Amendment No. 5 to Form S-1
Table of Contents
Index to Financial Statements

As filed with the Securities and Exchange Commission on October 2, 2012

Registration No. 333-179502

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

AMENDMENT NO. 5

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   ¨

CALCULATION OF REGISTRATION FEE

 

 

Title of each Class of

Securities to be Registered

 

Proposed

Maximum 

Aggregate

Offering Price(2)

 

Amount of

Registration Fee(3)

Common Stock, par value $0.01 per share(1)

  $273,125,000   $36,164.25

 

 

(1) Includes shares of common stock that may be sold to cover the exercise of an option to purchase additional shares granted to the underwriters.
(2) Estimated solely for the purpose of calculating the registration fee in accordance with Rule 457(o) under the Securities Act.
(3) Registrant has previously paid a registration fee of $5,730 in connection with the registration statement on Form S-1 (Registration Statement No. 333-179502) filed on February 14, 2012.

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.

 

 

 


Table of Contents
Index to Financial Statements

The information in this prospectus is not complete and may be changed. We 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 are not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

 

SUBJECT TO COMPLETION, DATED OCTOBER 2, 2012.

PROSPECTUS

12,500,000 Shares

 

LOGO

Diamondback Energy, Inc.

Common Stock

 

 

This is the initial public offering of our common stock. 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 $17.00 and $19.00 per share. We have applied to list our common stock on The NASDAQ Global Market under the symbol “FANG.”

We have granted the underwriters an option to purchase up to 1,875,000 additional shares of our common stock to cover the underwriters’ option to purchase additional shares.

Wexford Capital LP, or Wexford, our equity sponsor, has indicated that it or one or more of its affiliates may purchase in this offering up to $30.0 million, or up to approximately 1,666,667 shares (based on the midpoint of the price range set forth on the cover page of this prospectus), of our common stock at the same price as the price to the public. The underwriters will not receive any underwriting discounts or commissions on any shares sold to Wexford or its affiliates. The number of shares available for sale to the general public will be reduced to the extent Wexford or its affiliates purchase such shares. See “Underwriting (Conflicts of Interest)” beginning on page 151.

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 18.

 

   

Price to
Public

  

Underwriting
Discounts and
Commissions

 

Proceeds to
Diamondback

Per Share

  $                $               $            

Total(1)

  $                    $                   $                

 

(1) Assumes Wexford or its affiliates have not purchased shares of our common stock in this offering, for which the underwriters would not receive any underwriting discounts or commissions.

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

 

Raymond James   Tudor, Pickering, Holt & Co.    Wells Fargo Securities

 

Capital One Southcoast

     
  Scotiabank / Howard Weil      
   

Simmons & Company

         International

   
                        Sterne Agee  
      SunTrust Robinson Humphrey            
        Wunderlich Securities

The date of this prospectus is                     , 2012.


Table of Contents
Index to Financial Statements

 

TABLE OF CONTENTS

 

     Page  

PROSPECTUS SUMMARY

     1   

RISK FACTORS

     18   

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

     45   

USE OF PROCEEDS

     46   

DIVIDEND POLICY

     46   

CAPITALIZATION

     47   

DILUTION

     49   

SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

     51   

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

     54   

MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     61   

BUSINESS

     90   

MANAGEMENT

     115   

RELATED PARTY TRANSACTIONS

     134   
     Page  

PRINCIPAL STOCKHOLDERS

     140   

DESCRIPTION OF CAPITAL STOCK

     142   

SHARES ELIGIBLE FOR FUTURE SALE

     145   

MATERIAL U.S. FEDERAL INCOME AND ESTATE TAX CONSIDERATIONS FOR NON-U.S. HOLDERS

     147   

UNDERWRITING (CONFLICTS OF INTEREST)

     151   

LEGAL MATTERS

     157   

EXPERTS

     157   

WHERE YOU CAN FIND MORE INFORMATION

     157   

GLOSSARY OF OIL AND NATURAL GAS TERMS

     A-1   

RESERVE REPORT OF RYDER SCOTT COMPANY , L.P.

     B-1   

RESERVE REPORT OF RYDER SCOTT COMPANY , L.P. (WINDSOR UT)

     C-1   

RESERVE REPORT OF RYDER SCOTT COMPANY , L.P. (GULFPORT TRANSACTION PROPERTIES)

     D-1   

INDEX TO FINANCIAL STATEMENTS

     F-1   
 

 

 

ABOUT THIS PROSPECTUS

You should rely only on the information contained in this prospectus. We have not, 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 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 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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Index to Financial Statements

PROSPECTUS SUMMARY

This summary contains basic information about us and the offering. Because it is a summary, it does not contain all the information that you should consider before investing in our common stock. Except as expressly noted otherwise, the historical assets, operations and results described in this prospectus are those of Windsor Permian LLC, or Windsor Permian. Windsor Permian is a wholly-owned subsidiary of Diamondback Energy LLC, an entity controlled by Wexford Capital LP, or Wexford. Prior to the effectiveness of the registration statement of which this prospectus is a part, Diamondback Energy LLC will be merged with and into Diamondback Energy, Inc. and Diamondback Energy, Inc. will continue as the surviving entity. As a result of this merger, Windsor Permian will become our wholly-owned subsidiary. In addition, Wexford has agreed to cause all of the outstanding equity interests in Windsor UT LLC, or Windsor UT, to be contributed to Windsor Permian prior to the merger in a transaction we refer to as the Windsor UT contribution. Windsor UT owns oil and natural gas interests in the Permian Basin. On May 7, 2012, we entered into an agreement with Gulfport Energy Corporation, or Gulfport, in which Gulfport agreed to sell to us, subject to certain conditions, all of its oil and natural gas interests in the Permian Basin in exchange for shares of our common stock and a promissory note in a transaction we refer to as the Gulfport transaction. The Gulfport transaction would be completed prior to the effectiveness of the registration statement of which this prospectus is a part and immediately after the merger described above. In this prospectus, we refer to the Gulfport transaction and the Windsor UT contribution together as the Transactions. See “Prospectus Summary—The Transactions” beginning on page 7 of this prospectus for more information regarding the Transactions. Except as expressly noted otherwise, references to our operations and assets as of June 30, 2012 and thereafter give effect to the Transactions. You should read and carefully consider this entire prospectus before making an investment decision, especially the information presented under the heading “Risk Factors” and our financial statements and the accompanying notes included elsewhere in this prospectus, as well as the other documents to which we refer you. We have provided definitions for some of the oil and natural gas industry terms used in this prospectus in the “Glossary of Oil and Natural Gas Terms.”

DIAMONDBACK ENERGY, INC.

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 4,174 net acres with production at the time of acquisition of approximately 800 net barrels of oil equivalent, or BOE, per day from 34 gross (16.8 net) wells in the Permian Basin. Subsequently, we acquired approximately 26,878 additional net acres, which brought our total net acreage position in the Permian Basin to 31,052 net acres at August 31, 2012 and, after giving effect to the Transactions, we had 51,709 net acres. We are the operator of approximately 99% of this acreage. As of August 31, 2012, after giving effect to the Transactions, we had drilled 167 gross (155 net) wells, and participated in an additional 16 gross (seven net) non-operated wells, in the Permian Basin. Of these 183 gross wells, 171 were completed as producing wells and 12 are in various stages of completion. In the aggregate, as of August 31, 2012, we held interests in 205 gross (185 net) producing wells in the Permian Basin.

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-

 

 

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Index to Financial Statements

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.

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 916 identified potential vertical drilling locations on 40-acre spacing based on our evaluation of applicable geologic and engineering data as of August 31, 2012 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 48 gross (43 net) vertical wells on 40-acre spacing and two gross (two net) horizontal wells in the Wolfberry play. As of August 31, 2012, we were using two drilling rigs and, upon completion of this offering, intend to increase our drilling program to six 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 14 days during the period from April 2012 through August 2012 from 20 days during the second quarter of 2011. We also reduced the time from spud to production from an average of 68 days during the fourth quarter of 2011 to an average of 56 days during the second quarter of 2012. During the quarter ended June 30, 2012, our average daily production, pro forma for the Transactions, was 3,637 BOE/d, consisting of 2,579 Bbls/d of oil, 2,757 Mcf/d of natural gas and 599 Bbls/d of natural gas liquids, an increase of 13%, or 408 BOE/d, from 3,229 BOE/d, consisting of 2,365 Bbls/d of oil, 2,267 Mcf/d of natural gas and 486 Bbls/d of natural gas liquids, for the quarter ended March 31, 2012. This increase was due primarily to improved strategies and procedures introduced by our new executive team relating to wellbore configuration,

 

 

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Index to Financial Statements

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.

The following table provides a summary of selected operating information of our properties, pro forma for the Transactions. The information is as of August 31, 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

     51,709         87     916         849         59         48       $ 150.0-$160.0         39,460         23.9         3,712   

 

(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 (1,027 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 50 gross (45 net) wells, of which two gross (two net) wells are horizontal, for which we are the operator and nine gross (three net) non-operated wells, of which three gross (one net) wells are horizontal wells.
(3) During August 2012.

We currently anticipate our 2012 capital budget for drilling and infrastructure will be approximately $150.0 million to $160.0 million after giving effect to the Transactions. Of this amount, we plan to spend approximately $126.0 million on the drilling and completion of 48 gross (43 net) operated vertical wells and two gross (two net) horizontal wells, $11.0 million for the drilling and completion of nine gross (three net) non-operated wells, $6.0 million for leasehold acquisitions and $12.0 million for the construction of infrastructure to support production, including investments in water disposal infrastructure and gathering line projects. During the six months ended June 30, 2012, our aggregate capital expenditures for drilling and infrastructure after giving effect to the Transactions were $70.7 million.

Our Business Strategy

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

 

   

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 August 31, 2012, after giving effect to the Transactions, we had 916 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 48 gross (43 net) vertical wells and two gross (two 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 August 31, 2012, we were using two drilling rigs. Upon completion of this offering, we intend to increase our drilling program to six rigs. Subject to market conditions and rig availability, we expect to operate six rigs throughout 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. In June 2012, we completed our first horizontal operated well, in which we have a 100% interest, in the Wolfcamp B interval in Upton County and currently plan to drill one additional gross (one net) horizontal operated well in 2012, also targeting the Wolfcamp B interval. Our first horizontal operated well had a 3,842 foot lateral, a 24-hour initial production rate of 618 BOE/d and a 30-day average initial production rate of 486 BOE/d, of which 86% was oil. Based on the decline curve analysis of the current production, we anticipate that the EUR for this well will be in the range of 400 to 500 MBOE, of which 67% is expected to be oil. Additionally, since June 2012, we have participated in three gross (one net) horizontal non-operated wells in Midland and Ector Counties. See “Prospectus Summary—Recent Developments” on page 6. 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.

 

   

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 14 days during the period from April 2012 through August 2012, 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.

 

   

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 87% 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.

 

   

Pursue strategic acquisitions with exceptional resource potential. We have a proven history of acquiring leasehold positions in the Permian Basin that 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. After giving effect to this offering and the use of proceeds from this offering to repay the outstanding borrowings under our revolving credit facility, we will have $90.0 million of available borrowing capacity under such facility.

Our Strengths

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

 

   

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 September 21, 2012, the Baker Hughes Rig Count survey reported that there were 501 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 six months ended June 30, 2012 and the year ended December 31, 2011. 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.

 

   

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 our oil-weighted reserves that we believe provides attractive growth and return opportunities. As of August 31, 2012, after giving effect to the Transactions, we had 916 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 48 gross (43 net) vertical operated wells, which represent only approximately 5.1% of our identified potential vertical drilling locations on 40-acre spacing at August 31, 2012. We also believe that there are a significant number of horizontal locations that could be drilled on our acreage. In June 2012, we completed our first horizontal operated well, in which we have a 100% interest, in the Wolfcamp B interval in Upton County and currently expect to drill one additional gross (one net) horizontal operated well during 2012, also targeting the Wolfcamp B interval. Additionally, since June 2012, we have participated in three gross (one net) non-operated horizontal wells. Management currently estimates that EURs for our horizontal wells will be approximately 500 to 600 MBOE for lateral lengths averaging 7,500 feet. In addition, the liquids rich natural gas component of our inventory adds value with Btu content ranging from 1,225 MMBtu to 1,528 MMBtu and our June 2012 natural gas liquids yield was 118 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.

 

   

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 approximately 380,000 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.

 

   

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.

 

   

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. After giving effect to this offering and the use of proceeds from this offering to repay the outstanding borrowings under our revolving credit facility, we will have $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 Transactions.

Recent Developments

In June 2012, we completed our first horizontal operated well, in which we have a 100% interest, in the Wolfcamp B interval in Upton County and currently plan to drill one additional gross (one net) horizontal well in 2012, also targeting the Wolfcamp B interval. Our first horizontal operated well had a 3,842 foot lateral, a 24-hour initial production rate of 618 BOE/d and a 30-day average initial production rate of 486 BOE/d, of which 86% was oil. Based on the decline curve analysis of the current production, we anticipate that the EUR for this well will be in the range of 400 to 500 MBOE, of which 67% is expected to be oil. Additionally, since June 2012, we have participated in three gross (one net) horizontal non-operated wells. One of these is in Midland County and was completed in the Wolfcamp B interval with a 3,733 foot lateral and a 7-day average initial production rate as reported to us by the operator of 477 BOE/d, of which 89% was oil. During its initial production period, the well showed a production rate and pressures similar to those of our first horizontal operated well. We also participated in a horizontal non-operated well in Ector County targeting the Cline interval, which was completed in September 2012 with a 3,968 foot lateral and an average production rate as reported to us by the operator of 240 BOE/d measured on artificial lift over the last nine days of its initial 19 producing dates, of which 86% was oil. Finally, we participated in a horizontal non-operated well in Ector County, which was completed in August 2012 in the Clearfork interval with a 4,635 foot lateral and a 30-day initial production rate as reported to us by the operator of 58 BOE/d, of which 79% was oil.

Risk Factors

Investing in our common stock involves risks that include the speculative nature of oil and natural gas exploration, competition, volatile oil and natural gas prices and other material factors. You should read carefully the section of this prospectus entitled “Risk Factors” beginning on page 18 for an explanation of these risks before investing in our common stock. In particular, the following considerations may offset our competitive strengths or have a negative effect on our strategy or operating activities, which could cause a decrease in the price of our common stock and a loss of all or part of your investment:

 

   

Our business is difficult to evaluate because of our limited operating history.

 

 

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Difficulties managing the growth of our business may adversely affect our financial condition and results of operations.

 

   

Failure to develop our undeveloped acreage could adversely affect our future cash flow and income.

 

   

Our exploration and development operations require substantial capital that we may be unable to obtain, which could lead to a loss of properties and a decline in our reserves.

 

   

Our future success depends on our ability to find, develop or acquire additional oil and natural gas reserves.

 

   

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

 

   

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 values of our reserves.

 

   

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

 

   

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 limit our access to suitable markets for the oil and natural gas we produce.

 

   

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

 

   

Any failure by us to comply with applicable environmental laws and regulations, including those relating to hydraulic fracturing, could result in governmental authorities taking actions that adversely affect our operations and financial condition.

 

   

Our operations are subject to operational hazards for which we may not be adequately insured.

 

   

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

 

   

Our largest stockholder controls a significant percentage of our common stock and its interests may conflict with yours.

For a discussion of other considerations that could negatively affect us, see “Risk Factors” beginning on page 18 and “Cautionary Note Regarding Forward-Looking Statements” on page 45 of this prospectus.

The Transactions

On May 7, 2012, we entered into an agreement with Gulfport in which Gulfport agreed to sell to us all of its oil and natural gas properties in the Permian Basin in exchange for (i) 7,914,036 shares of our common stock, which will represent 35% of our outstanding common stock immediately prior to the closing of this offering and (ii) approximately $63.6 million in the form of a non-interest bearing promissory note, which we refer to as the Gulfport transaction note, that will be repaid in full upon the closing of this offering with a portion of the net proceeds from this offering. We are the operator of the acreage to be acquired by us from Gulfport. 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

 

 

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obligations, in each case as of the closing date of the transaction. If the closing date for the transaction had been September 30, 2012, based on preliminary estimates we believe that we would have owed Gulfport approximately $16.0 million for this post-closing adjustment. 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. In connection with this transaction, we will grant Gulfport the right, for so long as Gulfport beneficially owns more than 10% of our outstanding common stock, to designate one individual as a nominee to serve on our board of directors. We will also grant Gulfport certain demand and “piggyback” registration rights obligating us to register with the SEC the shares of our common stock owned by Gulfport. For more information regarding the Gulfport transaction, see “Management—Our Board of Directors and Committees,” “Related Party Transactions—Gulfport Transaction and Investor Rights Agreement” and “Shares Eligible for Future Sale—Registration Rights” beginning on pages 118, 134 and 146, respectively, of this prospectus.

In addition, our equity sponsor, Wexford, has agreed to cause all of the outstanding equity interests in Windsor UT LLC, or Windsor UT, to be contributed to Windsor Permian before the completion of the Gulfport transaction described above. Windsor UT was formed in April 2010 and acquired 4,978 gross (2,489 net) acres in the Permian Basin, of which we are the operator. The other 2,489 net acres are owned by Gulfport and will be transferred to us in the Gulfport transaction. Six wells have been drilled on this acreage as of August 31, 2012, which acreage contains 118 of our identified potential vertical drilling locations based on 40-acre spacing.

We refer to Gulfport’s sale of properties to us as the Gulfport transaction and we refer to the Gulfport transaction together with the contribution to Windsor Permian of all the equity interests in Windsor UT as the Transactions.

Our Equity Sponsor

We were formed by our equity sponsor, Wexford Capital LP, or Wexford, which is a Greenwich, Connecticut-based SEC-registered investment advisor with over $5.5 billion under management as of December 31, 2011. Wexford has made public and private equity investments in many different sectors and has particular expertise in the energy and natural resources sector. Upon completion of this offering, assuming Wexford or its affiliates make no additional purchases of our common stock, Wexford will beneficially own approximately 41.9% of our common stock (approximately 39.7% if the underwriters’ option to purchase additional shares is exercised in full). In addition, Wexford has indicated that it or one or more of its affiliates may purchase in this offering up to $30.0 million, or up to approximately 1,666,667 shares (based on the midpoint of the price range set forth on the cover page of this prospectus), of our common stock at the same price as the price to the public, in which case Wexford or its affiliates will beneficially own, upon completion of the offering, approximately 46.6% of our common stock (or approximately 44.2% if the underwriters’ option to purchase additional shares is exercised in full). The underwriters will not receive any underwriting discounts or commissions on any shares sold to Wexford or its affiliates. As a result, Wexford will continue to be able to exercise significant control over all matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. Prior to the closing of this offering, we will enter into an advisory services agreement with Wexford under which Wexford will provide us with financial and strategic advisory services related to our business. We are also party to certain other agreements with Wexford and its affiliates. For a description of the advisory services agreement and other agreements with Wexford and its affiliates, see “Related Party Transactions” beginning on page 134. Although our management believes that the terms of these related party agreements are reasonable, it is possible that we could have negotiated more favorable terms for such transactions with unrelated third parties. The existence of these related party agreements may give Wexford the ability to further influence and maintain control over many matters affecting us.

 

 

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Our History

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. All of our historical assets, operations and results described in this prospectus are those of Windsor Permian LLC, or Windsor Permian. Windsor Permian is a wholly-owned subsidiary of Diamondback Energy LLC, which is an entity controlled by our equity sponsor, Wexford. Prior to the effectiveness of the registration statement of which this prospectus is a part, Wexford will cause Diamondback Energy LLC to be merged with and into Diamondback Energy, Inc. and Diamondback Energy, Inc. will continue as the surviving entity. Immediately after the merger and prior to the effectiveness of the registration statement of which this prospectus is a part, Gulfport will complete the Gulfport transaction. Upon completion of these Transactions, Wexford and Gulfport will beneficially own 65% and 35%, respectively, of our outstanding common stock. Upon completion of the offering, assuming Wexford or its affiliates make no additional purchases of our common stock, Wexford and Gulfport will beneficially own approximately 41.9% and 22.5%, respectively, of our common stock (approximately 39.7% and 21.4%, respectively, if the underwriters’ option to purchase additional shares is exercised in full). Assuming Wexford or its affiliates purchase $30.0 million, or 1,666,667 shares (based on the midpoint of the price range set forth on the cover page of this prospectus), of our common stock in the offering, Wexford will beneficially own, upon completion of the offering, approximately 46.6% of our common stock (or approximately 44.2% if the underwriters’ option to purchase additional shares is exercised in full).

As of April 30, 2012, Windsor Permian held a 22% interest in Bison Drilling and Field Services LLC, or Bison, and a 33% interest in Muskie Holdings LLC, or Muskie. Bison owns drilling rigs and various oil and natural gas well servicing equipment and performs drilling and field services for us. Muskie owns certain assets, real estate and rights in a lease for land that is prospective for oil and natural gas fracture grade sand. 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 of $0.8 million and $1.5 million attributable to Bison in our consolidated statements of operations during 2010 and the first quarter of 2011, respectively. Muskie was formed in 2011, and we recorded a loss from equity method investments of $7,017 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 54 and 134, respectively, of this prospectus and Note 5 to our consolidated financial statements appearing elsewhere in this prospectus.

 

 

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The following organizational charts illustrate (a) our pre-offering organizational structure and (b) our organizational structure after giving effect to the Transactions and the offering:

 

LOGO

 

 

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Emerging Growth Company

We are an “emerging growth company” within the meaning of the federal securities laws. For as long as we are an emerging growth company, we will not be required to comply with the 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, the reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements and the 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. For a description of the qualifications and other requirements applicable to emerging growth companies and certain elections that we have made due to our status as an emerging growth company, see “Risk Factors—Risks Related to this Offering and our Common Stock – 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” on page 41 of this prospectus.

Our Offices

Our principal executive offices are located at 500 West Texas, Suite 1225, Midland, Texas, and our telephone number at that address is (432) 221-7400. We also lease additional office space in Midland and in Oklahoma City, Oklahoma. Our website address is www.diamondbackenergy.com. Information contained on our website does not constitute part of this prospectus. Except as otherwise indicated or required by the context, all references in this prospectus to “Diamondback,” the “Company,” “we,” “us” or “our” relate to Diamondback Energy, Inc., Windsor Permian LLC and its consolidated subsidiaries.

 

 

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The Offering

 

Common stock offered by us

12,500,000 shares (14,375,000 shares if the underwriters’ option to purchase additional shares is exercised in full)

 

Common stock to be outstanding immediately after completion of this offering

35,111,532 shares (36,986,532 shares if the underwriters’ option to purchase additional shares is exercised in full)

 

Option to purchase additional shares

We have granted the underwriters a 30-day option to purchase up to an aggregate of 1,875,000 additional shares of our common stock.

 

Use of proceeds

We expect to receive approximately $208.5 million of net proceeds from the sale of the common stock offered by us, based upon the assumed initial public offering price of $18.00 per share (the midpoint of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts and estimated offering expenses (or approximately $240.1 million if the underwriters’ option to purchase additional shares is exercised in full). At the closing of this offering, we will use $100.0 million of the net proceeds to repay the outstanding borrowings under our revolving credit facility, approximately $63.6 million to repay the Gulfport transaction note, $30.0 million to repay outstanding borrowings under our subordinated note with an affiliate of Wexford and approximately $8.4 million to settle the existing crude oil swaps. The remaining net proceeds of approximately $6.5 million (or approximately $38.1 million if the underwriters’ option to purchase additional shares is exercised in full), will be used 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 the post-closing cash adjustment payable to Gulfport under the terms of the Gulfport transaction. In the event that Wexford or its affiliates purchase $30.0 million of shares of common stock in this offering, then our net proceeds will increase by approximately $2.0 million. See “Use of Proceeds” on page 46 of this prospectus.

 

Conflicts of interest

Affiliates of Wells Fargo Securities, LLC are lenders under our revolving credit facility and, accordingly, will receive a substantial portion of the net proceeds from this offering as a result of the repayment of the outstanding borrowings under our revolving credit facility.

 

 

Because affiliates of Wells Fargo Securities, LLC are lenders under our revolving credit facility and will receive more than 5% of the net proceeds of this offering due to the repayment of a portion of the revolving credit facility, this offering will be conducted in accordance with Rule 5121 of the Financial Industry Regulatory Authority, Inc., which requires, among other things, that a “qualified independent underwriter” has participated in the preparation of, and has exercised the usual standards of “due diligence” with respect to, the registration

 

 

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statement and this prospectus. Credit Suisse Securities (USA) LLC has agreed to act as qualified independent underwriter for this offering. Please read “Use of Proceeds” and “Underwriting (Conflicts of Interest)” beginning on pages 46 and 151, respectively.

 

Dividend policy

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.

 

Directed Share Program

The underwriters have reserved for sale at the initial public offering price up to 5% of the common stock being offered by this prospectus for sale to our employees, executive officers, directors, business associates and related persons who have expressed an interest in purchasing common stock in the offering. We do not know if these persons will choose to purchase all or any portion of these reserved shares, but any purchases they do make will reduce the number of shares available to the general public. Please read “Underwriting (Conflicts of Interest)” beginning on page 151.

 

NASDAQ Global Market symbol

“FANG”

 

Risk Factors

You should carefully read and consider the information beginning on page 18 of this prospectus set forth under the heading “Risk Factors” and all other information set forth in this prospectus before deciding to invest in our common stock.

Except as otherwise indicated, all information contained in this prospectus:

 

   

assumes the underwriters do not exercise their over-allotment option; and

 

   

excludes 2,500,000 shares of common stock reserved for issuance under our equity incentive plan, including, based on an assumed public offering price of $18.00 per share (which is the midpoint of the range set forth on the cover of this prospectus):

 

   

272,219 restricted stock units to be issued to certain employees following the closing of this offering under the terms of their employment agreements, of which 66,666 will be vested on the closing date of this offering;

 

   

33,330 restricted stock units to be issued to our non-employee directors following the closing of this offering as part of their director compensation, of which 11,110 will be vested on the closing date of this offering; and

 

   

options to purchase 850,000 shares of our common stock to be granted to certain employees following the closing of this offering under the terms of their employment agreements, of which options to purchase 200,000 shares will be vested on the closing date of this offering.

 

 

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Summary Consolidated Historical and Pro Forma Financial Data

The following table sets forth our summary historical consolidated financial data as of and for each of the periods indicated. The summary historical consolidated financial data as of December 31, 2011 and 2010 and for the years ended December 31, 2011, 2010 and 2009 are derived from our historical audited consolidated financial statements included elsewhere in this prospectus. The summary historical consolidated balance sheet data as of December 31, 2009 are derived from our audited consolidated balance sheet as of that date, which is not included in this prospectus. The summary historical consolidated financial data as of June 30, 2012 and for the six months ended June 30, 2012 and 2011 are derived from our historical unaudited consolidated financial statements included elsewhere in this prospectus. The summary historical consolidated balance sheet data as of June 30, 2011 are derived from our unaudited consolidated balance sheet as of such date, which is not included in this prospectus. The unaudited pro forma financial data give effect to (a) the Transactions and (b) the distribution by Windsor Permian to its equity holder of its minority equity interests in Bison and Muskie. The unaudited pro forma statement of operations data for the year ended December 31, 2011 and the six months ended June 30, 2012 assume that these transactions occurred on January 1, 2011. The unaudited pro forma balance sheet data assume that the Transactions occurred on June 30, 2012. The unaudited pro forma C Corporation financial data presented give effect to income taxes assuming we operated as a taxable corporation since inception for historical columns and since January 1, 2011 for pro forma columns. Operating results for the years ended December 31, 2011, 2010 and 2009 and the six months ended June 30, 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,” “Selected Historical Consolidated Financial Data” and “Unaudited Pro Forma Condensed Consolidated Financial Statements” beginning on pages 61, 51 and 54, respectively, of this prospectus as well as our consolidated historical financial statements, the historical financial statements of Windsor UT and the statements of revenues and direct operating expenses of certain property interests of Gulfport and their respective related notes included elsewhere in this prospectus.

 

    Pro Forma     Historical  
    Six
Months
Ended
June 30,
2012
    Year Ended
December 31,

2011
    Six
Months
Ended
June 30,
    Year Ended December 31,  
        2012     2011               2011                2010     2009  

Statement of Operations Data:

         

Oil and natural gas revenues

  $ 46,572,620      $ 70,927,468      $
31,757,923
  
  $
22,038,729
  
  $ 47,180,802      $ 26,441,927      $ 12,716,011   

Other revenues

    —         
—  
  
    —          1,490,910        1,490,910        811,247        —     

Expenses:

             

Lease operating expense

    10,232,157        16,081,179        6,134,714        4,283,671        10,345,355        4,588,559        2,366,623   

Production taxes

    2,313,853        3,641,869        1,550,154        1,093,899        2,333,853        1,346,879        663,068   

Gathering and transportation

    146,320        201,828        146,320        85,944        201,828        105,870        42,091   

Oil and natural gas services

    —          —          —          1,732,892        1,732,892        811,247        —     

Depreciation, depletion and amortization

    15,287,686        23,661,538        10,235,730       
7,441,366
  
    15,402,826        8,145,143        3,215,891   

General and administrative

    2,884,277        3,522,231        2,815,051        1,421,313        3,603,479        3,051,627        5,062,618   

Asset retirement obligation accretion expense

    65,269        103,407        40,195        28,736        63,259        37,856        27,934   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses

    30,929,562        47,212,052        20,922,164        16,087,821        33,683,492        18,087,181        11,378,225   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income from operations

    15,643,058        23,715,416        10,835,759        7,441,818        14,988,220        9,165,993        1,337,786   

Other income (expense):

             

Interest income

    2,004        11,197        2,004        6,988        11,197        34,474        35,075   

Interest expense

    (2,053,706     (2,528,058     (2,053,706     (1,097,053     (2,528,058     (836,265     (10,938

Other income

    1,058,043        —          1,058,043        —          —          —          —     

Gain (loss) on derivative contracts

    5,164,987        (13,009,393     5,164,987        (28,181     (13,009,393     (147,983     (4,068,005

Loss from equity investment

    —          —          (66,654     —          (7,017     —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense), net

    4,171,328        (15,526,254     4,104,674        (1,118,246     (15,533,271     (949,774     (4,043,868
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

  $ 19,814,386      $ 8,189,162      $ 14,940,433      $ 6,323,572      $ (545,051   $ 8,216,219      $ (2,706,082
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

 

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    Pro Forma     Historical  
    Six
Months
Ended
June 30,
2012
    Year Ended
December 31,

2011
    Six Months Ended
June 30,
    Year Ended December 31,  
            2012             2011                   2011                2010     2009  

Pro Forma C Corporation Data:(1)

             

Net income (loss) before income taxes

  $ 19,814,386      $ 8,189,162      $ 14,940,433      $ 6,323,572      $ (545,051   $ 8,216,219      $ (2,706,082

Pro forma for income taxes

    7,063,829        2,919,436        —          —          —          —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Pro forma net income (loss)

  $ 12,750,557      $ 5,269,726      $ 14,940,433      $ 6,323,572      $ (545,051   $ 8,216,219      $ (2,706,082
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Pro forma income (loss) per common share — basic and diluted(2)

  $ 0.56      $ 0.23      $ 1.07        $ (0.04    
 

 

 

   

 

 

   

 

 

     

 

 

     

Weighted average pro forma shares outstanding — basic and diluted(2)

    22,611,532        22,611,532        14,000,000          14,000,000       
 

 

 

   

 

 

   

 

 

     

 

 

     

Selected Cash Flow and Other Financial Data:

             

Net income (loss)

      $ 14,940,433      $ 6,323,572      $ (545,051   $ 8,216,219      $ (2,706,082

Depreciation, depletion and amortization

        10,235,730        7,943,855        15,905,315        8,145,143        3,215,891   

Other non-cash items

        (4,273,541     177,309        13,844,010        344,461        4,108,464   

Change in operating assets and liabilities

        1,406,699        (925,350     1,179,920        (11,529,999     (1,916,707
     

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

      $ 22,309,321      $ 13,519,386      $ 30,384,194      $ 5,175,824      $ 2,701,566   
     

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

      $ (59,382,142   $ (38,363,561   $ (76,314,042   $ (53,134,641   $ (32,149,617

Net cash provided by financing activities

      $ 32,337,149      $ 23,292,499      $ 48,642,492      $ 49,618,254      $ 23,849,250   
                               
          Pro Forma     Historical  
          As of
June 30,
2012
    As of June 30,     As of December 31,  
                2012             2011         2011     2010     2009  

Balance sheet data:

             

Cash and cash equivalents

  

  $ 2,341,466      $ 2,066,717      $ 2,538,068      $ 6,802,389      $ 4,089,745      $ 2,430,308   

Other current assets

  

    23,267,333        23,197,048        23,855,341        24,130,450        20,947,659        2,263,097   

Oil and gas properties, net — using full cost method of accounting

   

    500,287,366        254,189,321        164,635,560        206,342,604        135,782,510        89,777,517   

Well equipment to be used in development of oil and gas properties

   

    —          —          —          —          —          5,413,310   

Other property and equipment, net

  

    1,540,452        1,540,452        3,435,130        684,015        11,059,220        105,564   

Other assets

  

    1,997,772        1,997,772        12,286,037        11,524,427        637,562        82,813   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total assets

  

  $ 529,434,389      $ 282,991,310      $ 206,750,136      $ 249,483,885      $ 172,516,696      $ 100,072,609   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Current liabilities

  

  $ 124,014,934      $ 51,806,938      $ 23,996,533      $ 42,418,305      $ 20,010,276      $ 13,972,080   

Note payable-long term

  

   
338,560
  
    338,560        —          —          —          —     

Note payable-credit facility-long term

  

    90,000,000        90,000,000        68,400,000        85,000,000        44,766,687        —     

Note payable-related party-long term

  

   
14,109,782
  
    14,109,782        —          —          —          —     

Derivative contracts-long term

  

    1,666,639        1,666,639        1,498,517        6,138,573        1,373,864        1,416,431   

Asset retirement obligations

  

    1,899,835        1,195,662        893,471        1,079,725        727,826        481,887   

Deferred income taxes

  

    56,269,454        —          —          —          —          —     

Member’s/stockholders’ equity

  

    241,135,185        123,873,729        111,961,615        114,847,282        105,638,043        84,202,211   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total liabilities and member’s/stockholders’ equity

   

  $ 529,434,389      $ 282,991,310      $ 206,750,136      $ 249,483,885      $ 172,516,696      $ 100,072,609   
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

 

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Index to Financial Statements
     Pro Forma      Historical  
     Six
Months
Ended
June 30,
2012
     Year Ended
December 31,
2011
     Six Months Ended June 30,      Year Ended December 31,  
               2012              2011          2011      2010      2009  

Other financial data:

                    

Adjusted EBITDA(3)

   $ 32,638,281       $ 48,538,337       $ 22,687,298       $ 15,421,397       $ 31,505,264       $ 17,383,466       $ 4,616,686   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(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 for the historical periods to give effect to income taxes assuming the earnings at Windsor Permian LLC had been subject to federal income tax as a subchapter C corporation since inception. If the earnings at Windsor Permian LLC had been subject to federal income tax as a subchapter C corporation since inception, we would have incurred net operating losses for income tax purposes in each period. 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 historical pro forma basic and diluted income (loss) per share has been presented for the latest fiscal year and interim period on the basis of the aggregate number of shares attributable to Windsor Permian LLC to be issued to DB Holdings in connection with the merger of Diamondback Energy LLC with and into Diamondback Energy, Inc.
(3) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss), see “Selected Historical Consolidated Financial Data” beginning on page 51 of this prospectus.

 

 

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Summary Historical and Pro Forma Reserve Data

The following table sets forth estimates of our net proved oil and natural gas reserves as of December 31, 2011 on a historical basis and on a pro forma basis after giving effect to the Transactions as if they had occurred as of December 31, 2011. Our historical reserves and the historical reserves attributable to the Windsor UT properties and the properties subject to the Gulfport transaction have been prepared in each case as of December 31, 2011 by Ryder Scott, an independent petroleum engineering firm, in accordance with SEC rules and regulations. Copies of these reserve reports are attached to this prospectus as Appendices B, C and D. You should also refer to “Risk Factors,”Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business—Oil and Gas Data—Proved Reserves,” “Business—Oil and Gas Production Prices and Production Costs—Production and Price History” beginning on pages 18, 61, 98 and 102, respectively, of this prospectus, our audited consolidated financial statements and notes thereto and our unaudited pro forma financial statements and notes thereto included in this prospectus in evaluating the material presented below.

 

     Pro Forma     Historical  
     December 31, 2011     December 31, 2011  

Estimated proved developed reserves:

    

Oil (Bbls)

     6,046,099        3,805,291   

Natural gas (Mcf)

     8,335,945        5,186,941   

Natural gas liquids (Bbls)

     1,969,710        1,233,318   

Total (BOE)

     9,405,133        5,903,099   

Estimated proved undeveloped reserves:

    

Oil (Bbls)

     20,140,377        12,911,578   

Natural gas (Mcf)

     24,261,522        14,431,926   

Natural gas liquids (Bbls)

     5,870,849        3,529,955   

Total (BOE)

     30,054,813        18,846,854   

Estimated Net Proved Reserves:

    

Oil (Bbls)

     26,186,476        16,716,869   

Natural gas (Mcf)

     32,597,467        19,618,867   

Natural gas liquids (Bbls)

     7,840,559        4,763,273   

Total (BOE)(1)

     39,459,946        24,749,953   

Percent proved developed

     23.8     23.9

 

(1) Estimates of reserves as of December 31, 2011 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 period ended December 31, 2011, in accordance with revised SEC guidelines applicable to reserves estimates as of the end of 2011. 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. 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.

 

 

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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 effectiveness of the registration statement of which this prospectus is a part, 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 $150.0 million to $160.0 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.

 

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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 August 31, 2012, after giving effect to the Transactions, we drilled a total of 167 gross wells and participated in an additional 16 gross non-operated wells, of which 171 wells were completed as producing wells and 12 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 August 31, 2012, after giving effect to the Transactions, we had 916 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 303 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 201 net acres expiring in 2012, 222 net acres expiring in 2013, 2,065 net acres expiring in 2014, 17,766 net acres expiring in 2015 and 6,893 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

 

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Index to Financial Statements

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.

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:

 

   

the domestic and foreign supply of oil and natural gas;

 

   

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

 

   

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

 

   

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

 

   

the price of foreign imports;

 

   

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

 

   

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

 

   

speculative trading in crude oil and natural gas derivative contracts;

 

   

the level of consumer product demand;

 

   

weather conditions and other natural disasters;

 

   

risks associated with operating drilling rigs;

 

   

technological advances affecting energy consumption;

 

   

domestic and foreign governmental regulations and taxes;

 

   

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

 

   

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

 

   

the price and availability of alternative fuels; and

 

   

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 August 31, 2012, the West Texas Intermediate posted price for crude oil was $96.47 per Bbl and the Henry Hub spot market price of natural gas was $2.72 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial

 

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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.

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 fixed price of $78.50 per barrel for 2012 and $80.55 per barrel 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. 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 $10.4 million at June 30, 2012) and receivables from purchasers of our oil and natural gas production (approximately $4.8 million at June 30, 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.

 

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We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the six months ended June 30, 2012, three purchasers accounted for more than 10% of our revenue: Plains Marketing, L.P. (63%); Andrews Oil Buyers, Inc. (13%); and Occidental Energy Marketing, Inc. (12%). 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%) and DCP Midstream, LP (15%). 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 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 $24.22 and $26.72 for the six months ended June 30, 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 six months ended June 30, 2012 and 2011 was $10.0 million and $7.3 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 six months ended June 30, 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 83 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,

 

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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 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.

 

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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 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 six months ended June 30, 2012, three purchasers accounted for more than 10% of our revenue: Plains Marketing, L.P. (63%); Andrews Oil Buyers, Inc. (13%); and Occidental Energy Marketing, Inc. (12%). 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%) and DCP Midstream, LP (15%). 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),

 

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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 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

 

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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 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

 

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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 106 and 110, respectively, of this prospectus for a description of the laws and regulations that affect us.

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.

 

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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 (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

 

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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 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

 

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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.

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

 

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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 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.

 

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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, assuming Wexford or its affiliates make no additional purchases of our common stock, Wexford will beneficially own approximately 41.9% of our common stock, or 39.7% if the underwriters exercise in full their option to purchase additional shares. Assuming Wexford or its affiliates purchase $30.0 million, or 1,666,667 shares (based on the midpoint of the price range set forth on the cover page of this prospectus), of our common stock in the offering, Wexford will beneficially own, upon completion of the offering, approximately 46.6% of our common stock (or approximately 44.2% if the underwriters’ option to purchase additional shares is exercised in full). See “Principal Stockholders” beginning on page 140 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:

 

   

unusual or unexpected geological formations;

 

   

loss of drilling fluid circulation;

 

   

title problems;

 

   

facility or equipment malfunctions;

 

   

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.

 

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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 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

 

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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 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.

 

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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.

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.

 

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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 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;

 

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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.

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

 

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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 September 30, 2012, the weighted average interest rate on outstanding borrowings under our revolving credit facility was 3.74%. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.

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, assuming Wexford or its affiliates make no additional purchases of our common stock, Wexford and Gulfport will beneficially own approximately 41.9% and 22.5%, respectively, of

 

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our common stock, or 39.7% and 21.4%, respectively, if the underwriters exercise their option to purchase additional shares in full. Assuming Wexford or its affiliates purchase $30.0 million, or 1,666,667 shares (based on the midpoint of the price range set forth on the cover page of this prospectus), of our common stock in the offering, Wexford will beneficially own, upon completion of the offering, approximately 46.6% of our common stock (or approximately 44.2% if the underwriters’ option to purchase additional shares is exercised in full). See “Principal Stockholders” beginning on page 140 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.

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 134 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

 

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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 39 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 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 36 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.

 

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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.”

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 Saleon page 145 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

 

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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.

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 $5.22 per share, representing the difference between our net tangible book value per share as of June 30, 2012 after giving effect to this offering and an assumed initial public offering price of $18.00 (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 $18.00 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 $0.33, and increase (decrease) the dilution to new investors by $0.67, 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 49 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

 

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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;

 

   

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, 18, 61 and 90, 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 12,500,000 shares of common stock in this offering, assuming a public offering price of $18.00 per share (which is the midpoint of the range set forth on the cover of this prospectus), are estimated to be $208.5 million, after deducting underwriting discounts and commissions and estimated offering expenses. The net proceeds would be $240.1 million if the underwriters’ option to purchase additional shares is exercised in full. At the closing of this offering, we intend to use $100.0 million of the net proceeds to repay the outstanding borrowings under our revolving credit facility, approximately $63.6 million to repay the Gulfport transaction note, $30.0 million to repay the outstanding borrowings under our subordinated note with an affiliate of Wexford and approximately $8.4 million to settle the existing crude oil swaps 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 post-closing cash adjustment payable to Gulfport under the terms of the Gulfport transaction. Upon repayment of the outstanding borrowings under our revolving credit facility, we will have $90.0 million of borrowing capacity under that facility to further fund our exploration and development activities and for general corporate purposes. In the event that Wexford or its affiliates purchase $30.0 million of shares of common stock in this offering, then our net proceeds will increase by approximately $2.0 million.

All borrowings under our revolving credit facility are due and payable on October 15, 2014. As of September 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 effectiveness of the registration statement of which this prospectus is a part in connection with the Gulfport transaction, is due upon completion of this offering and does not bear interest unless it is not paid when due.

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 $45.0 million. On September 30, 2012, $30.0 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.

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 $11.7 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 June 30, 2012:

 

   

on an actual basis;

 

   

on a pro forma basis to give effect to (a) the issuance of 14,697,496 shares of our common stock to an affiliate of Wexford in the merger of Diamondback Energy LLC with and into Diamondback Energy, Inc., (b) the issuance of 7,914,036 shares of our common stock and the Gulfport transaction note to Gulfport in connection with the Gulfport transaction and (c) the Windsor UT contribution; 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 $18.00 per share (which is the midpoint of the range set forth on the cover of this prospectus), our receipt of an estimated $208.5 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 Proceedson page 46 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 61 and our consolidated financial statements and related notes appearing elsewhere in this prospectus.

 

     As of June 30, 2012  
     Actual(1)      Pro Forma     Pro Forma
As  Adjusted(2)
 
     (in thousands)  

Cash and cash equivalents

   $ 2,067       $ 2,342      $ 24,742 (4)
  

 

 

    

 

 

   

 

 

 

Debt:

       

Revolving credit facility

   $ 100,000       $ 100,000      $ —     

Note payable-Wexford(3)

     14,110         14,110        —     

Note payable-Gulfport

     —           63,590        —     

Note payable-other

     411         411        411   
  

 

 

    

 

 

   

 

 

 

Total debt

     114,521         178,111        411   

Member’s equity

     123,874         —          —     

Stockholders’ equity:

       

Common stock, par value $0.01; 100 shares authorized and 100 shares issued and outstanding actual; 100,000,000 shares authorized and 22,611,532 shares issued and outstanding pro forma; and 100,000,000 shares authorized and 35,111,532 shares issued and outstanding pro forma as adjusted

     —           226        351   

Additional paid-in capital

     —           280,450        488,825   

Accumulated deficit(5)

     —           (39,541     (39,541
  

 

 

    

 

 

   

 

 

 

Total stockholders’ equity

     —           241,135        449,635   
  

 

 

    

 

 

   

 

 

 

Total capitalization

   $ 238,395       $ 419,246      $ 450,046  
  

 

 

    

 

 

   

 

 

 

 

(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 effectiveness of the registration statement of which this prospectus is a part, Windsor Permian LLC will become our wholly-owned subsidiary.
(2) A $1.00 increase (decrease) in the assumed initial public offering price of $18.00 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 $11.7 million, 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 September 30, 2012, long term debt was $130.4 million, which consists primarily of $30.0 million in borrowings under our subordinated note with an affiliate of Wexford and $100.0 million in borrowings under our revolving credit facility.

 

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(4) Does not reflect the repayment of an additional $15.9 million in borrowings under our subordinated note with an affiliate of Wexford borrowed subsequent to June 30, 2012, which repayment will reduce cash and cash equivalents. In the event that Wexford or its affiliates purchase $30.0 million of shares of common stock in this offering, then our cash and cash equivalents will increase by approximately $2.0 million. See “Use of Proceeds” on page 46 of this prospectus.
(5) Upon completion of the merger of Diamondback Energy LLC with and into Diamondback Energy, Inc. and the Windsor UT contributions, 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 June 30, 2012, a net deferred tax liability of approximately $39.5 million will be recognized with a corresponding charge to earnings.

 

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DILUTION

Our reported net tangible book value as of June 30, 2012 was $239.1 million, or $10.58 per share, based upon shares outstanding as of that date after giving pro forma effect to (a) the merger of Diamondback Energy LLC with and into Diamondback Energy, Inc., (b) the Gulfport transaction and (c) the Windsor UT contribution. 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 12,500,000 shares of common stock offered in this offering at an estimated initial public offering price of $18.00 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 June 30, 2012 would have been approximately $450.0 million, or $12.78 per share, after giving pro forma effect to (a) the merger of Diamondback Energy LLC with and into Diamondback Energy, Inc. (b) to the Gulfport transaction and (c) the Windsor UT contribution. This represents an immediate increase in net tangible book value of $2.20 per share to our existing stockholders and an immediate dilution of $5.22 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

      $ 18.00   

Pro forma net tangible book value per share as of June 30, 2012

   $ 10.58      

Increase per share attributable to new investors

   $ 2.20      
  

 

 

    

As adjusted net tangible book value per share after the offering

      $ 12.78   
     

 

 

 

Dilution per share to new investors

      $ 5.22   
     

 

 

 

A $1.00 increase (decrease) in the assumed initial public offering price of $18.00 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 per share after the offering by $0.33, and increase (decrease) the dilution to new investors by $0.67, 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 June 30, 2012, after giving pro forma effect to the merger of Diamondback Energy LLC with and into Diamondback Energy, Inc., the Gulfport transaction and the Windsor UT contribution, 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 the closing of this offering, and by the new investors at the assumed initial public offering price of $18.00 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

     22,611,532         64.4   $ 357,758,649         61.4   $ 15.82   

New investors

     12,500,000         35.6     225,000,000         38.6     18.00   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Total

     35,111,532         100.0   $ 582,758,649         100.0   $ 16.60   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

If the underwriters’ option to purchase additional shares is exercised in full, the number of shares held by new investors will be increased to 14,375,000, or approximately 38.9% of the total number of shares of common stock.

 

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The data in the table excludes 2,500,000 shares of common stock reserved for issuance under our equity incentive plan, including, based on an assumed public offering price of $18.00 per share (which is the midpoint of the range set forth on the cover of this prospectus):

 

   

272,219 restricted stock units to be issued to certain employees following the closing of this offering under the terms of their employment agreements, of which 66,666 will be vested on the closing date of this offering;

 

   

33,330 restricted stock units to be issued to our non-employee directors following the closing of this offering as part of their director compensation, of which 11,110 will be vested on the closing date of this offering; and

 

   

options to purchase 850,000 shares of our common stock to be granted to certain employees following the closing of this offering under the terms of their employment agreements, of which options to purchase 200,000 shares will be vested on the closing date of this offering.

 

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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 June 30, 2012 and for the six months ended June 30, 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 June 30, 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 six months ended June 30, 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 61 and our historical consolidated financial statements and related notes included elsewhere in this prospectus.

 

    Six Months
Ended
June 30,
    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

  $ 31,757,923      $ 22,038,729      $ 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

    6,134,714        4,283,671        10,345,355        4,588,559        2,366,623        3,375,419        25,684   

Production taxes

    1,550,154        1,093,899        2,333,853        1,346,879        663,068        1,008,991        136,077   

Gathering and transportation

    146,320        85,944        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

    10,235,730        7,441,366        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

    2,815,051        1,421,313        3,603,479        3,051,627        5,062,618        5,459,874        6,609   

Asset retirement obligation accretion expense

    40,195        28,736        63,259        37,856        27,934        23,569        514   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total expenses

    20,922,164        16,087,821        33,683,492        18,087,181        11,378,225        103,285,071        309,587   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from operations

    10,835,759        7,441,818        14,988,220        9,165,993        1,337,786        (85,046,379     268,749   

Other income (expense):

             

Interest income

    2,004        6,988        11,197        34,474        35,075        625,086        23,581   

Interest expense

    (2,053,706     (1,097,053     (2,528,058     (836,265     (10,938     —          —     

Other income

    1,058,043        —          —          —          —          —          —     

Gain (loss) on derivative contracts

    5,164,987        (28,181     (13,009,393     (147,983     (4,068,005     (9,528,220     (4,791,587

Loss from equity investment

    (66,654     —          (7,017     —          —          —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense), net

    4,104,674        (1,118,246     (15,533,271     (949,774     (4,043,868     (8,903,134     (4,768,006
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

  $ 14,940,433      $ 6,323,572      $ (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

  $ 14,940,433      $ 6,323,572      $ (545,051   $ 8,216,219      $ (2,706,082   $ (93,949,513   $ (4,499,257

Pro forma for income taxes

    —          —          —          —          —          —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Pro forma net income (loss)

  $ 14,940,433      $ 6,323,572      $ (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)

  $ 1.07        $ (0.04        
 

 

 

     

 

 

         

Weighted average pro forma shares outstanding — basic and diluted(2)

    14,000,000          14,000,000           
 

 

 

     

 

 

         

 

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Index to Financial Statements
    Six Months Ended
June 30,
   
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)

  $ 14,940,433      $ 6,323,572      $ (545,051   $ 8,216,219      $ (2,706,082   $ (93,949,513   $ (4,499,257

Depreciation, depletion and amortization

    10,235,730        7,943,855        15,905,315        8,145,143        3,215,891        10,199,581        138,066   

Other non-cash items

    (4,273,541     177,309        13,844,010        344,461        4,108,464        92,716,019        4,792,101   

Change in operating assets and liabilities

    1,406,699        (925,350     1,179,920        (11,529,999     (1,916,707     3,076,317        (2,448,557
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net cash provided by (used in) operating activities

  $ 22,309,321      $ 13,519,386      $ 30,384,194      $ 5,175,824      $ 2,701,566      $ 12,042,404      $ (2,017,647
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

  $ (59,382,142   $ (38,363,561   $ (76,314,042   $ (53,134,641   $ (32,149,617   $ (84,196,562   $ (86,863,149

Net cash provided by financing activities

  $ 32,337,149      $ 23,292,499      $ 48,642,492      $ 49,618,254      $ 23,849,250      $ 80,182,600      $ 88,881,463   
    As of
June 30,
    As of December 31,  
    2012     2011     2011     2010     2009     2008     2007  

Balance sheet data:

             

Cash and cash equivalents

  $ 2,066,717      $ 2,538,068      $ 6,802,389      $ 4,089,745      $ 2,430,308      $ 8,029,109      $ 667   

Other current assets

    23,197,048        23,855,341        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

    254,189,321        164,635,560        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

    1,540,452        3,435,130        684,015        11,059,220        105,564        161,103        —     

Other assets

    1,997,772        12,286,037        11,524,427        637,562        82,813        —          —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total assets

  $ 282,991,310      $ 206,750,136      $ 249,483,885      $ 172,516,696      $ 100,072,609      $ 91,869,484      $ 85,865,400   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Current liabilities

  $ 51,806,938      $ 23,996,533      $ 42,418,305      $ 20,010,276      $ 13,972,080      $ 18,011,452      $ 126,757   

Note payable-long term

    338,560        —          —          —          —          —          —     

Note payable-credit facility-long term

    90,000,000        68,400,000        85,000,000        44,766,687        —          —          —     

Note payable-related party-long term

    14,109,782        —          —          —          —          —          —     

Derivative contracts-long term

    1,666,639        1,498,517        6,138,573        1,373,864        1,416,431        2,868,452        1,141,587   

Asset retirement obligations

    1,195,662        893,471        1,079,725        727,826        481,887        374,287        214,850   

Members’ equity

    123,873,729        111,961,615        114,847,282        105,638,043        84,202,211        70,615,293        84,382,206   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total liabilities and members’ equity

  $ 282,991,310      $ 206,750,136      $ 249,483,885      $ 172,516,696      $ 100,072,609      $ 91,869,484      $ 85,865,400   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    Six Months Ended
June 30,
    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)

  $ 22,687,298      $ 15,421,397      $ 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 since inception. If the earnings of Windsor Permian LLC had been subject to federal income tax as a subchapter C corporation since inception, we would have incurred net operating losses for income tax purposes in each period. 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 has been presented for the latest fiscal year and interim period on the basis of the aggregate number of shares attributable to Windsor Permian LLC to be issued to DB Holdings in connection with the merger of Diamondback Energy LLC with and into Diamondback Energy, Inc.
(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).

 

    Six
Months Ended
June 30,
    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)

  $ 14,940,433      $ 6,323,572      $ (545,051   $ 8,216,219      $ (2,706,082   $ (93,949,513   $ (4,499,257

Gain (loss) on derivative contracts

    (5,164,987     28,181        13,009,393        147,983        4,068,005        9,528,220        4,791,587   

Interest expense

    2,053,706        1,097,053        2,528,058        836,265        10,938        —          —     

Depreciation, depletion and amortization

    10,235,730        7,943,855        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

    582,221        —          544,290        —          —          —          —     

Asset retirement obligation accretion expense

    40,195        28,736        63,259        37,856        27,934        23,569        514   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $ 22,687,298      $ 15,421,397      $ 31,505,264      $ 17,383,466      $ 4,616,686      $ 8,966,087      $ 430,910   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

53


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Index to Financial Statements

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 occurred on June 30, 2012. The unaudited pro forma condensed consolidated statement of operations for the year ended December 31, 2011 and for the six months ended June 30, 2012 assumes that the Transactions and other described transactions occurred on January 1, 2011.

 

54


Table of Contents
Index to Financial Statements

Diamondback Energy, Inc.

Unaudited Pro Forma Condensed Consolidated Balance Sheet

June 30, 2012

 

     Windsor
Permian

Historical
     Windsor
UT

Historical
     Pro Forma
Adjustments
    Pro Forma  
Assets                           

Cash and cash equivalents

   $ 2,066,717       $ 274,749         —        $ 2,341,466   

Other current assets

     23,197,048         70,285         —          23,267,333   
  

 

 

    

 

 

    

 

 

   

 

 

 

Total current assets

     25,263,765         345,034         —          25,608,799   

Oil and natural gas properties, net using full cost method of accounting

     254,189,321         14,162,818         231,935,227 (a)      500,287,366   

Other property and equipment

     1,540,452         —           —          1,540,452   

Other assets

     1,997,772         —           —          1,997,772   
  

 

 

    

 

 

    

 

 

   

 

 

 

Total assets

   $ 282,991,310       $ 14,507,852       $ 231,935,227      $ 529,434,389   
  

 

 

    

 

 

    

 

 

   

 

 

 
Liabilities and Members’/Stockholders’
Equity
                          

Current liabilities

     51,806,938         132,864       $ 72,075,132 (a)    $ 124,014,934   

Note payable-long term

     338,560         —           —          338,560   

Note payable-credit facility-long term

     90,000,000         —           —          90,000,000   

Note payable-related party-long term

     14,109,782         —          
—  
  
    14,109,782   

Derivative contracts-long term

     1,666,639         —           —          1,666,639   

Asset retirement obligations

     1,195,662         25,167         679,006 (c)      1,899,835   

Deferred income taxes

     —           —           56,269,454 (e)      56,269,454   

Members’/stockholders’ equity

     123,873,729         14,349,821         102,911,635 (a)(e)      241,135,185   
  

 

 

    

 

 

    

 

 

   

 

 

 

Total liabilities and members’/stockholders’ equity

   $ 282,991,310       $ 14,507,852       $ 231,935,227      $ 529,434,389   
  

 

 

    

 

 

    

 

 

   

 

 

 

 

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

 

55


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Index to Financial Statements

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       $ —        $ 70,927,468   

Oil and natural gas services

     1,490,910        —           —           (1,490,910 )(b)      —     
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

Total revenues

     48,671,712        23,052,000         694,666         (1,490,910     70,927,468   

Costs and expenses:

            

Lease operating expenses

     10,345,355        5,484,000         251,824         —          16,081,179   

Production taxes

     2,333,853        1,276,000         32,016         —          3,641,869   

Gathering and transportation

     201,828        —           —           —          201,828   

Oil and natural gas services

     1,732,892        —           —           (1,732,892 )(b)      —     

Depreciation, depletion and amortization

     15,402,826        —           198,712         8,060,000 (d)      23,661,538   

General and administrative expenses

     3,603,479        —           37,044         (118,292     3,522,231   

Asset retirement obligation accretion expense

     63,259        —           1,255         38,893 (c)      103,407   
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

Total costs and expenses

     33,683,492        6,760,000         520,851         6,247,709        47,212,052   
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

Income from operations

     14,988,220        16,292,000         173,815         (7,738,619     23,715,416   

Other income (expense)

            

Interest income

     11,197        —           —           —          11,197   

Interest expense

     (2,528,058     —           —           —          (2,528,058

Loss on derivative contracts

     (13,009,393     —           —           —          (13,009,393

Loss from equity investment

     (7,017     —           —           7,017 (b)      —     
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

Total other expense, net

     (15,533,271     —           —           7,017        (15,526,254
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

Net income (loss)

   $ (545,051   $ 16,292,000       $ 173,815       $ (7,731,602   $ 8,189,162   
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

Pro forma income before income taxes

             $ 8,189,162   
            

 

 

 

Pro forma for income taxes(f)

               2,919,436   
            

 

 

 

Pro forma net income

             $ 5,269,726   
            

 

 

 

Pro forma income per common share — basic and diluted(g)

             $ 0.23   
            

 

 

 

Weighted average pro forma shares outstanding — basic and diluted(g)

               22,611,532   
            

 

 

 

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

 

56


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Index to Financial Statements

Diamondback Energy, Inc.

Unaudited Pro Forma Condensed Consolidated Statement of Operations

Six Months ended June 30, 2012

 

     Windsor
Permian

Historical
    Gulfport
Transaction

Historical
     Windsor UT
Historical
     Pro Forma
Adjustments
    Pro Forma  

Revenues:

            

Oil and natural gas revenues

   $ 31,757,923      $ 14,192,000       $ 622,697       $ —        $ 46,572,620   

Costs and expenses:

            

Lease operating expenses

     6,134,714        3,914,000         183,443         —          10,232,157   

Production taxes

     1,550,154        735,000         28,699         —          2,313,853   

Gathering and transportation

     146,320        —           —           —          146,320   

Depreciation, depletion and amortization

     10,235,730        —           179,956         4,872,000 (d)      15,287,686   

General and administrative expenses

     2,815,051        —           69,226         —          2,884,277   

Asset retirement obligation accretion expense

     40,195        —           900         24,174 (c)      65,269   
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

Total costs and expenses

     20,922,164        4,649,000         462,224         4,896,174        30,929,562   
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

Income from operations

     10,835,759        9,543,000         160,473         (4,896,174     15,643,058   

Other income (expense)

            

Interest income

     2,004        —           —           —          2,004   

Interest expense

     (2,053,706     —           —           —          (2,053,706

Other income

     1,058,043        —           —           —          1,058,043   

Gain on derivative contracts

     5,164,987        —           —           —          5,164,987   

Loss from equity investment

     (66,654     —           —           66,654 (b)      —     
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

Total other income (expense), net

     4,104,674        —           —           66,654        4,171,328   
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

Net income

   $ 14,940,433      $ 9,543,000       $ 160,473       $ (4,829,520   $ 19,814,386   
  

 

 

   

 

 

    

 

 

    

 

 

   

 

 

 

Pro forma income before income taxes

               19,814,386   
            

 

 

 

Pro forma for income taxes(f)

               7,063,829   
            

 

 

 

Pro forma net income

             $ 12,750,557   
            

 

 

 

Pro forma income per common share—basic and diluted(g)

             $ 0.56   
            

 

 

 

Weighted average pro forma shares outstanding—basic and diluted(g)

               22,611,532   
            

 

 

 

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

 

57


Table of Contents
Index to Financial Statements

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 Energy Corporation. The unaudited pro forma condensed consolidated balance sheet as of June 30, 2012 has been prepared as if the Transactions had taken place on June 30, 2012. The unaudited pro forma condensed consolidated statements of operations for the year ended December 31, 2011 and the six months ended June 30, 2012 assume 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 approximately $231.9 million for 7,914,036 shares of our common stock valued at the assumed initial public offering price of $18.00 per share (the midpoint of the range set forth in the prospectus), 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 aggregate consideration payable to Gulfport is subject to a post-closing cash adjustment which amount, when calculated at June 30, 2012 for purposes of these pro forma condensed consolidated financial statements only, was $8,485,082. The allocation of the purchase price to the assets acquired and the cash adjustment amount are preliminary and, therefore, subject to change.

 

(b) To record the effects of the distribution of minority equity interests in Bison and Muskie to Windsor Permian’s sole member which occurred on June 15, 2012.

 

(c) To record incremental asset retirement obligation and related accretion of discount 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:

 

     Six Months Ended
June 30, 2012
     Year Ended
December 31, 2011
 

Purchase accounting basis adjustment for Gulfport properties

   $ 1,596,000         2,685,000   

Using a larger quantity of reserves in the units of production computation

     3,276,000         5,375,000   
  

 

 

    

 

 

 

Total incremental depletion, depreciation and amortization

   $ 4,872,000       $ 8,060,000   
  

 

 

    

 

 

 

 

(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 of approximately $39.5 million. A corresponding charge to earnings has not been reflected in the pro forma Statement of Operations, as the charge is considered non-recurring. Also to record estimated net deferred tax liabilities resulting from the Gulfport transaction of approximately $16.7 million.

 

(f)

To record the effect of income taxes assuming earnings had been subject to federal income tax as a subchapter C corporation, effective January 1, 2011.

 

58


Table of Contents
Index to Financial Statements

Diamondback Energy, Inc.

Notes to Unaudited Pro Forma Condensed Consolidated

Financial Statements

 

 

(g) To report basic and diluted income 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 merger of Diamondback Energy LLC with and into Diamondback Energy, Inc. and the Windsor UT contribution.

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        21,663        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        19,620        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