6.30.13 10-Q
Table of Contents

  
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 
 
FORM 10-Q

 
ý
QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED June 30, 2013
OR
¨
TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
Commission File Number 001-35700
 
 
Diamondback Energy, Inc.
(Exact Name of Registrant As Specified in Its Charter)
 
 

Delaware
 
45-4502447
(State or Other Jurisdiction of
Incorporation or Organization)
 
(IRS Employer
Identification Number)
 
 
500 West Texas, Suite 1225
Midland, Texas
 
79701
(Address of Principal Executive Offices)
 
(Zip Code)
(432) 221-7400
(Registrant Telephone Number, Including Area Code)
 
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý    No  ¨

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
 
Smaller Reporting Company
 
¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  ý
As of July 24, 2013, 42,161,532 shares of the registrant’s common stock were outstanding.




DIAMONDBACK ENERGY, INC.
TABLE OF CONTENTS
 
 
 
Page
 
 
ITEM1.
 
 
 
 
 
 
 
 
 
 
 
ITEM 2.
 
ITEM 3.
 
ITEM 4.
 
 
 
ITEM 1.
 
ITEM 1A.
 
ITEM 2.
 
ITEM 3.
 
ITEM 4.
 
ITEM 5.
 
ITEM 6.
 
 
 
 
 
 
 







GLOSSARY OF OIL AND NATURAL GAS TERMS
The following is a description of the meanings of some of the oil and natural gas industry terms used throughout this report:
3-D seismic. Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.
Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
Bbls/d. Bbls per day.
BOE. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BOE/d. BOE per day.
Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.
Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.
Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Finding and Development Costs. Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.
Fracturing. The process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle with a specified interval.
MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.
MBOE. One thousand barrels of crude oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Mcf. Thousand cubic feet of natural gas.
Mcf/d. Mcf per day.
MMcf. Million cubic feet of natural gas.
Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.




Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.
PDP. Proved developed producing.
Play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.
Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
PUD. Proved undeveloped.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved reserves. The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
Recompletion. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Stratigraphic play. An oil or natural gas formation contained within an area created by permeability and porosity changes characteristic of the alternating rock layer that result from the sedimentation process.
Structural play. An oil or natural gas formation contained within an area created by earth movements that deform or rupture (such as folding or faulting) rock strata.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.





CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, or the Exchange Act. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this quarterly report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed in this quarterly report on Form 10–Q and detailed under Part II, Item 1A. Risk Factors in this report and our Annual Report on Form 10–K for the year ended December 31, 2012 could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted or implied in such forward-looking statements.

Forward-looking statements 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 forward-looking statements speak only as of the date of this quarterly report. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this quarterly report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.



Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Consolidated Balance Sheets
(Unaudited)


                                                                                                           
 
 
June 30,
 
December 31,
 
 
2013
 
2012
Assets
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
81,898,000

 
$
26,358,000

Accounts receivable:
 
 
 
 
Joint interest and other
 
7,347,000

 
5,959,000

Oil and natural gas sales
 
16,374,000

 
8,081,000

Related party
 
648,000

 
772,000

Inventories
 
6,271,000

 
6,195,000

Deferred income taxes
 

 
1,857,000

Derivative instruments
 
3,191,000

 

Prepaid expenses and other
 
807,000

 
1,053,000

Total current assets
 
116,536,000

 
50,275,000

 
 
 
 
 
Property and equipment
 
 
 
 
Oil and natural gas properties, based on the full cost method of accounting ($118,893,000 and $121,245,000 excluded from amortization at June 30, 2013 and December 31, 2012, respectively)
 
847,732,000

 
697,742,000

Other property and equipment
 
4,749,000

 
2,337,000

Accumulated depletion, depreciation, amortization and impairment
 
(171,309,000
)
 
(145,837,000
)
 
 
681,172,000

 
554,242,000

 
 
 
 
 
Other assets
 
931,000

 
2,184,000

Total assets
 
$
798,639,000

 
$
606,701,000

Liabilities and Stockholders’ Equity
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable trade
 
$
22,630,000

 
$
12,141,000

Accounts payable-related party
 
724,000

 
18,813,000

Accrued capital expenditures
 
50,042,000

 
29,397,000

Other accrued liabilities
 
16,065,000

 
10,649,000

Revenues and royalties payable
 
5,020,000

 
3,270,000

Derivative instruments
 
2,679,000

 
4,817,000

Deferred income taxes
 
182,000

 

Note payable-short term
 
145,000

 
145,000

Total current liabilities
 
97,487,000

 
79,232,000

 
 
 
 
 
Note payable–long term
 
121,000

 
193,000

Derivative instruments-long term
 

 
388,000

Asset retirement obligations-long term
 
2,324,000

 
2,125,000

Deferred income taxes-noncurrent
 
71,098,000

 
62,695,000

Total liabilities
 
171,030,000

 
144,633,000

Contingencies (Note 13)
 


 


Stockholders’ equity:
 
 
 
 
Common stock, $0.01 par value, 100,000,000 shares authorized, 42,161,532 issued and outstanding at June 30, 2013; 36,986,532 issued and outstanding at December 31, 2012
 
422,000

 
370,000

Additional paid-in capital
 
659,394,000

 
513,772,000

Accumulated deficit
 
(32,207,000
)
 
(52,074,000
)
Total stockholders’ equity
 
627,609,000

 
462,068,000

Total liabilities and stockholders’ equity
 
$
798,639,000

 
$
606,701,000

See accompanying notes to combined consolidated financial statements.

1

Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Combined Consolidated Statements of Operations
(Unaudited)


 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2013
 
2012
 
2013
 
2012
Revenues:
 
 
 
 
 
 
 
 
Oil sales
 
$
41,034,000

 
$
14,366,000

 
$
66,287,000

 
$
29,012,000

Natural gas sales
 
988,000

 
205,000

 
1,727,000

 
397,000

Natural gas sales - related party
 
680,000

 
106,000

 
1,092,000

 
261,000

Natural gas liquid sales
 
1,649,000

 
841,000

 
3,471,000

 
1,575,000

Natural gas liquid sales - related party
 
1,043,000

 
512,000

 
1,726,000

 
1,136,000

Total revenues
 
45,394,000

 
16,030,000

 
74,303,000

 
32,381,000

Costs and expenses:
 
 
 
 
 
 
 
 
Lease operating expenses
 
5,695,000

 
3,523,000

 
10,928,000

 
5,744,000

Lease operating expenses - related party
 
392,000

 
6,000

 
594,000

 
574,000

Production taxes
 
2,080,000

 
738,000

 
3,431,000

 
1,479,000

Production taxes - related party
 
116,000

 
44,000

 
192,000

 
100,000

Gathering and transportation
 
31,000

 
35,000

 
106,000

 
52,000

Gathering and transportation - related party
 
216,000

 
44,000

 
274,000

 
94,000

Depreciation, depletion and amortization
 
14,815,000

 
5,659,000

 
25,553,000

 
10,416,000

General and administrative expenses
 
2,355,000

 
1,005,000

 
4,540,000

 
1,480,000

General and administrative expenses - related party
 
266,000

 
648,000

 
552,000

 
1,357,000

Asset retirement obligation accretion expense
 
45,000

 
21,000

 
88,000

 
41,000

Total costs and expenses
 
26,011,000

 
11,723,000

 
46,258,000

 
21,337,000

Income from operations
 
19,383,000

 
4,307,000

 
28,045,000

 
11,044,000

Other income (expense)
 
 
 
 
 
 
 
 
Interest income
 

 
1,000

 

 
2,000

Interest expense
 
(535,000
)
 
(1,173,000
)
 
(1,020,000
)
 
(2,054,000
)
Other income - related party
 
388,000

 
586,000

 
777,000

 
1,011,000

Gain on derivative instruments, net
 
3,037,000

 
9,957,000

 
3,029,000

 
5,165,000

Loss from equity investment
 

 
(54,000
)
 

 
(67,000
)
Total other income, net
 
2,890,000

 
9,317,000

 
2,786,000

 
4,057,000

Income before income taxes
 
22,273,000

 
13,624,000

 
30,831,000

 
15,101,000

Provision for income taxes
 
 
 
 
 
 
 
 
Deferred income tax provision
 
7,802,000

 

 
10,964,000

 

Net income
 
$
14,471,000

 
$
13,624,000

 
$
19,867,000

 
$
15,101,000

 
 
 
 
 
 
 
 
 
Earnings per common share
 
 
 
 
 
 
 
 
Basic
 
$
0.37

 
 
 
$
0.52

 
 
Diluted
 
$
0.36

 
 
 
$
0.52

 
 
Weighted average common shares outstanding
 
 
 
 
 
 
 
 
Basic
 
39,402,282

 
 
 
38,237,149

 
 
Diluted
 
39,718,574

 
 
 
38,476,719

 
 
 
 
 
 
 
 
 
 
 
See accompanying notes to combined consolidated financial statements.


2

Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Combined Consolidated Statements of Operations - Continued
(Unaudited)

 
 
Three Months Ended
 
Six Months Ended
 
 
June 30, 2012
 
June 30, 2012
Pro forma information
 
 
 
 
Income before income taxes, as reported
 
$
13,624,000

 
$
15,101,000

Pro forma provision for income taxes
 
4,857,000

 
5,384,000

Pro forma net income
 
$
8,767,000

 
$
9,717,000

 
 
 
 
 
Pro forma earnings per common share - basic and diluted
 
$
0.60

 
$
0.66

Pro forma weighted average common shares outstanding - basic and diluted
 
14,697,496

 
14,697,496


See accompanying notes to combined consolidated financial statements.




3

Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Consolidated Statement of Stockholders Equity
(Unaudited)

 
 
Common Stock
 
Additional
 
Accumulated
 
 
 
 
Shares
Amount
 
Paid-in Capital
 
Deficit
 
Total
Balance December 31, 2012
 
36,986,532

$
370,000

 
$
513,772,000

 
$
(52,074,000
)
 
$
462,068,000

 
 
 
 
 
 
 
 
 
 
Stock-based compensation
 


 
1,183,000

 

 
1,183,000

Common shares issued in public offering, net of offering costs
 
5,175,000

52,000

 
144,439,000

 

 
144,491,000

Net income
 


 

 
19,867,000

 
19,867,000

Balance June 30, 2013
 
42,161,532

$
422,000

 
$
659,394,000

 
$
(32,207,000
)
 
$
627,609,000

 
 
 
 
 
 
 
 
 
 

See accompanying notes to combined consolidated financial statements.


4

Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Combined Consolidated Statements of Cash Flows
(Unaudited)

 
 
Six Months Ended June 30,
 
 
2013
 
2012
Cash flows from operating activities:
 
 
 
 
Net income
 
$
19,867,000

 
$
15,101,000

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
Provision for deferred income taxes
 
10,964,000

 

Asset retirement obligation accretion expense
 
88,000

 
41,000

Depreciation, depletion, and amortization
 
25,553,000

 
10,416,000

Amortization of debt issuance costs
 
318,000

 
212,000

Change in fair value of derivative instruments
 
(5,429,000
)
 
(5,165,000
)
Loss from equity investment
 

 
67,000

Equity-based compensation expense
 
936,000

 
582,000

Gain on sale of assets
 
(30,000
)
 
(10,000
)
Changes in operating assets and liabilities:
 
 
 
 
Accounts receivable
 
(12,185,000
)
 
(2,915,000
)
Accounts receivable-related party
 
5,110,000

 
7,111,000

Inventories
 
(96,000
)
 
181,000

Prepaid expenses and other
 
(1,517,000
)
 
(1,590,000
)
Accounts payable and accrued liabilities
 
4,543,000

 
2,058,000

Accounts payable and accrued liabilities-related party
 
(74,000
)
 
(1,484,000
)
Revenues and royalties payable
 
1,750,000

 
(349,000
)
Revenues and royalties payable-related party
 

 
(1,595,000
)
Net cash provided by operating activities
 
49,798,000

 
22,661,000

Cash flows from investing activities:
 
 
 
 
Additions to oil and natural gas properties
 
(108,977,000
)
 
(50,576,000
)
Additions to oil and natural gas properties-related party
 
(9,298,000
)
 
(4,629,000
)
Acquisition of Gulfport properties
 
(18,550,000
)
 

Purchase of other property and equipment
 
(1,615,000
)
 
(637,000
)
Proceeds from sale of property and equipment
 
54,000

 
10,000

Settlement of non-hedge derivative instruments
 
(289,000
)
 
(5,263,000
)
Receipt on derivative margins
 

 
1,479,000

Net cash used in investing activities
 
(138,675,000
)
 
(59,616,000
)
Cash flows from financing activities:
 
 
 
 
Proceeds from borrowings on credit facility
 
49,000,000

 
15,000,000

Repayment on credit facility
 
(49,000,000
)
 

Proceeds from note payable - related party
 

 
14,100,000

Debt issuance costs
 
(72,000
)
 
(42,000
)
Public offering costs
 
(447,000
)
 
(729,000
)
Proceeds from public offering
 
144,936,000

 

Contributions by members
 

 
4,008,000

Net cash provided by financing activities
 
144,417,000

 
32,337,000

Net increase (decrease) in cash and cash equivalents
 
55,540,000

 
(4,618,000
)
Cash and cash equivalents at beginning of period
 
26,358,000

 
6,959,000

Cash and cash equivalents at end of period
 
$
81,898,000

 
$
2,341,000


See accompanying notes to combined consolidated financial statements.

5

Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Combined Consolidated Statements of Cash Flows - Continued
(Unaudited)

 
 
Six Months Ended June 30,
 
 
2013
 
2012
Supplemental disclosure of cash flow information:
 
 
 
 
Interest paid, net of capitalized interest

$
383,000

 
$
876,000

Supplemental disclosure of non-cash transactions:
 
 
 
 
Asset retirement obligation incurred
 
$
111,000

 
$
95,000

Distribution of equity method investments
 
$

 
$
10,504,000

Note payable exchanged for equipment
 
$

 
$
411,000


See accompanying notes to combined consolidated financial statements.

6

Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Notes to Combined Consolidated Financial Statements
(Unaudited)


1.    DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION
Organization and Description of the Business
Diamondback Energy, Inc. (“Diamondback” or the “Company”) together with its subsidiaries, is an independent oil and 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. Diamondback was incorporated in Delaware on December 30, 2011, and did not conduct any material business operations until October 11, 2012 when Diamondback merged with its parent entity, Diamondback Energy LLC, with Diamondback continuing as the surviving entity (the “Merger”). Prior to the Merger, Diamondback Energy LLC was a holding company and did not conduct any material business operations other than its ownership of the Diamondback’s common stock and the membership interests in Diamondback O&G LLC (formerly known as Windsor Permian LLC, or “Windsor Permian”). As a result of the Merger, Windsor Permian became a wholly-owned subsidiary of Diamondback. Also on October 11, 2012, Wexford Capital LP (“Wexford”), our equity sponsor, caused all of the outstanding equity interests in Windsor UT LLC (“Windsor UT”) to be contributed to Windsor Permian prior to the Merger in a transaction referred to as the “Windsor UT Contribution”. The Windsor UT Contribution was treated as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests. We refer to the historical results of Windsor Permian and Windsor UT prior to October 11, 2012 as our “Predecessors”.
Immediately after the Merger on October 11, 2012, Diamondback acquired from Gulfport Energy Corporation (“Gulfport”) all of its oil and natural gas interests in the Permian Basin (the “Gulfport properties”) in exchange for shares of Diamondback common stock and a promissory note in a transaction referred to as the Gulfport transaction. The Gulfport transaction was treated as a business combination accounted for under the acquisition method of accounting with the identifiable assets and liabilities recognized at fair value on the date of transfer. See Note 3—Acquisitions for information regarding the acquisition.
On October 17, 2012, the Company completed its initial public offering (“IPO”) of 14,375,000 shares of common stock, which included 1,875,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the public at $17.50 per share and the Company received net proceeds of approximately $234.1 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.
In the first quarter of 2013, Windsor UT merged with and into Windsor Permian and Windsor Permian, the surviving entity in the merger, was renamed Diamondback O&G LLC, or Diamondback O&G.
On May 22, 2013, the Company completed an underwritten primary public offering of 5,175,000 shares of common stock, which included 675,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the public at $29.25 per share and the Company received net proceeds of approximately $144.4 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.
On June 24, 2013, Gulfport and certain entities controlled by Wexford completed an underwritten secondary public offering of 6,000,000 shares of the Company’s common stock and, on July 5, 2013, the underwriters purchased an additional 869,222 shares of the Company’s common stock from these selling stockholders pursuant to an option to purchase such additional shares granted to the underwriters. The shares were sold to the public at $34.75 per share and the selling stockholders received all proceeds from this offering.
Basis of Presentation
These financial statements have been prepared by the Company without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been omitted pursuant to such rules and regulations, although the Company believes the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10–Q should be read in conjunction with the Company’s most recent

7

Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Notes to Combined Consolidated Financial Statements-(Continued)
(Unaudited)

Annual Report on Form 10–K for the fiscal year ended December 31, 2012, which contains a summary of the Company’s significant accounting policies and other disclosures.
Transfers of a business between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information. As discussed above, the Windsor UT Contribution was accounted for as a transaction between entities under common control. Thus, the accompanying combined consolidated financial statements and related notes of the Company have been retrospectively adjusted to include the historical results of Windsor UT at historical carrying values and its operations prior to October 11, 2012, the effective date of the Windsor UT Contribution. The accompanying financial statements and related notes presented herein represent the combined results of operations and cash flows of our Predecessors through October 11, 2012, and the Company and its wholly-owned subsidiaries consolidated financial position, results of operations, cash flows and equity subsequent to October 11, 2012. All intercompany balances and transactions are eliminated in consolidation.
2.    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
Certain amounts included in or affecting the Company’s combined consolidated financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the combined consolidated financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities at the date of the combined consolidated financial statements. Actual results could differ from those estimates.
The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, asset retirement obligations, the fair value determination of acquired assets and liabilities, stock-based compensation, fair value estimates of commodity derivatives and estimates of income taxes.
Unaudited Pro Forma Income Taxes
Diamondback was formed as a holding company on December 30, 2011, and did not conduct any material business operations prior to the Merger. Diamondback is a C-Corporation under the Internal Revenue Code and is subject to income taxes. The Company computed a pro forma income tax provision as if the Company and our Predecessors were subject to income taxes since December 31, 2011. The pro forma tax provision has been calculated at a rate based upon a federal corporate level tax rate and a state tax rate, net of federal benefit, incorporating permanent differences.
Unaudited Pro Forma Earnings per Share
The Company’s pro forma basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period, as if the common shares issued upon the Merger were outstanding for the entire year. Diluted earnings per share reflects the potential dilution, using the treasury stock method, which assumes that options were exercised and restricted stock awards and units were fully vested. During periods in which the Company realizes a net loss, options and restricted stock awards would not be dilutive to net loss per share and conversion into common stock is assumed not to occur.
3.    ACQUISITIONS
On October 11, 2012, the Company completed the acquisition of Gulfport’s oil and natural gas interests in the Permian Basin. The following unaudited summary pro forma combined consolidated statement of operations data of Diamondback for the three months and six months ended June 30, 2012 has been prepared to give effect to the acquisition as if it had occurred on January 1, 2011. The pro forma data are not necessarily indicative of financial results that would have been attained had the acquisition occurred on January 1, 2011. The pro forma data also

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Diamondback Energy, Inc. and Subsidiaries
Notes to Combined Consolidated Financial Statements-(Continued)
(Unaudited)

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.
 
 
Three Months Ended
 
Six Months Ended
 
 
 
June 30, 2012
 
June 30, 2012
 
 
 
(Pro Forma)
 
(Pro Forma)
 
Pro forma total revenues
 
$
22,951,000

 
$
46,572,000

 
Pro forma income from operations
 
6,405,000

 
15,691,000

 
Pro forma net income
 
15,722,000

(1) 
19,748,000

(1) 
(1) This amount does not include a pro forma income tax provision relating to becoming subject to income taxes as a result of the Merger.

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Diamondback Energy, Inc. and Subsidiaries
Notes to Combined Consolidated Financial Statements-(Continued)
(Unaudited)

4.    PROPERTY AND EQUIPMENT
Property and equipment includes the following:
 
 
June 30,
 
December 31,
 
 
2013
 
2012
Oil and natural gas properties:
 
 
 
 
Subject to depletion
 
$
728,839,000

 
$
576,497,000

Not subject to depletion-acquisition costs
 
 
 
 
Incurred in 2013
 
5,984,000

 

Incurred in 2012
 
109,059,000

 
117,395,000

Incurred in 2011
 
1,670,000

 
1,670,000

Incurred in 2010
 
1,647,000

 
1,647,000

Incurred in 2009
 
533,000

 
533,000

Total not subject to depletion
 
118,893,000

 
121,245,000

 
 
 
 
 
Gross oil and natural gas properties
 
847,732,000

 
697,742,000

Less accumulated depreciation, depletion, amortization and impairment
 
(170,286,000
)
 
(145,102,000
)
Oil and natural gas properties, net
 
677,446,000

 
552,640,000

 
 
 
 
 
Other property and equipment
 
4,749,000

 
2,337,000

Less accumulated depreciation
 
(1,023,000
)
 
(735,000
)
Other property and equipment, net
 
3,726,000

 
1,602,000

 
 
 
 
 
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment
 
$
681,172,000

 
$
554,242,000

The average depletion rate per barrel equivalent unit of production was $24.42 and $24.44 for the three months and six months ended June 30, 2013, respectively, and $24.26 and $23.70 for the three months and six months ended June 30, 2012, respectively. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs not directly associated with exploration and development activities were charged to expense as they were incurred. Capitalized internal costs were approximately $843,000 and $1,640,000 for the three months and six months ended June 30, 2013, respectively, and $1,083,000 and $1,775,000 for the three months and six months ended June 30, 2012, respectively. Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within three to five years.

5.    ASSET RETIREMENT OBLIGATIONS
The following table describes the changes to the Company’s asset retirement obligation liability for the following periods:
 
Six Months Ended
 
June 30,
 
2013
 
2012
Asset retirement obligation, beginning of period
$
2,145,000

 
$
1,104,000

Additional liability incurred
111,000

 
95,000

Accretion expense
88,000

 
41,000

Asset retirement obligation, end of period
2,344,000

 
1,240,000

Less current portion
20,000

 
19,000

Asset retirement obligations - long-term
$
2,324,000

 
$
1,221,000

The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The Company estimates the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current

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Diamondback Energy, Inc. and Subsidiaries
Notes to Combined Consolidated Financial Statements-(Continued)
(Unaudited)

present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance.
6.    EQUITY METHOD INVESTMENTS
Bison Drilling and Field Services LLC
On November 15, 2010, the Company formed a wholly owned subsidiary, Bison Drilling and Field Services LLC (“Bison”), formerly known as Windsor Drilling LLC. In addition, on March 2, 2010, the Company formed a wholly owned subsidiary, West Texas Field Services LLC, which, on January 1, 2011, contributed all of its assets and liabilities to Bison and West Texas Field Services LLC was subsequently dissolved on June 12, 2012. Bison owns and operates drilling rigs and various oil and natural gas well servicing equipment.
Beginning on March 31, 2011, various related party investors contributed capital to Bison diluting the Company’s ownership interest. The Company assessed its ability to exercise financial control over Bison and based on the results of its assessment, the Company concluded it maintained significant influence but it no longer had the ability to exercise control over Bison. The Company deconsolidated Bison for financial reporting purposes as of March 31, 2011 and the previously consolidated amounts were removed from the consolidated balance sheet and reflected as an equity method investment. The Company eliminated intercompany profits or losses in relation to its continuing involvement with Bison, proportionate to its equity interest. Under the equity method, generally the Company’s share of investees’ earnings or loss is recognized in the combined consolidated statements of operations. However, because substantially all of Bison’s earnings were generated by performing services on properties owned and operated by the Company, the Company’s share of Bison’s earnings have been credited to oil and natural gas properties.
An entity is required to deconsolidate a subsidiary when the entity ceases to have a controlling financial interest in the subsidiary. Upon deconsolidation of a subsidiary, an entity recognizes a gain or loss on the transaction and measures any retained investment in the subsidiary at fair value. The gain or loss includes any gain or loss associated with the difference between the fair value of the retained investment in the subsidiary and its carrying amount at the date the subsidiary is deconsolidated.
The Company internally reviewed the balance sheet of Bison to determine its fair value. At the time of the transaction Bison was still a recently formed company and had not yet built value in its operations. Bison’s assets consisted primarily of four recently purchased drilling rigs. Two of the drilling rigs were purchased at market price from a third party in December 2010 and the second two were purchased from the same third party in April 2011. The Company also reviewed pricing of similar rigs in the market through retail and auction transactions. Because the rigs had just recently been purchased and this purchase price was in line with other outside transactions the Company determined that Bison’s book value equaled fair value. There was no gain or loss recorded and the retained investment was recorded at fair value which equaled book value.
In September 2011, the Company completed the sale of 25% of its membership interest in Bison to a related party. The Company internally reviewed the fair value of Bison and because the effective date of this transaction was May 1, 2011 and was within thirty days of the above valuation the Company concluded the value of Bison had not changed. The Company determined that fair value equaled book value at the date of this transaction. There was no gain or loss recorded and the retained investment was recorded at fair value which equaled book value.
As of June 15, 2012, the Company distributed its remaining interest in Bison to an entity which is controlled and managed by Wexford. As the transaction was between entities under common control, the Company recognized the distribution of $6,437,000 as an equity transaction. Bison continues to be a related party with the Company.
Muskie Holdings LLC
During 2011, the Company paid approximately $4,200,000 for land and various other capital items related to the land. On October 7, 2011, the Company contributed these assets to a newly formed entity, Muskie Holdings LLC (“Muskie”), a Delaware limited liability company now known as Muskie Proppant LLC, for a 48.6% equity interest. Through additional contributions to Muskie from a related party and various Wexford portfolio companies, the Company’s interest in Muskie decreased to 33% as of June 15, 2012. Muskie generated a loss during the period from January 1, 2012 through June 15, 2012 and the Company recorded its share of this loss.

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Diamondback Energy, Inc. and Subsidiaries
Notes to Combined Consolidated Financial Statements-(Continued)
(Unaudited)

As of June 15, 2012, the Company distributed its remaining interest in Muskie to an entity which is controlled and managed by Wexford. As the transaction was between entities under common control, the Company recognized the distribution of $4,067,000 as an equity transaction. Muskie continues to be a related party with the Company.
7.    DEBT
Credit Facility-Wells Fargo Bank
On October 15, 2010, the Company entered into a secured loan agreement with BNP Paribas (“BNP”) as the administrative agent, sole book runner and lead arranger providing for a revolving credit facility. On May 10, 2012, the revolving credit agreement was amended to provide for the resignation of BNP, and the appointment of Wells Fargo Bank, National Association, as administrative agent for the lenders. The loan agreement, as amended, provides for a $250.0 million revolving credit facility subject to scheduled semi-annual and other elective collateral borrowing base redeterminations based on our oil and natural gas reserves (the “borrowing base”). The outstanding borrowings bear interest at a rate elected by the Company that is based on the prime, LIBOR or federal funds rate plus margins ranging from 1.25% to 3.50% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base.
Principal may be optionally repaid from time to time and is required to be paid (i) if the loan amount exceeds the borrowing base and (ii) at the maturity date of October 15, 2014. The Company is obligated to pay, quarterly, a commitment fee equal to 0.5% per year of the unused portion of the borrowing base. The loan is secured by substantially all of the Company’s assets. The borrowing base is re-determined semi-annually with effective dates of April 1st and October 1st (a “scheduled redetermination”). In addition, the Company may request an additional three redeterminations of the borrowing base during any 12 months period. The borrowing base was $100.0 million at December 31, 2011. The borrowing base increased throughout 2012 and 2013 through various redeterminations and at December 31, 2012 and June 30, 2013, the borrowing base was $135.0 million and $180.0 million, respectively. In connection with the IPO, the Company repaid all outstanding borrowings under its revolving credit facility and, as of December 31, 2012, had no outstanding borrowings. In connection with the public offering of the Company’s common stock in May 2013, the Company repaid all outstanding borrowings under its revolving credit facility and, as of June 30, 2013, had no outstanding borrowings under this facility.
The revolving credit agreement contains various affirmative and restrictive covenants. These covenants, among other things, prohibit additional indebtedness, sales of assets, mergers and consolidations, dividends and distributions, and changes in management and require the maintenance of various financial ratios defined below.
The current lenders and their percentage commitments in the revolving credit facility are Wells Fargo Bank, N.A. (45%), Amegy Bank, N.A. (25%), U.S. Bank, N.A. (25%) and West Texas National Bank (5%).
As of July 24, 2012, the revolving credit agreement was amended and restated to include Diamondback Energy LLC and its subsidiaries as additional guarantors to the facility. The covenant prohibiting additional indebtedness was also amended to allow the issuance of unsecured debt of up to $250.0 million and, in connection with any such issuance, the reduction of the borrowing base by 25% of the principal amount of such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid. The amendment also provided that redemptions of any unsecured debt will be restricted unless certain liquidity requirements are met. Further, the amendment modified certain financial ratios, the current requirements of which are described below.
Financial Covenant
 
 
Required Ratio
Ratio of EBITDAX to interest expense, as defined in the credit agreement
 
Not less than 2.5 to 1.0
Ratio of total debt to EBITDAX
 
Not greater than 4.0 to 1.0
Ratio of debt under revolving credit agreement to EBITDAX
 
Not greater than 3.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreement
 
Not less than 1.0 to 1.0

The revolving credit agreement defines EBITDAX, for any period, as the sum of consolidated net income for such period plus the following expenses or charges to the extent deducted from consolidated net income for such period: interest; income taxes; depreciation, depletion, amortization and exploration expenses; extraordinary items and other similar non-cash charges, including expenses related to stock-based compensation and hedging, minus all non-cash income added to consolidated net income.

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Diamondback Energy, Inc. and Subsidiaries
Notes to Combined Consolidated Financial Statements-(Continued)
(Unaudited)


As of September 28, 2012, the second amendment to the amended and restated credit agreement was executed, which among other things provided for an increase in permitted subordinated debt in a maximum principal amount not to exceed $45.0 million, waived compliance with the Company’s current ratio covenant for the quarter ending September 30, 2012 and increased the aggregate limitation on lease payments during any period of 12 months consecutive calendar months from $250,000 to $550,000.

As of June 30, 2013, the Company was in compliance with all financial covenants under the revolving credit facility. The lenders may accelerate all of the indebtedness under the revolving credit facility upon the occurrence of any event of default unless the Company cures any such default within any applicable grace period. For payments of principal and interest under the revolving credit facility, the Company generally has a three business day grace period, and a 30-day cure period for most covenant defaults, but not for defaults of certain specific covenants, including the financial covenants and negative covenants.
Note Payable
The Company entered into an installment payment contract with EMC Corporation for the purchase of computer equipment. The contract is payable in equal installments over a period of 36 months. As of June 30, 2013 and December 31, 2012, the Company had amounts outstanding under this note of $266,000 and $338,000, respectively.

Subordinated Note
Effective May 14, 2012, the Company issued a subordinated note to an affiliate of Wexford pursuant to which, as amended, the Wexford affiliate could, from time to time, advance up to an aggregate of $45.0 million. These advances were solely at the lender’s discretion and neither Wexford nor any of its affiliates had any commitment or obligation to provide further capital support to the Company. The note bore interest at a rate equal to LIBOR plus 0.28% or 8% per annum, whichever was lower. Interest was due quarterly in arrears beginning on July 1, 2012. Interest payments were payable in kind by adding such amounts to the principal balance of the note. The unpaid principal balance and all accrued interest on the note was due and payable in full on January 31, 2015 or the earlier completion of an initial public offering. Any indebtedness evidenced by this note was subordinate in the right of payment to any indebtedness outstanding under the Company’s revolving credit facility. As of June 30, 2012, there was $14.1 million in aggregate principal amount outstanding under this note. In connection with the IPO, the Company repaid all outstanding borrowings under the subordinated note and the subordinated note was canceled.

8.    EARNINGS PER SHARE & PRO FORMA EARNINGS PER SHARE

Earnings Per Share
The Company’s basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:
 
 
Three Months Ended June 30, 2013
 
 
 
 
 
 
Per
 
 
Income
 
Shares
 
Share
Basic:
 
 
 
 
 
 
Net income attributable to common stock
 
$
14,471,000

 
39,402,282

 
$
0.37

Effect of Dilutive Securities:
 
 
 
 
 
 
Dilutive effect of potential common shares issuable
 
$

 
316,292

 
 
Diluted:
 
 
 
 
 
 
Net income attributable to common stock
 
$
14,471,000

 
39,718,574

 
$
0.36


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Diamondback Energy, Inc. and Subsidiaries
Notes to Combined Consolidated Financial Statements-(Continued)
(Unaudited)

 
 
Six Months Ended June 30, 2013
 
 
 
 
 
 
Per
 
 
Income
 
Shares
 
Share
Basic:
 
 
 
 
 
 
Net income attributable to common stock
 
$
19,867,000

 
38,237,149

 
$
0.52

Effect of Dilutive Securities:
 
 
 
 
 
 
Dilutive effect of potential common shares issuable
 
$

 
239,570

 
 
Diluted:
 
 
 
 
 
 
Net income attributable to common stock
 
$
19,867,000

 
38,476,719

 
$
0.52


Pro Forma Earnings Per Share
The Company’s pro forma basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period, as if the common shares issued upon the Merger were outstanding for the entire year. A reconciliation of the components of pro forma basic and diluted earnings per common share is presented in the table below:
 
 
Three Months Ended June 30, 2012
 
 
 
 
 
 
Per
 
 
Income
 
Shares
 
Share
Basic:
 
 
 
 
 
 
Pro forma net income attributable to common stock
 
$
8,767,000

 
14,697,496

 
$
0.60

Effect of Dilutive Securities:
 
 
 
 
 
 
Dilutive effect of potential common shares issuable
 
$

 

 
 
Diluted:
 
 
 
 
 
 
Pro forma net income attributable to common stock
 
$
8,767,000

 
14,697,496

 
$
0.60

 
 
Six Months Ended June 30, 2012
 
 
 
 
 
 
Per
 
 
Income
 
Shares
 
Share
Basic:
 
 
 
 
 
 
Pro forma net income attributable to common stock
 
$
9,717,000

 
14,697,496

 
$
0.66

Effect of Dilutive Securities:
 
 
 
 
 
 
Dilutive effect of potential common shares issuable
 
$

 

 
 
Diluted:
 
 
 
 
 
 
Pro forma net income attributable to common stock
 
$
9,717,000

 
14,697,496

 
$
0.66

9.    STOCK AND EQUITY BASED COMPENSATION
For the three months and six months ended June 30, 2013, the Company incurred $700,000 and $1,356,000, respectively, of stock based compensation, of which the Company capitalized $223,000 and $420,000, respectively, pursuant to the full cost method of accounting for oil and natural gas properties. For the three months and six months ended June 30, 2012, the Company incurred $291,000 and $582,000, respectively, of equity based compensation, of which the Company capitalized $116,000 and $223,000, respectively, pursuant to the full cost method of accounting for oil and natural gas properties.
The following table presents the Company’s stock option activity under the 2012 Plan for the six months ended June 30, 2013.

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Diamondback Energy, Inc. and Subsidiaries
Notes to Combined Consolidated Financial Statements-(Continued)
(Unaudited)

 
 
 
 
Weighted Average
 
 
 
 
 
 
Exercise
 
Remaining
 
Intrinsic
 
 
Options
 
Price
 
Term
 
Value
 
 
 
 
 
 
(In years)
 
 
Outstanding at December 31, 2012
 
850,000

 
$
17.50

 
 
 
 
Granted
 
63,000

 
$
22.72

 
 
 
 
Exercised
 

 
$

 
 
 
 
Expired/Forfeited
 

 
$

 
 
 
 
Outstanding at June 30, 2013
 
913,000

 
$
17.86

 
3.28
 
$
14,115,000

 
 
 
 
 
 
 
 
 
Vested and Expected to vest at June 30, 2013
 
913,000

 
$
17.86

 
3.28
 
$
14,115,000

Exercisable at June 30, 2013
 
287,500

 
$
17.50

 
2.99
 
$
4,548,000

As of June 30, 2013, the unrecognized compensation cost related to unvested stock options was $2,347,000. Such cost is expected to be recognized over a weighted-average period of 2.3 years.
The following table presents the Company’s restricted stock awards and units activity under the 2012 Plan for the six months ended June 30, 2013.
 
 
 
 
Weighted Average
 
 
Restricted Stock
 
Grant-Date
 
 
Awards & Units
 
Fair Value
Unvested at December 31, 2012
 
206,507

 
$
17.50

Granted
 

 
$

Vested
 
14,286

 
$
17.50

Forfeited
 

 
$

Unvested at June 30, 2013
 
192,221

 
$
17.50

As of June 30, 2013, the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $2,574,000. Such cost is expected to be recognized over a weighted-average period of 2.0 years.
10.    RELATED PARTY TRANSACTIONS

Administrative Services
An entity under common management provided technical, administrative and payroll services to the Company under a shared services agreement which began March 1, 2008. Through December 31, 2011, amounts charged to the Company included those costs directly attributable to the Company as well as indirect costs allocated to the Company. The reimbursement amount for indirect costs is determined by the affiliate’s management based on estimates of time devoted to the Company. The initial term of this shared service agreement was two years. Since the expiration of such two-year period on March 1, 2010, the agreement by its terms, continued on a month-to-month basis. For the three months and six months ended June 30, 2013, the Company incurred total costs of $51,000 and $109,000, respectively. For the three months and six months ended June 30, 2012, the Company incurred total costs of $1,673,000 and $4,123,000, respectively. Costs incurred unrelated to drilling activities are expensed and costs incurred in the acquisition, exploration and development of proved oil and natural gas properties have been capitalized. The expensed costs were partially offset in general and administrative expenses by overhead reimbursements of $613,000 and $1,152,000 for the three months and six months ended June 30, 2012, respectively. As of June 30, 2013 and December 31, 2012, the Company owed the administrative services affiliate $16,000 and $13,000, respectively. These amounts are included in accounts payable-related party in the accompanying consolidated balance sheets.

Effective January 1, 2012, the Company entered into an additional shared services agreement with this entity. Under this agreement, the Company provides this entity and, at its request, certain affiliates, with consulting, technical and administrative services. The initial term of the additional shared services agreement is two years. Upon expiration of

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Diamondback Energy, Inc. and Subsidiaries
Notes to Combined Consolidated Financial Statements-(Continued)
(Unaudited)

the initial term the agreement will continue on a month-to-month basis until canceled by either party upon thirty days prior written notice. Costs that are attributable to and billed to other affiliates are reported as other income-related party. For the three months and six months ended June 30, 2013, the affiliate reimbursed the Company $388,000 and $777,000, respectively, and for the three months and six months ended June 30, 2012, the affiliate reimbursed the Company $586,000 and $1,011,000, respectively for services under the shared services agreement. As of June 30, 2013 and December 31, 2012, the affiliate owed the Company no amounts and $1,000, respectively. These amounts are included in accounts receivable-related party in the accompanying consolidated balance sheets.
Operating Services
The Company is the operator of substantially all of its properties. As operator of these properties, the Company is responsible for the daily operations, monthly operation billings and monthly revenue disbursements for the properties.
As of June 30, 2013 and December 31, 2012, amounts due from an affiliate related to joint interest billings and included in accounts receivable-related party in the accompanying consolidated balance sheets were $183,000 and $742,000, respectively.
Drilling Services
Bison has performed drilling and field services for the Company under master drilling and field service agreements. Under the Company’s most recent master drilling agreement with Bison, effective as of January 1, 2013, Bison committed to accept orders from the Company for the use of at least two of its rigs. At June 30, 2013, Bison was providing drilling services to the Company using one of its rigs. This master drilling agreement is terminable by either party on 30 days prior written notice, although neither party will be relieved of its respective obligations arising from a drilling contract being performed prior to the termination of the master drilling agreement. The Company owed Bison $708,000 as of June 30, 2013 and $120,000 as of December 31, 2012.
MidMar
The Company is party to a gas purchase agreement, dated May 1, 2009, as amended, with MidMar Gas LLC (“MidMar”), an entity affiliated with Wexford that owns a gas gathering system and processing plant in the Permian Basin. Under this agreement, MidMar is obligated to purchase from the Company, and the Company is obligated to sell to MidMar, all of the gas conforming to certain quality specifications produced from certain of the Company’s Permian Basin acreage. Following the expiration of the initial ten year term, the agreement will continue on a year-to-year basis until terminated by either party on 30 days’ written notice. Under the gas purchase agreement, MidMar is obligated to pay the Company 87% of the net revenue received by MidMar for all components of the Company’s dedicated gas, including the liquid hydrocarbons, and the sale of residue gas, in each case extracted, recovered or otherwise processed at MidMar’s gas processing plant, and 94.56% of the net revenue received by MidMar from the sale of such gas components and residue gas, extracted, recovered or otherwise processed at Chevron’s Headlee plant. The Company recognized revenues from Midmar of $1,723,000 and $2,818,000 for the three months and six months ended June 30, 2013, respectively, and $618,000 and $1,397,000 for the three months and six months ended June 30, 2012, respectively. As of June 30, 2013 and December 31, 2012, MidMar owed the Company $465,000 and $6,000, respectively, for the Company’s portion of the net proceeds from the sale of gas, gas products and residue gas.
Sand Supply
Muskie, an entity affiliated with Wexford, holds certain rights in a lease covering land in Wisconsin for mining oil and natural gas fracture grade sand. The Company began purchasing sand from Muskie in March 2013. The Company incurred costs of zero and $234,000 for the three months and six months ended June 30, 2013. As of June 30, 2013, the Company did not owe Muskie any amounts.
Midland Lease
Effective May 15, 2011, the Company occupied corporate office space in Midland, Texas under a lease with a five-year term. The office space is owned by an entity controlled by an affiliate of Wexford. The Company paid $43,000 and $82,000 for the three months and six months ended June 30, 2013, respectively, and $40,000 and $72,000, for the three months and six months ended June 30, 2012, respectively, under this lease. In the second quarter of 2013, we amended this agreement to increase the size of the leased premises. The current monthly rent under the lease will

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Diamondback Energy, Inc. and Subsidiaries
Notes to Combined Consolidated Financial Statements-(Continued)
(Unaudited)

increase from $13,000 to $15,000 beginning on September 1, 2013 and $21,000 beginning on October 1, 2013. The monthly rent will increase approximately 4% annually on June 1 of each year during the remainder of the lease term.
Oklahoma City Lease
Effective January 1, 2012, the Company occupied corporate office space in Oklahoma City, Oklahoma under a lease with a 67 month term. The office space is owned by an entity controlled by an affiliate of Wexford. The Company paid $58,000 and $111,000 for the three months and six months ended June 30, 2013, respectively, and $82,000 and $206,000 for the three months and six months ended June 30, 2012, respectively, under this lease. Effective April 1, 2013, we amended this lease to increase the size of the leased premises, at which time our monthly base rent increased to $19,000 for the remainder of the lease term. The Company is also responsible for paying a portion of specified costs, fees and expenses associated with the operation of the premises.
Advisory Services Agreement & Professional Services from Wexford
The Company entered into an advisory services agreement (the “Advisory Services Agreement”) with Wexford, dated as of October 11, 2012, under which Wexford provides the Company with general financial and strategic advisory services related to the business in return for an annual fee of $500,000, plus reasonable out-of-pocket expenses. The Advisory Services Agreement has a term of two years commencing on October 18, 2012, and will continue for additional one-year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term. It may be terminated at any time by either party upon 30 days prior written notice. In the event the Company terminates such agreement, it is obligated to pay all amounts due through the remaining term. In addition, the Company agreed to pay Wexford to-be-negotiated market-based fees approved by the Company’s independent directors for such services as may be provided by Wexford at the Company’s request in connection with future acquisitions and divestitures, financings or other transactions in which the Company may be involved. The services provided by Wexford under the Advisory Services Agreement do not extend to the Company’s day-to-day business or operations. The Company has agreed to indemnify Wexford and its affiliates from any and all losses arising out of or in connection with the Advisory Services Agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willful misconduct. The Company incurred total costs of $125,000 and $250,000 for the three months and six months ended June 30, 2013, respectively, under the Advisory Services Agreement. Wexford provides certain professional services to the Company, for which the Company incurred total costs of $57,000 and $94,000 for the three months and six months ended June 30, 2012, respectively. As of June 30, 2013 and December 31, 2012, the Company owed Wexford no amounts and $113,000, respectively. These amounts are included in accounts payable-related party in the accompanying consolidated balance sheets.
Secondary Offering Costs
On June 24, 2013, Gulfport and certain entities controlled by Wexford completed an underwritten secondary public offering of 6,000,000 shares of the Company’s common stock and, on July 5, 2013, the underwriters purchased an additional 869,222 shares of the Company’s common stock from these selling stockholders pursuant to an option to purchase such additional shares granted to the underwriters. The shares were sold to the public at $34.75 per share and the selling stockholders received all proceeds from this offering. The Company incurred costs of approximately $179,000 related to the secondary public offering.
11. DERIVATIVES

All derivative financial instruments are recorded at fair value. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the realized and unrealized changes in fair value in the combined consolidated statements of operations under the caption “Gain on derivative instruments.”

The Company has used price swap contracts to reduce price volatility associated with certain of its oil sales. With respect to the Company’s fixed price swap contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing, Argus Louisiana light sweet pricing or Inter–Continental Exchange (“ICE”) pricing for Brent crude oil. The counterparties

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Diamondback Energy, Inc. and Subsidiaries
Notes to Combined Consolidated Financial Statements-(Continued)
(Unaudited)

to the Company’s derivative contracts are BNP Paribas and Wells Fargo Bank, N.A., who the Company believes are acceptable credit risks.
As of June 30, 2013, the Company had open crude oil derivative positions with respect to future production as set forth in the tables below.
Crude Oil—NYMEX West Texas Intermediate Fixed Price Swap
 
 
 
 
 
 
 
 
Production Period
 
Volume (Bbls)
 
Fixed Swap Price
July–December 2013
184,000

 
$
80.55

 
 
 
 
 
Crude Oil—Argus Louisiana Light Sweet Fixed Price Swap
 
 
 
 
 
 
 
 
Production Period
 
Volume (Bbls)
 
Fixed Swap Price
July - December 2013
 
184,000

 
$
100.20

January - June 2014
 
181,000

 
100.20

 
 
 
 
 
Crude Oil—ICE Brent Fixed Price Swap
 
 
 
 
 
 
 
 
Production Period
 
Volume (Bbls)
 
Fixed Swap Price
July–December 2013
184,000

 
$
109.70

January–April 2014
 
120,000

 
109.70


The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions that are with the same counterparty and are subject to contractual terms which provide for net settlement. The net amounts are classified as current or noncurrent based on their anticipated settlement dates. The net fair value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:
 
 
June 30,
 
December 31,
 
 
2013
 
2012
Current Assets: Derivative instruments
 
$
3,191,000

 
$

Noncurrent Assets: Derivative instruments
 

 

Total Assets
 
$
3,191,000

 
$

 
 
 
 
 
Current Liabilities: Derivative instruments
 
$
2,679,000

 
$
4,817,000

Noncurrent Liabilities: Derivative instruments
 

 
388,000

Total Liabilities
 
$
2,679,000

 
$
5,205,000


The following table presents the netting offsets of the Company’s derivative assets and liabilities as of June 30, 2013 and December 31, 2012.

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Diamondback Energy, Inc. and Subsidiaries
Notes to Combined Consolidated Financial Statements-(Continued)
(Unaudited)

 
 
June 30, 2013
 
 
Gross Amounts of Recognized Assets
 
Gross Amounts Offset in the Consolidated Balance Sheet
 
Net Amounts of Assets Presented in the Consolidated Balance Sheet
Derivative assets:
 
 
 
 
 
 
Crude Oil—ICE Brent Fixed Price Swap
$
2,891,000

 
$

 
$
2,891,000

Crude Oil—Argus Louisiana Light Sweet Fixed Price Swap
300,000

 

 
300,000

 
 
 
 
 
 
 
 
 
Gross Amounts of Recognized Liabilities
 
Gross Amounts Offset in the Consolidated Balance Sheet
 
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
Derivative liabilities:
 
 
 
 
 
 
Crude Oil—NYMEX West Texas Intermediate Fixed Price Swap
$
2,679,000

 
$

 
$
2,679,000

 
 
 
 
 
 
 

 
 
December 31, 2012
 
 
Gross Amounts of Recognized Liabilities
 
Gross Amounts Offset in the Consolidated Balance Sheet
 
Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
Derivative liabilities:
 
 
 
 
 
 
Crude Oil—NYMEX West Texas Intermediate Fixed Price Swap
$
5,205,000

 
$

 
$
5,205,000

None of the Company’s derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following table summarizes the gains and losses on derivative instruments included in the combined consolidated statements of operations:
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2013
 
2012
 
2013
 
2012
Unrealized gain on open non-hedge derivative instruments
 
$
3,893,000

 
$
12,065,000

 
$
5,428,000

 
$
8,638,000

Loss on settlement of non-hedge derivative instruments
 
(856,000
)
 
(2,108,000
)
 
(2,399,000
)
 
(3,473,000
)
Gain on derivative instruments
 
$
3,037,000

 
$
9,957,000

 
$
3,029,000

 
$
5,165,000


12.    FAIR VALUE MEASUREMENTS
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.
The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities.
Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

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Diamondback Energy, Inc. and Subsidiaries
Notes to Combined Consolidated Financial Statements-(Continued)
(Unaudited)

Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.
Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments. The fair values of the Company’s fixed price crude oil swaps are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs.
The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of June 30, 2013 and December 31, 2012.
 
 
 
Fair value measurements at June 30, 2013 using:
 
 
 
 
Quoted Prices in Active Markets Level 1
 
Significant Other Observable Inputs
Level 2
 
Significant Unobservable Inputs
 Level 3
 
Total
Assets:
 
 
Fixed price swaps
 
$

 
$
3,191,000

 
$

 
$
3,191,000

Liabilities:
 
 
 
 
 
 
 
 
Fixed price swaps
 

 
2,679,000

 

 
2,679,000

 
 
 
 
 
 
 
 
 
 
 
 
Fair value measurements at December 31, 2012 using:
 
 
 
 
Quoted Prices in Active Markets Level 1
 
Significant Other Observable Inputs
Level 2
 
Significant Unobservable Inputs
 Level 3
 
Total
Liabilities:
 
 
 
 
 
 
 
 
Fixed price swaps
 
$

 
$
5,205,000

 
$

 
$
5,205,000

 
 
 
 
 
 
 
 
 
 
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
The following table provides the fair value of financial instruments that are not recorded at fair value in the combined consolidated financial statements.
 
 
June 30, 2013
 
December 31, 2012
 
 
Carrying
 
 
 
Carrying
 
 
 
 
Amount
 
Fair Value
 
Amount
 
Fair Value
Debt:
 
 
 
 
 
 
 
 
Note payable
 
$
266,000

 
$
249,000

 
$
338,000

 
$
305,000

The fair value of the note payable is determined using internal discounted cash flow calculations based on the interest rate and payment terms of the note payable. The fair value of the note payable is classified as Level 3 in the fair value hierarchy.




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Diamondback Energy, Inc. and Subsidiaries
Notes to Combined Consolidated Financial Statements-(Continued)
(Unaudited)

13.    CONTINGENCIES

In September 2010, Windsor Permian (now known as Diamondback O&G LLC) purchased certain property in Goodhue County, Minnesota, that was prospective for hydraulic fracturing grade sand. Prior to the purchase, the prior owners of the property had entered into a Mineral Development Agreement with the plaintiff and the Company purchased the property subject to that agreement. Windsor Permian subsequently contributed the property to Muskie. In an amended complaint filed in November 2012 by the plaintiff against the prior owners of the property, Windsor Permian and certain affiliates of Windsor Permian in the first judicial district court in Goodhue County, Minnesota, the plaintiff seeks damages from the Company and the other defendants alleging, among other things, interference with contractual relationship, interference with prospective advantage and unjust enrichment. In an order filed on May 24, 2013, the judge denied certain motions made by the defendants and set a trial date to determine liability, with a damage phase of the matter to commence on a later date if there is a determination of liability. Following a trial on the liability phase on June 21, 2013, the jury determined that the defendants intentionally interfered with plaintiff’s contract but that the interference did not cause the plaintiff to be unable to acquire mining permits prior to the enactment of the moratorium by Goodhue County. In an order filed on July 10, 2013, the judge ordered the damage phase to be set for trial following a pretrial and scheduling conference set for August 12, 2013. The Company believes these claims are without merit and will continue to vigorously defend this action. While management has determined that the possibility of loss is remote, litigation is inherently uncertain and management cannot determine the amount of loss, if any, that may result.
The Company could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations.

14.    SUBSEQUENT EVENTS

The Company has entered into two definitive agreements with unrelated third party sellers to purchase an aggregate of approximately 13,900 gross (11,150 net) operated acres in the Midland Basin for an aggregate of approximately $165,000,000, subject to certain adjustments. The Company entered into one agreement on August 1, 2013 and one agreement on August 2, 2013. The proposed transactions are expected to close by the end of September 2013.


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ITEM 2.         MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our unaudited combined consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10–Q as well as our audited combined consolidated financial statements and notes thereto included in our Annual Report on Form 10–K for the year ended December 31, 2012. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See “Part II, Item 1A. Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements”.

Overview

We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, long-life, onshore oil and natural gas reserves in the Permian Basin in West Texas. Our activities are primarily directed at the Clearfork, Spraberry, Wolfcamp, Cline, Strawn and Atoka formations which we refer to as the Wolfberry play. We intend to grow our reserves and production through development drilling, exploitation and exploration activities on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves. Substantially all of our revenues are generated through the sale of oil, natural gas liquids and natural gas production. Our production was approximately 75% oil, 14% natural gas liquids and 11% natural gas for the three months ended June 30, 2013, and was approximately 73% oil, 16% natural gas liquids and 11% natural gas for the three months ended June 30, 2012. Our production was approximately 73% oil, 15% natural gas liquids and 12% natural gas for the six months ended June 30, 2013, and was approximately 74% oil, 15% natural gas liquids and 11% natural gas for the six months ended June 30, 2012. On June 30, 2013, our net acreage position in the Permian Basin was approximately 54,035 net acres.

Diamondback was incorporated in Delaware on December 30, 2011, and did not conduct any material business operations until October 11, 2012 when Diamondback merged with its parent entity, Diamondback Energy LLC, with Diamondback continuing as the surviving entity. Diamondback Energy LLC was a holding company and did not conduct any material business operations other than its ownership of our common stock and the membership interests in Windsor Permian LLC, or Windsor Permian. As a result of the merger, Windsor Permian became a wholly-owned subsidiary of Diamondback and subsequently changed its name to Diamondback O&G LLC. Also on October 11, 2012, Wexford Capital LP, or Wexford, our equity sponsor, caused 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.” The Windsor UT Contribution was treated as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests. We refer to the historical results of Windsor Permian and Windsor UT prior to October 11, 2012 as our “Predecessors.”

Also on October 11, 2012, we acquired all of the oil and natural gas properties of Gulfport located in the Permian Basin in exchange for (i) 7,914,036 shares of our common stock, (ii) approximately $63.6 million in the form of a non-interest bearing promissory note that was repaid in full upon the closing of our initial public offering, or IPO, and (iii) a post-closing cash adjustment of approximately $18.6 million. We are the operator of the acreage acquired by us from Gulfport.    

On October 17, 2012, we completed our IPO of 14,375,000 shares of common stock, which included 1,875,000 shares of common stock issued pursuant to the over-allotment option exercised by the underwriters. The stock was priced at $17.50 per share and we received net proceeds of approximately $234.1 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.
In the first quarter of 2013, Windsor UT merged with and into Windsor Permian and Windsor Permian, the surviving entity in the merger, was renamed Diamondback O&G LLC, or Diamondback O&G.
On May 22, 2013, we completed an underwritten primary public offering of 5,175,000 shares of common stock, which included 675,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the public at $29.25 per share and we received net proceeds of approximately $144.4 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.

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Table of Contents

On June 24, 2013, Gulfport Energy Corporation, which we refer to as “Gulfport,” and certain entities controlled by Wexford Capital LP, which we refer to as “Wexford,” completed an underwritten secondary public offering of 6,000,000 shares of our common stock and, on July 5, 2013, the underwriters purchased an additional 869,222 shares of our common stock from these selling stockholders pursuant to an option to purchase such additional shares granted to the underwriters. The shares were sold to the public at $34.75 per share and the selling stockholders received all proceeds from this offering.
Recent Developments

We have entered into two definitive agreements with unrelated third party sellers to purchase an aggregate of approximately 13,900 gross (11,150 net) operated acres in the Midland Basin for an aggregate of approximately $165.0 million, subject to certain adjustments. We entered into one agreement on August 1, 2013 and one agreement on August 2, 2013. The proposed transactions are expected to close by the end of September 2013.

Basis of Presentation

Transfers of a business between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior years are retrospectively adjusted to furnish comparative information. As discussed above, the Windsor UT Contribution was accounted for as a transaction between entities under common control. Accordingly, the financial information and production data contained in this report have been retrospectively adjusted to include the historical results of Windsor UT at historical carrying values and its operations prior to October 11, 2012, the effective date of the Windsor UT Contribution.
Since we began operations in 2007, we have increased our drilling activity, evaluated potential acquisitions and added to our acreage portfolio. Because of our growth through acquisitions and development of our properties, our historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful or indicative of future results.
Operating Results Overview
During the three months ended June 30, 2013, our average daily production was approximately 6,590 BOE/d, consisting of 4,914 Bbls/d of oil, 4,489 Mcf/d of natural gas and 927 Bbls/d of natural gas liquids, an increase of 4,080 BOE/d, or 163%, from average daily production of 2,510 BOE/d for the three months ended June 30, 2012, consisting of 1,828 Bbls/d of oil, 1,734 Mcf/d of natural gas and 392 Bbls/d of natural gas liquids. The ST 4301H well in Midland County, with a 29 stage 7,141 foot lateral, achieved a peak 30 day rate of 916 BOE/d on submersible pump, with a previously reported peak 24 hour initial production, or IP, rate of 1,136 BOE/d. Our 14 producing horizontal Wolfcamp B wells have achieved peak 24 hour IP rates that averaged 920 BOE/d (88% oil) from lateral lengths that averaged 5,576 feet.

During the six months ended June 30, 2013, our average daily production was approximately 5,694 BOE/d, consisting of 4,134 Bbls/d of oil, 4,197 Mcf/d of natural gas and 860 Bbls/d of natural gas liquids, an increase of 3,323 BOE/d, or 140%, from average daily production of 2,371 BOE/d for the six months ended June 30, 2012, consisting of 1,747 Bbls/d of oil, 1,594 Mcf/d of natural gas and 358 Bbls/d of natural gas liquids.

During the three months ended June 30, 2013, we drilled 19 gross (16 net) wells, and participated in one additional gross non-operated well, in the Permian Basin. During the six months ended June 30, 2013, we drilled 38 gross (33 net) wells, and participated in one additional gross non-operated well, in the Permian Basin.

Sources of our revenue
Our revenues are derived from the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from our natural gas during processing. Our oil and natural gas revenues do not include the effects of derivatives. For the three months ended June 30, 2013 and 2012, our revenues were derived 90% and 90%, respectively, from oil sales, 6% and 8%, respectively, from natural gas liquids sales and 4% and 2%, respectively, from natural gas sales. For the six months ended June 30, 2013 and 2012, our revenues were derived 89% and 90%, respectively, from oil sales, 7% and 8%, respectively, from natural gas liquids sales and 4% and 2%, respectively, from natural gas sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.


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Table of Contents

Results of Operations
The following table sets forth selected historical operating data for the periods indicated.
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2013
 
2012
 
2013
 
2012
 
 
(unaudited)
 
(unaudited)
Operating Results:
 
 
 
 
 
 
 
 
Revenues
 
 
 
 
 
 
 
 
Oil and natural gas revenues
 
$
45,394,000

 
$
16,030,000

 
$
74,303,000

 
$
32,381,000

Operating Expenses
 
 
 
 
 
 
 
 
Lease operating expense
 
6,087,000

 
3,529,000

 
11,522,000

 
6,318,000

Production taxes
 
2,196,000

 
782,000

 
3,623,000

 
1,579,000

Gathering and transportation expense
 
247,000

 
79,000

 
380,000

 
146,000

Depreciation, depletion and amortization
 
14,815,000

 
5,659,000

 
25,553,000

 
10,416,000

General and administrative
 
2,621,000

 
1,653,000

 
5,092,000

 
2,837,000

Asset retirement obligation accretion expense
 
45,000

 
21,000

 
88,000

 
41,000

Total expenses
 
26,011,000

 
11,723,000

 
46,258,000

 
21,337,000

Income from operations
 
19,383,000

 
4,307,000

 
28,045,000

 
11,044,000

Net interest expense
 
(535,000
)
 
(1,172,000
)
 
(1,020,000
)
 
(2,052,000
)
Other income - related party
 
388,000

 
586,000

 
777,000

 
1,011,000

Gain on derivative instruments, net
 
3,037,000

 
9,957,000

 
3,029,000

 
5,165,000

Loss from equity investment
 

 
(54,000
)
 

 
(67,000
)
Total other income
 
2,890,000

 
9,317,000

 
2,786,000

 
4,057,000

Income before income taxes
 
22,273,000

 
13,624,000

 
30,831,000

 
15,101,000

Provision for deferred income taxes
 
7,802,000

 

 
10,964,000

 

Net income
 
$
14,471,000

 
$
13,624,000

 
$
19,867,000

 
$
15,101,000

 
 
 
 
 
 
 
 
 
Production Data:
 
 
 
 
 
 
 
 
Oil (Bbls)
 
447,203

 
166,385

 
748,244

 
317,906

Natural gas (Mcf)
 
408,530

 
157,835

 
759,568

 
290,171

Natural gas liquids (Bbls)
 
84,360

 
35,678

 
155,689

 
65,188

Combined volumes (Boe)
 
599,651

 
228,369

 
1,030,528

 
431,456

Daily combined volumes (Boe/d)
 
6,590

 
2,510

 
5,694

 
2,371

 
 
 
 
 
 
 
 
 
Average Prices(1):
 
 
 
 
 
 
 
 
Oil (per Bbl)
 
$
91.76

 
$
86.34

 
$
88.59

 
$
91.26

Natural gas (per Mcf)
 
4.08

 
1.97

 
3.71

 
2.27

Natural gas liquids (per Bbl)
 
31.91

 
37.92

 
33.38

 
41.59

Combined (per BOE)
 
75.70

 
70.19

 
72.10

 
75.05

 
 
 
 
 
 
 
 
 
Average Costs (per BOE)
 
 
 
 
 
 
 
 
Lease operating expense
 
$
10.15

 
$
15.45

 
$
11.18

 
$
14.64

Gathering and transportation expense
 
0.41

 
0.35

 
0.37

 
0.34

Production taxes
 
3.66

 
3.42

 
3.52

 
3.66

Production taxes as a % of sales
 
4.8
%
 
4.9
%
 
4.9
%
 
4.9
%
Depreciation, depletion, and amortization
 
24.71

 
24.78

 
24.80

 
24.14

General and administrative
 
4.37

 
7.24

 
4.94

 
6.58

 
 
 
 
 
 
 
 
 
(1) After giving effect to our derivative instruments, the average prices per Bbl of oil and per BOE were $89.84 and $74.27, respectively, during the three months ended June 30, 2013, and $73.67 and $60.96, respectively, during the three months ended June 30, 2012. After giving effect to our derivative instruments, the average prices per Bbl of oil and per BOE were $85.38 and $69.77, respectively, during the six months ended June 30, 2013, and $80.34 and $67.00, respectively, during the six months ended June 30, 2012.

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Table of Contents

Comparison of the Three Months Ended June 30, 2013 and 2012
Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $29,364,000, or 183%, to $45,394,000 for the three months ended June 30, 2013 from $16,030,000 for the three months ended June 30, 2012. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 4,080 BOE/d to 6,590 BOE/d during the three months ended June 30, 2013 from 2,510 BOE/d during the three months ended June 30, 2012. The total increase in revenue of approximately $29,364,000 is largely attributable to higher oil, natural gas liquids and natural gas production volumes for the three months ended June 30, 2013 as compared to the three months ended June 30, 2012. The increases in production volumes were due to a combination of increased drilling activity and the effect of the contribution of Gulfport’s Permian Basin assets on October 11, 2012. Our production increased by 280,818 Bbls of oil, 48,682 Bbls of natural gas liquids and 250,695 Mcf of natural gas for the three months ended June 30, 2013 as compared to the three months ended June 30, 2012. The net dollar effect of the increases in prices of approximately $2,778,000 (calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas liquids and natural gas) and the net dollar effect of the increase in production of approximately $26,586,000 (calculated as the increase in period-to-period volumes for oil, natural gas liquids and natural gas multiplied by the period average prices) are shown below.
 
 
 
Change in prices
 
Production volumes(1)
 
Total net dollar effect of change
 
Effect of changes in price:
 
 
 
 
 
 
 
Oil
 
$
5.42

 
447,203

 
$
2,423,000

 
Natural gas liquids
 
$
(6.01
)
 
84,360

 
$
(507,000
)
 
Natural gas
 
$
2.11

 
408,530

 
$
862,000

 
Total revenues due to change in price
 
 
 
 
 
$
2,778,000

 
 
 
Change in production volumes(1)
 
Prior period Average Prices
 
Total net dollar effect of change
 
Effect of changes in production volumes:
 
 
 
 
 
 
 
Oil
 
280,818

 
$
86.34

 
$
24,246,000

 
Natural gas liquids
 
48,682

 
$
37.92

 
$
1,846,000

 
Natural gas
 
250,695

 
$
1.97

 
$
494,000

 
Total revenues due to change in production volumes
 
 
 
 
 
$
26,586,000

 
Total change in revenues
 
 
 
 
 
$
29,364,000

 
 
 
 
 
 
 
 
(1
)
Production volumes are presented in Bbls for oil and natural gas liquids and Mcf for natural gas
Lease Operating Expense. Lease operating expense was $6,087,000 ($10.15 per BOE) for the three months ended June 30, 2013, an increase of $2,558,000, or 72%, from $3,529,000 ($15.45 per BOE) for the three months ended June 30, 2012. The increase is due to increased drilling activity, which resulted in additional producing wells for the three months ended June 30, 2013 as compared to the three months ended June 30, 2012. Our lease operating expense during the three months ended June 30, 2012 was adversely impacted by the cost of processing and treating non-hydrocarbon gases from certain of our wells that came on-line in 2011. During the fourth quarter of 2012, we completed construction of a gas gathering system that transports this gas stream to a sour gas pipeline, thereby eliminating the monthly processing and treating expense, which savings are reflected in our lease operating expense for the three months ended June 30, 2013. In addition, in the first quarter 2013, we moved a portion of our produced water by a pipeline connected to a commercial salt water disposal well rather than by truck. During the remainder of 2013, we intend to continue the migration of water disposal and oil transportation from truck carriers to pipelines. We believe that the connection to salt water disposal wells and other actions will help reduce our lease operating expense in future periods.

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Table of Contents

Production Tax Expense. Production taxes as a percentage of oil and natural gas sales were 4.8% for the three months ended June 30, 2013, a decrease of 0.1% from 4.9% for the three months ended June 30, 2012. Production taxes are primarily based on the market value of our production at the wellhead and may vary across the different counties in which we operate. Total production taxes increased $1,414,000 from $782,000 during the three months ended June 30, 2012 to $2,196,000 during the three months ended June 30, 2013, as a result of higher production and an increase in the market value of our production.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $9,156,000, or 162%, from $5,659,000 for the three months ended June 30, 2012 to $14,815,000 for the three months ended June 30, 2013. This increase was due to an increase in our full cost pool as a result of the acquisition of the Gulfport properties and increased capital expenditures in conjunction with our drilling program during the three months ended June 30, 2013. The average depletion rate was $24.71 for the three months ended June 30, 2013 and $24.78 for the three months ended June 30, 2012. The average depletion rate includes oil and gas depletion and other property and equipment depreciation.
General and Administrative Expense. General and administrative expense increased $968,000 from $1,653,000 for the three months ended June 30, 2012 to $2,621,000 for the three months ended June 30, 2013. The increase was due to increases in salary, stock-based compensation, legal, secondary offering expenses, professional service and advisory service expenses. These increases were partially offset by increases in general and administrative costs related to exploration and development activity capitalized to the full cost pool and increases in COPAS overhead reimbursements due to increased drilling activity.
Net Interest Expense. Net interest expense for the three months ended June 30, 2013 was $535,000, as compared to $1,172,000 for the three months ended June 30, 2012, a decrease of $637,000, or 54%. This decrease was due primarily to a decrease in our weighted average outstanding borrowings under our credit agreement to $23,071,000 for the three months ended June 30, 2013 from $99,724,000 for the same period in 2012.
Derivatives. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the realized and unrealized changes in fair value on derivative instruments in our combined consolidated statements of operations under the line item captioned “Gain on derivative instruments.” For the three months ended June 30, 2013 and 2012, we had a realized loss on settlement of derivative instruments of $856,000 and $2,108,000, respectively. For the three months ended June 30, 2013 and 2012, we had an unrealized gain on open derivative instruments of $3,893,000 and $12,065,000, respectively.
Income tax expense. Prior to our IPO in October 2012, the operations of Windsor Permian and Windsor UT, as limited liability companies, were not subject to federal income taxes. Deferred income tax expense of $7,802,000 was incurred as a result of operations for the three months ended June 30, 2013.
Comparison of the Six Months Ended June 30, 2013 and 2012
Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $41,922,000, or 129%, to $74,303,000 for the six months ended June 30, 2013 from $32,381,000 for the six months ended June 30, 2012. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 3,323 BOE/d to 5,694 BOE/d during the six months ended June 30, 2013 from 2,371 BOE/d during the six months ended June 30, 2012. The total increase in revenue of approximately $41,922,000 is largely attributable to higher oil, natural gas liquids and natural gas production volumes for the six months ended June 30, 2013 as compared to the six months ended June 30, 2012, partially offset by a decrease in the average sales price received for these volumes. The increases in production volumes were due to a combination of increased drilling activity and the effect of the contribution of Gulfport’s Permian Basin assets on October 11, 2012. Our production increased by 430,338 Bbls of oil, 90,501 Bbls of natural gas liquids and 469,397 Mcf of natural gas for the six months ended June 30, 2013 as compared to the six months ended June 30, 2012. The net dollar effect of the decreases in prices of approximately $2,180,000 (calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas liquids and natural gas) and the net dollar effect of the increase in production of approximately $44,102,000 (calculated as the increase in period-to-period volumes for oil, natural gas liquids and natural gas multiplied by the period average prices) are shown below.

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Table of Contents

 
 
 
Change in prices
 
Production volumes(1)
 
Total net dollar effect of change
 
Effect of changes in price:
 
 
 
 
 
 
 
Oil
 
$
(2.67
)
 
748,244

 
$
(1,998,000
)
 
Natural gas liquids
 
$
(8.21
)
 
155,689

 
$
(1,278,000
)
 
Natural gas
 
$
1.44

 
759,568

 
$
1,096,000

 
Total revenues due to change in price
 
 
 
 
 
$
(2,180,000
)
 
 
 
Change in production volumes(1)
 
Prior period Average Prices
 
Total net dollar effect of change
 
Effect of changes in production volumes:
 
 
 
 
 
 
 
Oil
 
430,338

 
$
91.26

 
$
39,273,000

 
Natural gas liquids
 
90,501

 
$
41.59

 
$
3,764,000

 
Natural gas
 
469,397