of your right to compensation or other benefits will be null and void. This Agreement shall be binding upon and inure to the benefit of you, your legal representatives, heirs and distributees, and shall be binding upon and inure to the benefit of the Company, its affiliates and its and their respective successors and assigns, including, without limitation, those by asset assignment, stock sale, merger, consolidation or other reorganization (each a “Permitted Assignee”). The Company shall have the right to assign its rights and obligations under this Agreement to any Permitted Assignee and will give you written notice of any such assignment.

16. Governing Law; Venue; Waiver of Trial by Jury.

(a) This Agreement and the rights of the parties hereunder shall be governed by, interpreted, and enforced in accordance with the internal laws of the State of Oklahoma without giving effect to any choice of law or conflicts of law rules or provisions thereof.

(b) Each party irrevocably agrees that any action or proceeding involving any dispute or matter arising under this Agreement may only be brought in the federal courts of the State of Texas, or if such court does not have jurisdiction or shall not accept jurisdiction, in any court of general jurisdiction in the State of Oklahoma. All parties hereby irrevocably consent to the exclusive jurisdiction by any such court with respect to any such proceeding and hereby irrevocably waives, and agrees not to assert, by way of motion, as a defense, counterclaim or otherwise (i) any claim that it is not personally subject to the jurisdiction of the above-named courts for any reason other than by failure to lawfully serve process, (ii) that it or its property is exempt or immune from the jurisdiction of any such court or from any legal process commenced in such courts, and (iii) to the fullest extent permitted by applicable law, that (x) the action or proceeding is brought in an inconvenient forum, (y) the venue of such action or proceeding is improper and (z) this Agreement or the subject matter thereof may not be enforced in or by such courts.

(c) To the extent not prohibited by applicable law, each party to this Agreement hereby waives, and covenants that it shall not assert (whether as plaintiff, defendant or otherwise), its respective right to a jury trial of any permitted claim or cause of action arising out of this Agreement, any of the transactions contemplated hereby, or any dealings between any of the parties hereto relating to the subject matter of this Agreement or any of the transactions contemplated hereby. The scope of this waiver and covenant is intended to be all encompassing of any and all disputes that may be filed in any court and that relate to the subject matter of this Agreement or any of the transactions contemplated hereby, including, contract claims, tort claims and all other common law and statutory claims. This waiver and covenant is irrevocable and shall apply to any subsequent amendments, supplements or other modifications to this Agreement.

17. Prevailing Party Expenses. In the event that litigation or other legal action is instituted between you and the Company or any of its affiliates to enforce the rights under this Agreement, the successful party in such litigation or other legal action shall be entitled to reimbursement from the unsuccessful party in such litigation or other legal action of all reasonable fees, costs and expenses (including court costs and reasonable attorneys’ fees) incurred by such successful party in connection with such litigation or other legal action.

 

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18. Third Party Beneficiaries. The Wexford Parties and their successors and assigns, as express third party beneficiaries of this Agreement, shall be entitled, in their sole and absolute discretion, to enforce any of the provisions hereof from time to time, including, but not limited to, the restrictions set forth in Sections 6 and 7 of this Agreement.

19. Titles and Subtitles. The titles and subtitles used in this Agreement are used for convenience only and are not to be considered in construing or interpreting this Agreement.

20. Counterparts; Facsimile. This Agreement may be executed and delivered by facsimile signature and in two or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same instrument.

21. Review of this Agreement. You acknowledge that you have (a) carefully read this Agreement, (b) consulted with independent counsel with respect to this Agreement and (c) entered into this Agreement of your own free will.

22. Survival. The obligations of Sections 6, 7, 8, 14, 16 and 17 shall expressly survive any expiration or termination of this Agreement.

23. Background Verification. You hereby authorize the Company to conduct one or more Background Verifications prior to and during your actual employment. “Background Verification” includes, without limitation, information regarding your employment and other experience, educational background and any criminal, credit or regulatory history. You further authorize, without reservation, any law enforcement agency, administrator, court, governmental body, federal or provincial agency, institution, school or university (public or private), information service bureau, employer or insurance company contacted by the Company or any agent of the Company to furnish the information set forth in the preceding sentence as part of the employment application process. You hereby consent to and understand that the Company will only use the information collected for the purposes of (if and as applicable) establishing or continuing your employment, including without limitation, evaluating your employment application, determining employment eligibility under the Company’s employment policies, assessing property and business risks to the Company, and otherwise as may be permitted or required by law. You authorize and consent to the release of records obtained through such checks to the authorized representatives of the Company or its agents, and to the Company’s affiliates, for the purposes described above. You acknowledge and agree that any information relating to a Background Verification may be shared with any Wexford Party and stored on the respective servers.

24. Code Section 409A and Other Tax Considerations.

(a) Deferred Compensation Exceptions. Payments under this Agreement will be administered and interpreted to maximize the short-term deferral exception to and the involuntary separation pay exception under Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”), and the regulations thereunder (collectively “Section 409A”). The portion of any payment under this Agreement that is paid within the short-term deferral period

 

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(within the meaning of Code Section 409A and Treas. Regs. §1.409A-1(b)(4)) or that is paid within the involuntary separation pay safe harbor (as described in Code Section 409A and Treas. Regs. §1.409A-1(b)(9)(iii)) will not be treated as nonqualified deferred compensation and will not be aggregated with other nonqualified deferred compensation plans or payments.

(b) Separate Payments and Payment Timing. Any payment or installment made under this Agreement and any amount that is paid as a short-term deferral, within the meaning of Treas. Regs. §1.409A-1(b)(4), will be treated as separate payments. Employee will not, directly or indirectly, designate the taxable year of a payment made under this Agreement. Payment dates provided for in this Agreement will be deemed to incorporate grace periods that are treated as made upon a designated payment date within the meaning of Code Section 409A and Treas. Regs. §1.409A-3(d).

(c) General 409A Provisions. If for any reason, the short-term deferral or involuntary separation pay plan exception is inapplicable, payments and benefits payable to Employee under this Agreement are intended to comply with the requirements of Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”). To the extent the payments and benefits under this Agreement are subject to Section 409A of the Code, this Agreement will be interpreted, construed and administered in a manner that satisfies the requirements of Sections 409A(a)(2), (3) and (4) of the Code and the Treasury Regulations thereunder (and any applicable transition relief under Section 409A of the Code). The Company does not guaranty or warrant the tax consequences of this Agreement and, except as specifically provided to the contrary in this Agreement, Employee will, in all cases, be liable for any taxes due as a result of this Agreement. Neither the Company nor any of its affiliates shall have any obligation to indemnify or otherwise hold you harmless from any or all such taxes, interest or penalties, or liability for any damages related thereto. Employee acknowledges that he has been advised to obtain independent legal, tax or other counsel in connection with Section 409A.

(i) If Employee or the Company determines that any payments or benefits payable under this Agreement intended to comply with Sections 409A(a)(2), (3) and (4) of the Code do not comply with Section 409A of the Code, Employee and the Company agree to amend this Agreement, or take such other actions as Employee and the Company deem reasonably necessary or appropriate, to comply with the requirements of Section 409A of the Code, the Treasury Regulations thereunder (and any applicable relief provisions) while preserving the economic agreement of the parties. If any provision of the Agreement would cause such payments or benefits to fail to so comply, such provision will not be effective and will be null and void with respect to such payments or benefits, and such provision will otherwise remain in full force and effect.

(ii) All payments considered nonqualified deferred compensation under Section 409A and the regulations thereunder will be made on the date(s) provided herein and no request to accelerate or defer any payment under this Section will be considered or approved for any reason whatsoever, except as permitted under Section 409A. The Base Salary continuation payments will commence on the first payroll date that is on or after the eighth day following receipt by the Company of Employee’s executed release; provided, however, if the Base Salary continuation payments are deferred compensation subject to Code Section 409A and if the period during which

 

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Employee has discretion to execute or revoke the release straddles two taxable years of Employee, then the Company will commence the Base Salary continuation payments in the second of such taxable years. Notwithstanding the foregoing, subject to the release requirement, the Base Salary continuation payments will in all events be paid no later than 60 days following Executive’s termination of employment, regardless of which taxable year Executive actually delivers the executed Release to the Company. Once such Base Salary continuation payments commence, the first installment thereof will include all amounts that would have been paid had such payments commenced on the first payroll date occurring on or after the termination of employment date. Executive may not, directly or indirectly, designate the calendar year of the commencement of any payment hereunder. Notwithstanding the foregoing, amounts payable hereunder which are not nonqualified deferred compensation, or which may be accelerated pursuant to Section 409A, such as distributions for applicable tax payments, may be accelerated, but not deferred, at the sole discretion of Company.

(iii) All references in this Agreement to termination of employment or termination mean Employee’s “separation from service” as that term is defined in Section 1.409A-1(h) of the Treasury Regulations.

(iv) All reimbursements and in-kind benefits provided under this agreement that constitute deferred compensation within the meaning of Section 409A of the Code shall be made or provided in accordance with the requirements of Section 409A of the Code, including that (i) in no event shall reimbursements by the Company under this agreement be made later than the end of the calendar year next following the calendar year in which the applicable fees and expenses were incurred, provided that you shall have submitted an invoice for such fees and expenses at least 10 days before the end of the calendar year next following the calendar year in which such fees and expenses were incurred; (ii) the amount of in-kind benefits that the Company is obligated to pay or provide in any given calendar year (other than medical reimbursements described in Treas. Reg. § 1.409A-3(i)(1)(iv)(B)) shall not affect the in-kind benefits that the Company is obligated to pay or provide in any other calendar year; (iii) your right to have the Company pay or provide such reimbursements and in-kind benefits may not be liquidated or exchanged for any other benefit; and (iv) in no event shall the Company’s obligations to make such reimbursements or to provide such in-kind benefits apply later than your remaining lifetime or, if longer, through the 20th anniversary of the Effective Date.

(d) Specified Employee Status. If Employee is a specified employee (within the meaning of Code Section 409A) on the date of his separation from service, any payments made with respect to such separation from service under this Agreement, and other payments or benefits under this Agreement that are subject to Section 409A of the Code, will be delayed in order to comply with Section 409A(a)(2)(B)(i) of the Code, and such payments or benefits will be paid or distributed to you during the five-day period commencing on the earlier of: (i) the expiration of the six-month period measured from the date of your separation from service, or (ii) the date of your death. Upon the expiration of the applicable six-month period under Section 409A(a)(2)(B)(i) of the Code, all payments deferred pursuant to this Section (e) will be paid to Employee (or Employee’s estate, in the event of Employee’s death) in a lump sum payment. Any remaining payments and benefits due under the Agreement will be paid as otherwise provided in the Agreement.

 

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(e) Withholding Taxes. To the extent any payments under this Agreement are wages subject to income and employment tax withholding, the Company has the right to withhold or otherwise require Executive to pay to the Company the amount of any taxes that the Company may be required to withhold before delivery of such payment to Executive.

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IN WITNESS WHEREOF, each of the parties has executed this Agreement, in the case of the Company by its duly authorized officers, as of the day and year first above written.

 

				WINDSOR PERMIAN, LLC
Date:     July 3, 2012				By:		/s/ Travis Stice
						Travis Stice, Chief Executive Officer
				TERESA DICK
Date:     July 3, 2012				/s/ Teresa Dick

Windsor Permian, LLC Teresa Dick Employment Agreement Signature Page

Exhibit 21.1

Significant Subsidiaries of Diamondback Energy, Inc.

Diamondback E&P LLC

Windsor Permian LLC

Windsor UT LLC

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued (i) our report dated March 23, 2012, with respect to the consolidated financial statements of Windsor Permian LLC, (ii) our report dated May 1, 2012, with respect to the financial statements of Windsor UT LLC, and (iii) our report dated April 24, 2012, with respect to the statements of revenues and direct operating expenses of working and revenue interests of certain oil and gas properties owned by Gulfport Energy Corporation, contained in the Registration Statement and Prospectus of Diamondback Energy, Inc. We consent to the use of the aforementioned reports in the Registration Statement and Prospectus, and to the use of our name as it appears under the caption “Experts”.

/s/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

July 3, 2012

Exhibit 23.2

CONSENT OF PINNACLE ENERGY SERVICES, LLC

We have issued our report letters dated January 25, 2011 and January 6, 2010 for the years ended December 31, 2010 and 2009, respectively, on estimates of proved reserves and future net cash flows of certain oil and natural gas properties located in the Permian Basin of West Texas of Windsor Permian LLC, successor in interest to Windsor Energy Group, LLC. As independent oil and gas consultants, we hereby consent to the use and inclusion of information from the aforementioned report letters in this Amendment to the Registration Statement on Form S-1/A. We hereby also consent to the references to our firm and to the use of our name, as it appears under the caption “Experts,” in this Amendment to the Registration Statement on Form S-1/A.

 

July 3, 2012

Oklahoma City, Oklahoma

Exhibit 23.3

CONSENT OF RYDER SCOTT COMPANY, L.P.

We hereby consent to the references to our firm in this Amendment to the Registration Statement on Form S-1/A for Diamondback Energy, Inc. and to the use of information from, and the inclusion of, in this Amendment our reports dated May 31, 2012, May 31, 2012 and May 29, 2012 with respect to the estimates of reserves, future production and income attributable to certain leasehold interests of Windsor Permian LLC, Windsor UT, LLC and Gulfport Energy Corporation, respectively, in properties located in the Permian Basin in West Texas, in each case as of December 31, 2011. We further consent to the reference to our firm under the heading “Experts” in this Amendment and related prospectus.

/s/ RYDER SCOTT COMPANY, L.P.

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

July 3, 2012

Houston, Texas