FANG 10-Q Quarterly Report Sept. 30, 2012

FANG 10-Q Quarter ended Sept. 30, 2012

DIAMONDBACK ENERGY, INC.

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10-Q 1 a9301210-q.htm 10-Q 9.30.12 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 September 30, 2012



¨	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 ¨ No ý

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 ¨ 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):

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 November 16, 2012, 36,986,532 shares of common stock were outstanding.

DIAMONDBACK ENERGY, INC. TABLE OF CONTENTS

		Page
EXPLANATORY NOTE		i
PART I. FINANCIAL INFORMATION
ITEM 1.	Consolidated Financial Statements of Windsor Permian LLC (unaudited)
	Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011	1
	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2012 and 2011	2
	Consolidated Statements of Changes in Members' Equity for the Nine Months Ended September 30, 2012	4
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2012 and 2011	5
	Notes to Consolidated Financial Statements	7
ITEM 2.	Management's Discussion and Analysis of Financial Conditions and Results of Operations	20
ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk	29
ITEM 4.	Controls and Procedures	31
PART II OTHER INFORMATION
ITEM 1.	Legal Proceedings	31
ITEM 1A.	Risk Factors	31
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	31
ITEM 3.	Defaults Upon Senior Securities	32
ITEM 4.	Mine Safety Disclosures	32
ITEM 5.	Other Information	32
ITEM 6.	Exhibits	34
Signatures

Table of Contents

EXPLANATORY NOTE

The historical financial information contained in this report relates to periods that ended prior to the completion of the initial public offering (“IPO”) of Diamondback Energy, Inc., and prior to the effective dates of the Windsor UT LLC ("Windsor UT") and Gulfport Energy Corporation ("Gulfport") transactions discussed herein. Consequently, the unaudited consolidated financial statements and related discussion of financial condition and results of operations contained in this report pertain to Windsor Permian LLC (“Windsor”). Windsor is a wholly-owned subsidiary of Diamondback Energy LLC, an entity controlled by Wexford Capital LP ("Wexford"). In connection with completion of the IPO, Diamondback Energy LLC was merged with and into Diamondback Energy, Inc., causing Windsor to become a wholly owned subsidiary of Diamondback Energy, Inc. In addition, Wexford agreed to cause all of the outstanding equity interests in Windsor UT to be contributed to Windsor Permian prior to the merger in a transaction referred to as the Windsor UT contribution. On May 7, 2012, we entered into an agreement with Gulfport, in which Gulfport agreed to sell to us, subject to certain conditions, all of its oil and natural gas interests in the Permian Basin in exchange for shares of our common stock and a promissory note in a transaction we refer to as the Gulfport transaction. The Gulfport transaction was completed in connection with completion of the IPO. We refer to the Gulfport transaction and the Windsor UT contribution together as the Transactions.

On October 11, 2012, Diamondback Energy, Inc. priced 12,500,000 shares of its common stock in its IPO at a price of $17.50 per share, and on October 12, 2012 shares of Diamondback Energy, Inc.'s common stock began trading on the Nasdaq Global Select Market under the symbol “FANG”. On October 17, 2012, Diamondback Energy, Inc. closed its IPO. On October 23, 2012, the underwriters purchased an additional 1,875,000 shares of common stock following the exercise in full of their over-allotment option. Unless the context otherwise requires, references in this report to “we,” “our,” “us,” or like terms, when used in a historical context (periods prior to October 11, 2012) refer to Windsor. References in this report to “we,” “our,” “us,” or like terms, when used in the present tense or prospectively (periods after October 11, 2012) refer to Diamondback Energy, Inc. and its subsidiaries. See Note 3 to the following financial statements for Windsor for information regarding the closing of the IPO.

While management believes that the financial statements contained herein are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and in compliance with the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”), we do not believe that the financial statements of Windsor are indicative of the financial results that will be reported for periods subsequent to the IPO of Diamondback Energy, Inc. The information contained in this report should be read in conjunction with the information contained in Diamondback Energy, Inc.'s final prospectus dated October 11, 2012 and filed with the SEC pursuant to Rule 424(b) under the Securities Act of 1933 on October 15, 2012.

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Windsor Permian LLC and Subsidiaries

Consolidated Balance Sheets



	September 30, 2012			December 31, 2011
	September 30, 2012			December 31, 2011
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	1,275,000		$	6,802,000
Accounts receivable:
Joint interest and other	3,010,000			3,734,000
Oil and natural gas sales	5,172,000			839,000
Related party	10,041,000			13,123,000
Inventories	6,310,000			6,006,000
Prepaid expenses and other	1,096,000			428,000
Total current assets	26,904,000			30,932,000

Property and equipment
Oil and natural gas properties, at cost, based on the full cost method of accounting ($7,343,000 and $1,732,000 excluded from amortization at September 30, 2012 and December 31, 2011, respectively)	410,806,000			325,510,000
Other property and equipment	2,277,000			1,017,000
Accumulated depletion, depreciation, amortization and impairment	(135,733,000		)	(119,500,000		)
	277,350,000			207,027,000

Investments-equity method	—			10,310,000
Other assets	3,513,000			1,215,000
Total assets	$	307,767,000		$	249,484,000
Liabilities and Members' Equity
Current liabilities:
Accounts payable trade	$	22,683,000		$	8,770,000
Accounts payable-related party	1,066,000			3,436,000
Accrued capital expenditures	11,465,000			13,923,000
Other accrued liabilities	6,114,000			4,804,000
Revenues and royalties payable	2,426,000			3,165,000
Derivative contracts	6,185,000			8,320,000
Note payable-short term	133,000			—
Note payable credit facility-short term	10,000,000			—
Total current liabilities	60,072,000			42,418,000

Note payable–long term	230,000			—
Note payable credit facility-long term	90,000,000			85,000,000
Note payable–related party–long term	30,045,000			—
Derivative contracts	1,556,000			6,139,000
Asset retirement obligations	1,264,000			1,080,000
Total liabilities	183,167,000			134,637,000
Contingencies (Note 13)
Members' equity	124,600,000			114,847,000
Total liabilities and members' equity	$	307,767,000		$	249,484,000

See accompanying notes to consolidated financial statements.

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Windsor Permian LLC and Subsidiaries

Consolidated Statements of Operations

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Revenues:
Oil sales	$	14,314,000		$	1,282,000		$	42,703,000		$	1,920,000
Oil sales - related party	—			8,274,000			—			26,692,000
Natural gas sales	208,000			181,000			605,000			726,000
Natural gas sales - related party	369,000			207,000			631,000			399,000
Natural gas liquid sales	672,000			590,000			2,246,000			2,137,000
Natural gas liquid sales - related party	1,035,000			437,000			2,171,000			1,135,000
Oil and natural gas services - related party	—			—			—			1,491,000
Total revenues	16,598,000			10,971,000			48,356,000			34,500,000

Costs and expenses:
Lease operating expenses	3,613,000			2,035,000			9,187,000			5,797,000
Lease operating expenses - related party	269,000			1,084,000			830,000			1,607,000
Production taxes	716,000			244,000			2,166,000			419,000
Production taxes - related party	99,000			291,000			199,000			1,210,000
Gathering and transportation	9,000			12,000			61,000			29,000
Gathering and transportation - related party	108,000			41,000			203,000			110,000
Oil and natural gas services	—			—			—			1,207,000
Oil and natural gas services - related party	—			—			—			526,000
Depreciation, depletion and amortization	6,066,000			3,680,000			16,302,000			11,121,000
General and administrative expenses	1,314,000			129,000			2,759,000			328,000
General and administrative expenses - related party	340,000			626,000			1,709,000			1,848,000
Asset retirement obligation accretion expense	22,000			17,000			62,000			45,000
Total costs and expenses	12,556,000			8,159,000			33,478,000			24,247,000

Income from operations	4,042,000			2,812,000			14,878,000			10,253,000

Other income (expense)
Interest income	1,000			2,000			3,000			9,000
Interest expense	(1,130,000		)	(718,000		)	(3,184,000		)	(1,815,000		)
Other income - related party	671,000			—			1,729,000			—
Gain (loss) on derivative contracts	(3,148,000		)	(7,000		)	2,017,000			(35,000		)
Loss from equity investment	—			—			(67,000		)	—
Total other income (expense), net	(3,606,000		)	(723,000		)	498,000			(1,841,000		)

Net income	$	436,000		$	2,089,000		$	15,376,000		$	8,412,000

See accompanying notes to consolidated financial statements.

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Windsor Permian LLC and Subsidiaries

Consolidated Statements of Operations - Continued

(Unaudited)



Pro forma information
Net income before income taxes, as reported	$	436,000	$	2,089,000	$	15,376,000	$	8,412,000
Pro forma provision for income tax	—		—		—		—
Pro forma net income	$	436,000	2,089,000		$	15,376,000	8,412,000
Pro forma income per common share - basic and diluted	$	0.03	$	0.15	$	1.10	$	0.60
Weighted average pro forma shares outstanding - basic and diluted	14,000,000		14,000,000		14,000,000		14,000,000

See accompanying notes to consolidated financial statements.

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Windsor Permian LLC and Subsidiaries

Consolidated Statement of Changes in Members' Equity

(Unaudited)



	Total member's equity
Balance at January 1, 2012	$	114,847,000
Contributions	4,008,000
Distributions of equity method investments	(10,504,000		)
Equity based compensation	873,000
Net income	15,376,000
Balance at September 30, 2012	$	124,600,000

Balance at January 1, 2011	$	105,638,000
Contributions	710,000
Equity based compensation	259,000
Net income	8,412,000
Balance at September 30, 2011	$	115,019,000

See accompanying notes to consolidated financial statements.

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Windsor Permian LLC and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)



	Nine Months Ended September 30,
	2012			2011
Cash flows from operating activities:
Net income	$	15,376,000		$	8,412,000
Adjustments to reconcile net income to net cash provided by operating activities:
Asset retirement obligation accretion expense	62,000			45,000
Depreciation, depletion, and amortization	16,302,000			11,624,000
Amortization of debt issuance costs	347,000			235,000
(Gain) loss on derivative contracts	(2,017,000		)	35,000
Loss from equity investment	67,000			—
Equity-based compensation expense	873,000			259,000
Gain on sale of assets	(26,000		)	(23,000		)
Changes in operating assets and liabilities:
Accounts receivable	(4,256,000		)	(4,944,000		)
Accounts receivable-related party	3,736,000			(5,599,000		)
Inventories	(44,000		)	(888,000		)
Prepaid expenses and other	1,000			(202,000		)
Accounts payable and accrued liabilities	2,145,000			3,252,000
Accounts payable and accrued liabilities-related party	2,360,000			615,000
Revenues and royalties payable	(740,000		)	807,000
Revenues and royalties payable-related party	(2,404,000		)	412,000
Net cash provided by operating activities	31,782,000			14,040,000

Cash flows from investing activities:
Additions to oil and natural gas properties	(73,237,000		)	(34,664,000		)
Additions to oil and natural gas properties-related party	(6,592,000		)	(14,992,000		)
Purchase of other property and equipment	(778,000		)	(6,950,000		)
Proceeds from sale of property and equipment	26,000			55,000
Settlement of non-hedge derivative instruments	(7,025,000		)	(3,091,000		)
Receipt on derivative margins	2,325,000			3,152,000
Deconsolidation of Bison	—			(10,000		)
Proceeds from sale of membership interest in equity investment	—			6,010,000
Net cash used in investing activities	(85,281,000		)	(50,490,000		)

Cash flows from financing activities:
Proceeds from borrowings on credit facility	15,000,000			35,233,000
Proceeds from note payable – related party	30,045,000			—
Debt issuance costs	(72,000		)	(365,000		)
Initial public offering costs	(1,009,000		)	—
Contributions by members	4,008,000			710,000
Net cash provided by financing activities	47,972,000			35,578,000

Net decrease in cash and cash equivalents	(5,527,000		)	(872,000		)
Cash and cash equivalents at beginning of period	6,802,000			4,090,000
Cash and cash equivalents at end of period	$	1,275,000		$	3,218,000

See accompanying notes to consolidated financial statements.

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Windsor Permian LLC and Subsidiaries

Consolidated Statements of Cash Flows - Continued

(Unaudited)



	Nine Months Ended September 30,
	2012		2011
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest	$	2,778,000	$	1,983,000
Supplemental disclosure of non-cash transactions:
Asset retirement obligation incurred, including changes in estimate	$	141,000	$	246,000
Distribution of equity method investments	$	10,504,000	$	—
Note payable exchanged for equipment	$	411,000	$	—

See accompanying notes to consolidated financial statements.

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Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements

(Unaudited)

1. DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION

Description of the Business

Windsor Permian LLC (“Windsor”) is a limited liability company formed on October 23, 2007 to acquire, produce, develop and exploit oil and natural gas properties. As of and for the three and nine month periods ended September 30, 2012 and 2011 (the “Reporting Periods”), Windsor Permian LLC was a wholly owned subsidiary of Diamondback Energy LLC, an entity controlled by Wexford Capital LP, or Wexford. On October 11, 2012 Diamondback Energy LLC, merged with and into Diamondback Energy, Inc. and Diamondback Energy, Inc. continued as the surviving entity (the "Merger"). Neither Diamondback Energy LLC or Diamondback Energy, Inc. conducted any material business operations prior to October 11, 2012. Refer to Note 3 for information regarding the Diamondback Energy, Inc. initial public offering (“IPO”). As a limited liability company, the members of Windsor are not liable for the liabilities or other obligations of Windsor. Collectively, Windsor and its subsidiaries, Diamondback E&P LLC, formed on February 17, 2012, Bison Drilling and Field Services LLC (formerly known as Windsor Drilling LLC) through March 31, 2011, and West Texas Field Services LLC through its dissolution on June 12, 2012, are referred to in these financial statements as the “Company”.

The Company is engaged in the acquisition, exploitation, development and production of oil and natural gas properties and related sale of oil, natural gas and natural gas liquids. The Company’s reserves are located in the Southern region of the United States. The Company’s results of operations are largely dependent on the difference between the prices received for its oil, natural gas and natural gas liquids and the cost to find, develop, produce and market such resources. Oil and natural gas prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond the Company’s control. These factors include worldwide political instability, quantity of natural gas in storage, foreign supply of oil and natural gas, the price of foreign imports, the level of consumer demand and the price of available alternative fuels, among others.

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 the 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 that the disclosures are adequate to make the information presented not misleading. For a more complete understanding of our operations, financial position and accounting policies, these financial statements should be read in conjunction with the Company’s most recent annual financial statements included in Diamondback Energy, Inc.’s final prospectus (the "final prospectus") dated October 11, 2012 and filed with the SEC pursuant to Rule 424(b) under the Securities Act of 1933 on October 15, 2012.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

As of September 30, 2012 , Windsor's significant accounting policies are consistent with those discussed in Note 2 of its consolidated financial statements contained in the final prospectus.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the Reporting Periods. Significant estimates with regard to these financial statements include the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, fair value estimates and asset retirement obligations. Actual results could differ from those estimates.

Income Taxes

The operations of the Company and its subsidiaries, as limited liability companies, are not subject to federal income taxes. As appropriate, the taxable income or loss applicable to those operations is included in the federal income tax returns of the respective owners and no income tax effect is included in the accompanying consolidated financial statements. The Company is subject to margin tax in the state of Texas. During the nine months ended September 30, 2012 and 2011, there was no margin tax expense. The Company’s 2008, 2009 and 2010 federal income tax and state margin tax returns remain open to examination by tax authorities. As of September 30, 2012 and December 31, 2011, the Company had no unrecognized tax benefits that would have a material impact on the effective rate. The

Table of Contents

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Company is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the nine months ended September 30, 2012 and 2011, there was no interest or penalties associated with uncertain tax positions recognized in the Company’s consolidated financial statements.

Unaudited Pro Forma Income Taxes and Earnings Per Share

Diamondback Energy, Inc. was formed as a holding company on December 30, 2011, and did not conduct any material business operations prior to the Merger. Diamondback Energy, Inc. is a C-Corp under the Internal Revenue Code and is subject to income taxes. Accordingly, the Company computed a pro forma income tax provision as if the Company were a C-Corp since inception. The pro forma tax provision has been calculated at a rate based upon a federal corporate level tax rate and a state tax rate, net of federal benefit, incorporating permanent differences. However, on a pro forma basis, management has determined that any net deferred income tax asset would not be realizable; therefore tax expense would be zero for all periods. Additionally, upon Windsor becoming a subsidiary of Diamondback Energy, Inc. the Company will establish a net deferred tax liability for differences between the tax and book basis of the Company’s assets and liabilities, and record a corresponding “first day” tax expense to net income from continuing operations. On a pro forma basis, at September 30, 2012 the amount of this charge would have been approximately $44.2 million.

The Company has presented pro forma earnings per share for the most recent period. Pro forma basic and diluted income per share was computed by dividing net income attributable to the Company by the number of Diamondback shares of common stock attributable to the Company issued in the Merger and the Gulfport transaction, as if such shares were issued and outstanding for the nine months ended September 30, 2012.

New Pronouncements Issued but Not Yet Adopted

In December 2011, the FASB issued Accounting Standards Update No. 2011-11, which increases disclosures about offsetting assets and liabilities. New disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under GAAP and International Financial Reporting Standards related to the offsetting of financial instruments. The existing GAAP guidance allowing balance sheet offsetting, including industry-specific guidance, remains unchanged. The guidance in ASU No. 2011-11 is effective for annual and interim reporting periods beginning on or after January 1, 2013. The disclosures should be applied retrospectively for all prior periods presented. The Company does not expect the adoption of this guidance to have a significant impact on its financial position, results of operations or cash flow.

3. INITIAL PUBLIC OFFERING OF DIAMONDBACK ENERGY, INC.

On February 13, 2012, a Registration Statement on Form S-1 (SEC File No. 333-179502) was filed with the SEC relating to the proposed underwritten IPO of Diamondback Energy, Inc. Prior to the completion of the IPO, Windsor was a wholly-owned subsidiary of Diamondback Energy LLC, an entity controlled by Wexford. In connection with completion of the IPO, Diamondback Energy LLC was merged with and into Diamondback Energy, Inc. in the Merger, causing Windsor to become a wholly owned subsidiary of Diamondback Energy, Inc.

On October 11, 2012, Diamondback Energy, Inc. priced 12,500,000 shares of its common stock in its IPO at a price of $17.50 per share, and on October 12, 2012 shares of Diamondback Energy, Inc.'s common stock began trading on the Nasdaq Global Select Market under the symbol “FANG”. On October 17, 2012, Diamondback Energy, Inc. closed its IPO. On October 23, 2012, the underwriters purchased an additional 1,875,000 shares of common stock following the exercise in full of their over-allotment option. Diamondback Energy, Inc. received estimated net proceeds of $235.3 million from the sale of these shares of common stock, after deducting the underwriting discount, and used a portion of these net proceeds to repay: (i) $100.0 million of outstanding borrowings under its revolving credit facility, (ii) $63.6 million to Gulfport Energy Corporation; and (iii) $30.0 million of outstanding borrowings under its subordinated note with an affiliate of Wexford.

4. ACQUISITIONS

On May 7, 2012, Diamondback Energy, Inc. entered into an agreement with Gulfport Energy Corporation ("Gulfport") in which Gulfport agreed to sell to Diamondback Energy, Inc., subject to certain conditions, all of its oil and natural gas interests in the Permian Basin in exchange for shares of Diamondback Energy, Inc. common stock and a promissory note in a transaction referred to as the Gulfport transaction. The Gulfport transaction was completed in connection with completion of the IPO (see Note 3). In addition, Wexford agreed to cause all of the outstanding equity interests in Windsor UT LLC (“Windsor UT”) to be contributed to Windsor Permian prior to its

Table of Contents

Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

merger into Diamondback Energy, Inc. in a transaction referred to as the Windsor UT contribution. The Gulfport transaction and the Windsor UT contribution are referred to as the Transactions. The acquisition of certain property interests of Gulfport (the "Gulfport properties") will be treated as a business combination accounted for under the acquisition method of accounting with the identifiable assets recognized at fair value on the date of transfer. The Windsor UT contribution is treated as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in the accounts of the transferring entity at the date of transfer. The pro forma data presented reflect events directly attributable to the Transactions and certain assumptions the Company believes are reasonable.

The following unaudited summary pro forma combined statement of operations data of Diamondback Energy, Inc. for the three and nine month periods ended September 30, 2012 has been prepared to give effect to the Transactions as if they had occurred on January 1, 2011. The pro forma data are not necessarily indicative of financial results that would have been attained had the described transactions occurred on January 1, 2011. The pro forma data also necessarily exclude various operation expenses related to the Gulfport properties and the financial statements should not be viewed as indicative of operations in future periods. As the current operator of the properties acquired by the Company upon completion of the Gulfport transaction and the Windsor UT contribution, the Company does not expect any material impact from these transactions on its existing employees or infrastructure.



	Three Months Ended		Nine Months Ended
	September 30, 2012		September 30, 2011
	(Pro Forma)		(Pro Forma)
Pro forma total revenues	$	23,839,000	$	70,412,000
Pro forma income from operations	5,536,000		21,204,000
Pro forma net income ⁽¹⁾	$	1,930,000	$	21,702,000

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

5. PROPERTY AND EQUIPMENT

Property and equipment includes the following:



	September 30, 2012			December 31, 2011
	September 30, 2012			December 31, 2011
Oil and natural gas properties:
Subject to depletion	$	403,463,000		$	323,778,000
Not subject to depletion-acquisition costs
Incurred in 2012	5,632,000			—
Incurred in 2011	1,178,000			1,199,000
Incurred in 2009	533,000			533,000
Total not subject to depletion	7,343,000			1,732,000

Gross oil and natural gas properties	410,806,000			325,510,000
Less accumulated depreciation, depletion, amortization and impairment	(135,130,000		)	(119,167,000		)
Oil and natural gas properties, net	275,676,000			206,343,000

Other property and equipment	2,277,000			1,017,000
Less accumulated depreciation	(603,000		)	(333,000		)
Other property and equipment, net	1,674,000			684,000

Property and equipment, net of accumulated depreciation, depletion, amortization and impairment	$	277,350,000		$	207,027,000

Included in oil and gas properties at September 30, 2012 is the cumulative capitalization of $3,714,000 in general and administrative costs incurred and capitalized to the full cost pool. General and administrative costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development

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activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All general and administrative costs not directly associated with exploration and development activities were charged to expense as they were incurred. Capitalized general and administrative costs were approximately $1,068,000 and $2,843,000 for the three and nine months ended September 30, 2012 , respectively, and $375,000 and $375,000 for the three and nine months ended September 30, 2011 , respectively.

6. ASSET RETIREMENT OBLIGATION

A reconciliation of the asset retirement obligation for the nine months ended September 30, 2012 and 2011 is as follows:



	Nine Months Ended
	September 30,
	2012		2011
Asset retirement obligation, beginning of period	$	1,080,000	$	728,000
Additional liability incurred	141,000		246,000
Accretion expense	62,000		45,000
Asset retirement obligation, end of period	1,283,000		1,019,000
Less current portion	19,000		—
Asset retirement obligations - long-term	$	1,264,000	$	1,019,000

7. EQUITY METHOD INVESTMENTS

Bison Drilling and Field Services LLC

The Company held a wholly owned subsidiary, Bison Drilling and Field Services LLC (“Bison”), formerly known as Windsor Drilling LLC, formed on November 15, 2010. In addition, the Company held a wholly owned subsidiary, West Texas Field Services LLC, formed on March 2, 2010 which, on January 1, 2011, contributed all of its assets and liabilities to Bison and subsequently dissolved on June 12, 2012. Bison owns and operates drilling rigs and various oil and gas well servicing equipment.

Beginning on March 31, 2011, various related party investors contributed capital to Bison diluting the Company’s ownership interest. The Company assessed its ability to exercise financial control over Bison and based on the results of its assessment, the Company concluded it 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. Under the equity method, the Company eliminated intercompany profits or losses in relation to its continuing involvement with Bison, proportionate to its equity interest.

An entity is required to deconsolidate a subsidiary when the entity ceases to have a controlling financial interest in the subsidiary. Upon deconsolidation of a subsidiary, an entity recognizes a gain or loss on the transaction and measures any retained investment in the subsidiary at fair value. The gain or loss includes any gain or loss associated with the difference between the fair value of the retained investment in the subsidiary and its carrying amount at the date the subsidiary is deconsolidated.

The Company internally reviewed the balance sheet of Bison to determine its fair value. At the time of the transaction Bison was still a recently formed company and had not yet built value in its operations. Bison’s assets consisted primarily of four recently purchased drilling rigs. Two of the drilling rigs were purchased at market 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.

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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 has 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, a Delaware limited liability company, for a 48.6% equity interest. Through additional contributions to Muskie from a related party and various Wexford portfolio companies, the Company’s interest in Muskie decreased to 33% as of June 15, 2012. Muskie generated a loss during the period January 1, 2012 through June 15, 2012 and the Company has recorded its share of this loss.

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 has recognized the distribution of $4,067,000 as an equity transaction. Muskie continues to be a related party with the Company.

8. 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, as amended, providing for a revolving credit facility. On May 10, 2012, the revolving credit agreement was further amended to provide for the resignation of BNP, and the appointment of Wells Fargo Bank, National Association, as administrative agent for the lenders. The aggregate maximum credit amount under the revolving credit agreement is $250.0 million notwithstanding future redeterminations of 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-month period. The borrowing base was $45.0 million at December 31, 2010. The borrowing base increased throughout 2011 through various redeterminations and at December 31, 2011 the borrowing base was $100.0 million. Under the terms of the revolving credit agreement upon the closing of the IPO of Diamondback Energy Inc., the borrowing base was reduced to $90.0 million, subject to the periodic and elective borrowing base redeterminations described above. As of September 30, 2012, the Company has classified $10.0 million of the outstanding borrowings under this credit facility as short term based on management’s expectation of the timing of closing an initial public offering. As of September 30, 2012 and December 31, 2011, the Company had outstanding borrowings of $100.0 million and $85.0 million, respectively. Outstanding borrowings under the credit facility bore a weighted average interest rate of 3.72% and 3.30% as of September 30, 2012 and December 31, 2011, respectively. In connection with the IPO of Diamondback Energy, Inc., the Company repaid all outstanding borrowings under its revolving credit facility.

The agreement contains various affirmative and restrictive covenants. These covenants, among other things, prohibit additional indebtedness, sales of assets, mergers and consolidations, dividends and distributions, and changes in management and require the maintenance of various financial ratios defined below.

The current lenders and their percentage commitments in the revolving credit facility are Wells Fargo Bank, NA (45%), Amegy Bank, NA (25%), U.S. Bank, NA (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

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Notes to Consolidated Financial Statements-(Continued)

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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 4.5 to 1.0
Ratio of total debt to EBITDAX (after closing date of IPO)			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

As of July 31, 2012, the first amendment to the amended and restated credit agreement was executed, which provided for the issuance to Gulfport of the Gulfport transaction note and the payment of the Gulfport transaction note from the proceeds of the IPO.

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, including any such indebtedness evidenced by the Company’s subordinated note with an affiliate of Wexford described in more detail under “-Subordinated Note” below, 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 twelve consecutive calendar months from $250,000 to $550,000.

As of September 30, 2012 and December 31, 2011, the Company was in compliance with all financial covenants under the revolving bank credit facility as in effect on the applicable date. The lenders may accelerate all of the indebtedness under the revolving bank credit facility upon the occurrence of any event of default unless the Company cures any such default within any applicable grace period. For payments of principal and interest under the revolving bank credit facility, the Company generally has a three business day grace period, and a 30-day cure period for most covenant defaults, but not for defaults of certain specific covenants, including the financial covenants and negative covenants.

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 may, from time to time, advance up to an aggregate of $45.0 million. These advances are solely at the lender’s discretion and neither Wexford nor any of its affiliates has any commitment or obligation to provide further capital support to the Company. The note bears interest at a rate equal to LIBOR plus 0.28% or 8% per annum, whichever is lower. Interest is due quarterly in arrears beginning on July 1, 2012. Interest payments are payable in kind by adding such amounts to the principal balance of the note. The unpaid principal balance and all accrued interest on the note are due and payable in full on January 31, 2015 or the earlier completion of an initial public offering. Any indebtedness evidenced by this note is subordinate in the right of payment to any indebtedness outstanding under the Company’s revolving credit facility. As of September 30, 2012, there was $30.0 million in aggregate principal amount outstanding under this note. In connection with the IPO of Diamondback Energy, Inc., the Company repaid all outstanding borrowings under the subordinated note and the subordinated note was canceled.

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 September 30, 2012, there was $363,000 outstanding under this note.

9. DERIVATIVES

The Company has used price swap derivatives to reduce price volatility associated with certain of its oil sales. In these swaps, the Company receives the fixed price per the contract and pays a floating market price to the counterparty based on New York Mercantile Exchange Light Sweet Crude Oil pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. The counterparties to the Company’s derivative contracts are BNP Paribas (“BNP”) and Hess Corporation (“Hess”), who the Company believes are acceptable credit risks.

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

On October 4, 2011, in order to lock-in prices on the anticipated base level of production, while at the same time providing downside protection for the borrowing base under the revolving credit facility, the Company executed with BNP, West Texas Intermediate light sweet crude oil swaps on the NYMEX for calendar year 2012 and 2013 of one thousand barrels per day priced at $78.50 and $80.55, respectively.

Set forth below are the summarized amounts, terms and fair values of outstanding instruments held as of September 30, 2012 and December 31, 2011.



Description and Production Period	Volume (Bbls)	Original Strike Price (per Bbl)	September 30, 2012		December 31, 2011
			Fair Value Liability		Fair Value Liability
			Fair Value Liability		Fair Value Liability
Crude Oil Swaps:
January – August 2012	244,000	$78.50	$	—	$	5,038,000
September – November 2012	91,000	$78.50	1,337,000		1,795,000
December 2012	31,000	$78.50	454,000		594,000
January – August 2013	243,000	$80.55	3,239,000		3,823,000
September – November 2013	91,000	$80.55	1,171,000		1,298,000
December 2013	31,000	$80.55	385,000		424,000

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

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

Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the April 2008 settlements as of September 30, 2012 and December 31, 2011, respectively.



Description and Production Period	Volume (Bbls)	Original Strike Price (per Bbl)	Lock-in Price(per Bbl)	September 30, 2012		December 31, 2011
				Fair Value Liability		Fair Value Liability
				Fair Value Liability		Fair Value Liability
Crude Oil Swaps:
December 2011	22,500	$82.90	$98.50–$102.20	$	—	$	379,000
January-August 2012	180,000	$85.07	$98.25–$101.80	—		2,585,000
September-December 2012	90,000	$85.07	$98.25–$101.80	1,292,000		1,292,000

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Set forth below are the summarized amounts, terms and fair values of the locked-in swaps from the June 2009 settlements as of September 30, 2012 and December 31, 2011, respectively.



Description and Production Period	Volume (Bbls)	Original Strike Price (per Bbl)	Lock-in Price(per Bbl)	September 30, 2012		December 31, 2011
				Fair Value Asset		Fair Value Asset
				Fair Value Asset		Fair Value Asset
Crude Oil Swaps:
December 2011	7,500	$82.90	$78.42	$	—	$	34,000
January-August 2012	60,000	$85.07	$80.52	—		273,000
September- December 2012	30,000	$85.07	$80.52	136,000		136,000

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 summarizes the loss on derivative contracts included in the consolidated statements of operations:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012			2011
Unrealized loss (gain) on open non-hedge derivative instruments	$	2,252,000	$	—	$	(6,386,000	)	$	—
Loss on settlement of non-hedge derivative instruments	896,000		7,000		4,369,000			35,000
(Gain) Loss on derivative contracts	$	3,148,000	$	7,000	$	(2,017,000	)	$	35,000

The Company is required to provide margin deposits to Hess whenever its unrealized losses exceed predetermined credit limits. The Company had a margin deposit held by Hess of $0 and $2,326,000 as of September 30, 2012 and December 31, 2011, respectively, which earns interest that is remitted to the Company. As the Company has a master netting agreement with Hess, the Company has offset this margin deposit against its derivative positions.

10. EQUITY BASED COMPENSATION

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

Summarized below are the grant dates with the total exercise prices and total fair values of the underlying options:



Grants Made During the Months Ended	Membership Interest Granted	Exercise Price		Fair Value at Date of Grant
April 2011	1.00%	$	3,600,000	$	1,453,000
August 2011	1.20%	6,000,000		1,384,000
September 2011	1.25%	5,900,000		1,533,000
November 2011	0.25%	1,250,000		288,000
	3.70%	$	16,750,000	$	4,658,000

At September 30, 2012 and December 31, 2011, for outstanding options, the intrinsic value was zero and $113,000, respectively, and the weighted-average remaining contractual terms were 3.8 and 4.6 years, respectively. A 0.86% membership interest was exercisable at September 30, 2012. No options were exercisable at December 31, 2011.

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

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The fair value of the options issued was estimated using the Black-Scholes option-pricing model. One of the inputs to this model is the estimate of the fair value of the underlying membership interest on the date of grant. The other inputs include an estimate of the expected volatility of the membership interest, an option’s expected term, the risk-free interest rate over the option’s expected term, the option’s exercise price, and the Company’s expectations regarding dividends.

The Company does not have a history of market prices for its membership interests because such interests are not publicly traded. The expected volatility was determined using the historical volatility for a peer group of companies. The expected term for options issued was determined based on the contractual term of the awards. The weighted-average risk-free interest rate was based on the daily U.S. treasury yield curve rate whose term was consistent with the expected life of the options. The Company does not anticipate paying cash dividends; therefore, the expected dividend yield was assumed to be zero.

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



Expected term	5 years
Risk-free interest rate	0.96%
Expected volatility	45.5%
Expected dividend yield	0.00%

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

Equity-based compensation expense recorded for the three and nine months ended September 30, 2012 was $291,000 and $873,000, respectively. Equity-based compensation expense recorded for both the three and nine months ended September 30, 2011 was $259,000. The unrecognized equity-based compensation expense as of September 30, 2012 and December 31, 2011 was $3,240,000 and $4,113,000, respectively, related to these awards which is expected to be recognized over a weighted-average period of 2.8 and 3.6 years, respectively.

11. FAIR VALUE MEASUREMENTS

The Company measures and discloses fair value in accordance with ASC Topic 820, Fair Value Measurements and Disclosures (“ASC Topic 820”). Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.

ASC Topic 820 describes a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Company's assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Company uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities.

Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

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.

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Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2012 and December 31, 2011.



		Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3		Cash Collateral ⁽¹⁾			Net Fair Value
Financial Liabilities
		September 30, 2012
Derivative contracts		$	—	$	7,741,000	$	—	$	—		$	7,741,000

		December 31, 2011
Derivative contracts		$	—	$	16,785,000	$	—	$	(2,326,000	)	$	14,459,000
(1)	Represents the impact of netting cash collateral with a counterparty with which the right of offset exists.

Level 2 Fair Value Measurements

Derivative contracts-The fair values of the Company’s crude oil swaps are measured internally using established index prices and other sources. These are based upon, among other things, futures prices and time to maturity.

Asset Retirement and Environmental Obligations

The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410, “ Asset Retirement and Environmental Obligations” (“FASB ASC 410”). The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 6 for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred were $141,000 and $246,000 during the nine months ended September 30, 2012 and 2011, respectively.

12. 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 Company incurred total costs of $235,000 and $4,357,000 for the three months and nine months ended September, 30, 2012, respectively, and $656,000 and $3,776,000 for the three months and nine months ended September 30, 2011, 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 $620,000 and $1,772,000 for the three months and nine months ended September 30, 2012, respectively, and $473,000 and $1,382,000 for the three months and nine months ended September 30, 2011, respectively. As of September 30, 2012, the Company owed the administrative services affiliate $12,000 and as of December 31, 2011, the Company owed the administrative services affiliate $769,000. 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 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-

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related party. For the three months and nine months ended September 30, 2012, the affiliate reimbursed the Company $671,000 and $1,729,000 respectively, for services under the shared services agreement and at September 30, 2012, the affiliate owed the Company $97,000 and this amount is 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 September 30, 2012, the Company had amounts due to affiliated parties related to revenue distributions payable of $109,000. As of December 31, 2011, amounts due to affiliated parties related to prepaid drilling costs of $210,000 and revenue distributions payable of $2,303,000. These amounts are included in accounts payable-related party in the accompanying consolidated balance sheets. Each of these affiliated parties is either controlled by or was an affiliate of Wexford.

As of September 30, 2012 and December 31, 2011, amounts due from affiliates related to joint interest billings and included in accounts receivable-related party in the accompanying consolidated balance sheets is $9,299,000 and $8,990,000, respectively. Each of these affiliated parties is either controlled by or was an affiliate of Wexford.

Drilling Services

Bison has performed drilling and field services for the Company under master drilling agreements. Under the Company's most recent master drilling agreement with Bison, effective as of January 1, 2012, Bison committed to accept orders from the Company for the use of at least two of its rigs, and at September 30, 2012 was providing drilling services to the Company using two of its rigs. This master drilling agreement is terminable by either party on 30 day prior written notice, although neither party will be relieved of its respective obligations arising from a drilling contract being performed prior to the termination of the master drilling agreement. For the three months ended March 31, 2011, Bison was a wholly-owned subsidiary thus intercompany amounts were eliminated in consolidation. The Company owed Bison $923,000 as of September 30, 2012 and $154,000 as of December 31, 2011.

Completion and Well Servicing Services

The Company contracted with an affiliate for certain of its well completion services. Effective August 24, 2011, the affiliate was sold to a non-related third party. While still an affiliate of the Company, the Company was billed $2,504,000 and $12,511,000 for the three months and nine months ended September 30, 2011, respectively. Such amounts are capitalized in oil and natural gas properties in the accompanying consolidated balance sheet. At September 30, 2012 and December 31, 2011, the entity was no longer a related party.

Marketing Services

The Company entered into an agreement on March 1, 2009 with an entity under common management that purchased and received a significant portion of the Company's oil volumes. Effective January 1, 2012 the agreement with the affiliate was canceled. The Company's revenues from the affiliate were $8,274,000 and $26,692,000 for the three months and nine months ended September 30, 2011, respectively, and such amounts are included in oil sales in the accompanying consolidated statements of operations. As of December 31, 2011, the Company had an accounts receivable-related party balance with the affiliate of $4,132,000 and such amount is included in the accompanying consolidated balance sheets.

MidMar

The Company is party to a gas purchase agreement, dated May 1, 2009, as amended, with MidMar Gas LLC, or MidMar, an entity affiliated with Wexford that owns a gas gathering system and processing plant in the Permian Basin. Under this agreement, MidMar is obligated to purchase from the Company, and the Company is obligated to sell to MidMar, all of the gas conforming to certain quality specifications produced from certain of the Company's Permian Basin acreage. Following the expiration of the initial ten-year term, the agreement will continue on a year-to-year basis until terminated by either party on 30 days written notice. Under the gas purchase agreement, MidMar is obligated to pay the Company 87% of the net revenue received by MidMar for all components of the Company's dedicated gas, including the liquid hydrocarbons, and the sale of residue gas, in each case extracted, recovered or otherwise processed at MidMar's gas processing plant, and 94.56% of the net revenue received by MidMar from the sale of such gas components and residue gas, extracted, recovered or otherwise processed at Chevron's Headlee

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Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

plant. For the three months and nine months ended September 30, 2012, MidMar paid the Company $803,000 and $2,187,000, respectively. For the three months and nine months ended September 30, 2011, MidMar paid the Company $556,000 and $1,316,000, respectively. As of September 30, 2012 and December 31, 2011, MidMar owed the Company $645,000 and $462,000, respectively, for the Company's portion of the net proceeds from the sale of gas, gas products and residue gas.

Midland Lease

Effective May 15, 2011, the Company occupied corporate office space in Midland, Texas under a lease with a five-year term. The office space is owned by an entity controlled by an affiliate of Wexford. For the three months and nine months ended September 30, 2012, the Company paid $46,000 and $117,000, respectively, and for the three months and nine months ended September 30, 2011, the Company paid $8,000 and $16,000, respectively. The current monthly rent under the lease will increase approximately 4% annually on June 1 of each year during the lease term.

Oklahoma City Lease

Effective January 1, 2012, the Company occupied corporate office space in Oklahoma City, Oklahoma under a lease with a 67 month term. The office space is owned by an entity controlled by an affiliate of Wexford. For the three months and nine months ended September 30, 2012, the Company paid $60,000 and $267,000, respectively. The monthly rent under the lease increased to $17,000 per month on August 1, 2012 with no further escalations for the remaining term of the lease.

Professional Services from Wexford

From time to time, Wexford provides certain professional services to the Company. For the three months and nine months ended September 30, 2012, the Company incurred total costs of $25,000 and $119,000, respectively. As of September 30, 2012 the Company owed Wexford $22,000 and this amount is included in accounts payable-related party in the accompanying consolidated balance sheets. The Company did not incur any costs for professional services from Wexford during the nine months ended September 30, 2011.

13. CONTINGENCIES

The Company could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations.

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Windsor Permian LLC and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

14. SUBSEQUENT EVENTS

On October 17, 2012 Diamondback Energy, Inc. closed its IPO. See Note 3 for further details.

Advisory Services Agreement

Diamondback Energy, Inc. entered into an advisory services agreement (the "Advisory Services Agreement") with Wexford, dated as of October 11, 2012, under which Wexford will provide Diamondback Energy, Inc. 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 the completion of the IPO, 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 Diamondback Energy, Inc. terminates such agreement, it is obligated to pay all amounts due through the remaining term. In addition, Diamondback Energy, Inc. agreed to pay Wexford to-be-negotiated market-based fees approved by Diamondback's independent directors for such services as may be provided by Wexford at Diamondback Energy, Inc.'s request in connection with future acquisitions and divestitures, financings or other transactions in which Diamondback Energy, Inc. may be involved. The services provided by Wexford thereunder will not extend to Diamondback Energy, Inc.'s day-to-day business or operations. Diamondback Energy, Inc. 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.

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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 the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section and audited consolidated financial statements and related notes thereto included in our final prospectus dated October 11, 2012 and filed with the Securities and Exchange Commission, or SEC, pursuant to Rule 424(b) under the Securities Act of 1933, or the Securities Act, on October 15, 2012, and with the unaudited consolidated financial statements and related notes thereto presented in this Quarterly Report on Form 10-Q.

CAUTIONARY NOTE 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 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 report on Form 10-Q and detailed in our final prospectus dated October 11, 2012 and filed with the SEC pursuant to Rule 424(b) on October 15, 2012, could affect our actual results and cause our actual results to differ materially from expectations, estimates, or assumptions expressed in, forecasted in, 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.

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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.

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.

We began operations in December 2007 with the acquisition of 4,174 net acres of oil and natural gas properties in the Permian Basin in West Texas. Subsequently, we acquired additional acreage which brought our total net acreage position in the Permian Basin to approximately 31,052 net acres at September 30, 2012.

On October 11, 2012, prior to the pricing of our initial public offering, Wexford Capital LP, or Wexford, our equity sponsor, caused all the outstanding equity interests in Windsor UT LLC, or Windsor UT, to be contributed to us. Windsor UT owns 2,489 net acres in the Permian Basin of which we are the operator. Also on October 11, 2012, we acquired all of the oil and natural gas properties of Gulfport Energy Corporation, or Gulfport, located in the Permian Basin in exchange for (i) 7,914,036 shares of our common stock and (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. We are the operator of the acreage acquired by us from Gulfport. The aggregate consideration payable to Gulfport is subject to a post-closing cash adjustment. If the closing date for the Gulfport transaction had been September 30, 2012, based on preliminary estimates we believe that we would have owed Gulfport approximately $16.0 million for this post-closing adjustment.

On October 11, 2012, after giving effect to the contribution to us of Windsor UT and our acquisition of Gulfport’s oil and natural gas assets in the Permian Basin, our net acreage position in the Permian Basin was approximately 51,709 net acres.

On October 11, 2012, we priced, and on October 17, 2012 we closed, our initial public offering of 12,500,000 shares of our common stock at a price to the public of $17.50 per share. On October 23, 2012, the underwriters purchased an additional 1,875,000 shares of our common stock following the exercise in full of their over-allotment option. We received net proceeds of approximately $235.3 million from the sale of these shares of common stock (net of estimated expenses and underwriting discounts and commissions).

Basis of Presentation

Diamondback Energy, Inc. was incorporated on December 30, 2011 in Delaware as a holding company and did not conduct any material business operations prior to the transaction described above. Accordingly, our historical financial information included in this report pertains to the assets, liabilities, revenues and expenses of Windsor Permian LLC, or Windsor Permian. Windsor Permian was a wholly-owned subsidiary of Diamondback Energy LLC, which was an entity controlled by our equity sponsor, Wexford. On October 11, 2012, Wexford caused Diamondback Energy LLC to be merged with and into Diamondback Energy, Inc. and Diamondback Energy, Inc. continued as the surviving entity. Since the contribution of Windsor UT to us and our acquisition of assets from Gulfport occurred on October 11, 2012, the financial results of Windsor UT and of the assets and operations acquired from Gulfport are not included in the historical financial information contained in this report and will only be included in our financial results for periods subsequent to their acquisition on October 11, 2012.

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As of April 30, 2012, Windsor Permian held a 22% interest in Bison Drilling and Field Services LLC, or Bison, and a 33% interest in Muskie Holdings LLC, or Muskie. Bison owns drilling rigs and various oil and natural gas well servicing equipment and performs drilling and field services for us. Muskie owns certain assets, real estate and rights in a lease for land that is prospective for oil and natural gas fracture grade sand. Windsor Permian’s interests in Bison and Muskie were distributed to Windsor Permian’s sole member in June 2012 so we may focus our activities on our oil and natural gas exploration and development activities. We recorded revenues of $1.5 million attributable to Bison in our consolidated statements of operations during the first quarter of 2011. Muskie was formed in 2011, and we recorded a loss from equity method investments of zero for the three months and nine months ended September 30, 2011. For the three months and nine months ended September 30, 2012, we recorded a loss from equity method investments of zero and $67,000, respectively. The interests in Bison and Muskie are reflected in “Investments-equity method” on our consolidated balance sheets. For additional information regarding Bison and Muskie, see Note 7 to our consolidated financial statements appearing elsewhere in this report.

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 September 30, 2012, Windsor Permian’s average daily production was 1,780 barrels per day, or Bbls/d, of oil, 2,220 thousand cubic feet per day, or Mcf/d, of natural gas and 488 Bbls/d of natural gas liquids, an increase of 7%, or 163 BOE/d over the three months ended June 30, 2012, consisting of 1,793 Bbls/d of oil, 1,734 Mcf/d of natural gas and 392 Bbls/d of natural gas liquids. On a pro forma basis for the Windsor UT and Gulfport transactions, our daily production for the three months ended September 30, 2012 would have been 2,559 Bbls/d of oil, 3,400Mcf/d of natural gas and 744 Bbls/d of natural gas liquids, an increase of 6%, or 232 BOE/d, over the pro forma results for the three months ended June 30, 2012, consisting of 2,579 Bbls/d of oil, 2,757 Mcf/d of natural gas and 599 Bbls/d of natural gas liquids.

During the three months ended September 30, 2012, we drilled 9 gross (6 net) wells, and participated in an additional 1 gross (0.4 net) non-operated well, in the Permian Basin. On a pro forma basis for the Windsor UT and Gulfport transactions, we would have drilled 10 gross (9 net) wells, and participated in an additional 1 gross (0.4 net) non-operated well, in the Permian Basin.

Factors that can Significantly Affect our Results

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

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Results of Operations

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(unaudited)						(unaudited)
Operating Results:
Revenues
Oil and natural gas revenues	$	16,598,000		$	10,971,000		$	48,356,000		$	33,009,000
Other revenue	—			—			—			1,491,000
Operating Expenses
Lease operating expense	3,882,000			3,119,000			10,017,000			7,404,000
Production taxes	815,000			535,000			2,365,000			1,629,000
Gathering and transportation expense	117,000			53,000			264,000			139,000
Oil and natural gas services	—			—			—			1,733,000
Depreciation, depletion and amortization	6,066,000			3,680,000			16,302,000			11,121,000
General and administrative	1,654,000			755,000			4,468,000			2,176,000
Asset retirement obligation accretion expense	22,000			17,000			62,000			45,000
Total expenses	12,556,000			8,159,000			33,478,000			24,247,000
Income from operations	4,042,000			2,812,000			14,878,000			10,253,000
Net interest income (expense)	(1,129,000		)	(716,000		)	(3,181,000		)	(1,806,000		)
Other income	671,000			—			1,729,000			—
Gain (loss) on derivative contracts	(3,148,000		)	(7,000		)	2,017,000			(35,000		)
Loss from equity investment	—			—			(67,000		)	—
Total other income (expense)	(3,606,000		)	(723,000		)	498,000			(1,841,000		)
Net income	$	436,000		$	2,089,000		$	15,376,000		$	8,412,000

Production Data:
Oil (Bbls)	163,740			107,848			474,915			307,179
Natural gas (Mcf)	204,225			91,570			494,396			274,432
Natural gas liquids (Bbls)	44,851			16,851			110,039			61,671
Combined volumes (Boe)	242,629			139,961			667,353			414,589
Daily combined volumes (Boe/d)	2,637			1,521			2,436			1,519

Average Prices ⁽¹⁾ :
Oil (per Bbl)	$	87.42		$	88.61		$	89.92		$	93.14
Natural gas (per Mcf)	2.83			4.24			2.50			4.10
Natural gas liquids (per Bbl)	38.06			60.95			40.14			53.06
Combined (per BOE)	68.41			78.39			72.46			79.62

(1) After giving effect to our hedging arrangements in effect during the period ended, the average prices per Bbl of oil and per BOE were $81.95 and $64.72, respectively, during the three months ended September 30, 2012, and $88.54 and $78.33, respectively, during the three months ended September 30, 2011. After giving effect to our hedging arrangements in effect during the period ended, the average prices per Bbl of oil and per BOE were $80.72 and $65.91, respectively, during the nine months ended September 30, 2012, and $93.03 and $79.53, respectively, during the nine months ended September 30, 2011.

Comparison of the Three Months Ended September 30, 2012 and 2011

Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $5,627,000, or 51%, to $16,598,000 for the three months ended September 30, 2012 from $10,971,000 for the three months ended September 30, 2011. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 1,116 BOE/d during the three months ended September 30, 2012 as compared to the same period in 2011. The total increase in revenue of approximately $5,627,000 is largely attributable to higher oil,

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natural gas liquids and natural gas production volumes for the three months ended September 30, 2012 as compared to the three months ended September 30, 2011. Production increased by 55,892 Bbls of oil, 28,000 Bbls of natural gas liquids and 112,655 Mcf of natural gas for the three months ended September 30, 2012 as compared to the three months ended September 30, 2011. The net dollar effect of the decreases in prices of approximately $1,509,000 (calculated as the change in quarter-to-quarter average prices times current quarterly production volumes of oil, natural gas liquids and natural gas) and the net dollar effect of the increase in production of approximately $7,136,000 (calculated as the increase in quarter-to-quarter volumes for oil, natural gas liquids and natural gas times the prior year quarterly average prices) are shown below.



		Change in prices			Production volumes ⁽¹⁾		Total net dollar effect of change (in thousands)
	Effect of changes in price:
	Oil	$	(1.19	)	163,740		$	(194	)
	Natural gas liquids	$	(22.89	)	44,851		$	(1,027	)
	Natural gas	$	(1.41	)	204,225		$	(288	)
	Total revenues due to change in price						$	(1,509	)
		Change in production volumes ⁽¹⁾			Prior period Average Prices		Total net dollar effect of change (in thousands)
	Effect of changes in price:
	Oil	55,892			$	88.61	$	4,952
	Natural gas liquids	28,000			$	60.95	$	1,707
	Natural gas	112,655			$	4.24	$	477
	Total revenues due to change in price						$	7,136
	Total change in revenues						$	5,627
(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 $3,882,000 for the three months ended September 30, 2012, an increase of $763,000, or 24%, from $3,119,000 for the three months ended September 30, 2011. The increase is due to increased drilling activity, which resulted in additional producing wells for the three months ended September 30, 2012 as compared to the three months ended September 30, 2011. Our lease operating expense during both periods was also adversely impacted by the cost of processing and treating non-hydrocarbon gases from certain of our wells that came on-line in 2011. During the fourth quarter of 2012, we intend to complete both oil and water gathering systems that will transport this gas stream to a sour gas pipeline, thereby eliminating the monthly processing and treating expense, and reducing water trucking, respectively. We believe that the completion of the gathering systems will help reduce our lease operating expense in future periods.

Production Tax Expense. Production taxes as a percentage of oil and natural gas sales were 4.9% for both the three months ended September 30, 2012, and 2011. Production taxes are primarily based on the market value of our production at the wellhead and may vary across the different counties in which we operate. Total production taxes increased $280,000, from $535,000 during the three months ended September 30, 2011 to $815,000 during the three months ended September 30, 2012, as a result of higher production and an increase in the market value of our production.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $2,386,000, or 65%, from $3,680,000 for the three months ended September 30, 2011 to $6,066,000 for the three months ended September 30, 2012. This increase was due to an increase in our full cost pool as a result of our capital activities.

General and Administrative Expense. General and administrative expense increased $899,000 from $755,000 for the three months ended September 30, 2011 to $1,654,000 for the three months ended September 30, 2012. This increase was due primarily to increases in salary and equity based compensation expense and legal and professional service expenses related to our IPO. 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

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overhead payments due to increased drilling activity. In connection with our initial public offering, we incurred a non-recurring charge to our fourth quarter general and administrative expense of approximately $3.0 million for executive bonuses associated with such offering.

Net Interest Expense. Net interest expense for the three months ended September 30, 2012 was $1,129,000, as compared to $716,000 for the three months ended September 30, 2011, an increase of $413,000. This increase is due to an increase in our weighted average outstanding borrowings under our credit agreement to $100,000,000 for the three months ended September 30, 2012 from $75,526,000 for the same period in 2011.

Comparison of the Nine Months Ended September 30, 2012 and 2011

Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $15,347,000, or 46%, to $48,356,000 for the nine months ended September 30, 2012 from $33,009,000 for the nine months ended September 30, 2011. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 917 BOE/d during the nine months ended September 30, 2012 as compared to the same period in 2011. The total increase in revenue of approximately $15,347,000 is largely attributable to higher oil, natural gas liquids and natural gas production volumes for the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011. Production increased by 167,736 Bbls of oil, 48,368 Bbls of natural gas liquids and 219,964 Mcf of natural gas for the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011. The net dollar effect of the decreases in prices of approximately $3,745,000 (calculated as the change in period-to-period average prices times current period production volumes of oil, natural gas liquids and natural gas) and the net dollar effect of the increase in production of approximately $19,902,000 (calculated as the increase in period-to-period volumes for oil, natural gas liquids and natural gas times the period average prices) are shown below.



		Change in prices			Production volumes ⁽¹⁾		Total net dollar effect of change (in thousands)
	Effect of changes in price:
	Oil	$	(3.23	)	474,915		$	(1,533	)
	Natural gas liquids	$	(12.92	)	110,039		$	(1,421	)
	Natural gas	$	(1.60	)	494,396		$	(791	)
	Total revenues due to change in price						$	(3,745	)
		Change in production volumes ⁽¹⁾			Prior period Average Prices		Total net dollar effect of change (in thousands)
	Effect of changes in price:
	Oil	167,736			$	93.14	$	15,624
	Natural gas liquids	48,368			$	53.06	$	2,566
	Natural gas	219,964			$	4.10	$	902
	Total revenues due to change in price						$	19,092
	Total change in revenues						$	15,347
(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 $10,017,000 for the nine months ended September 30, 2012, an increase of $2,613,000, or 35%, from $7,404,000 for the nine months ended September 30, 2011. The increase is due to increased drilling activity, which resulted in additional producing wells for the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011. Our lease operating expense during both periods was also adversely impacted by the cost of processing and treating non-hydrocarbon gases from certain of our wells that came on-line in 2011. During the fourth quarter of 2012, we intend to complete both oil and water gathering systems that will transport this gas stream to a sour gas pipeline, thereby eliminating the monthly processing and treating expense, and reducing water trucking, respectively. We believe that the completion of the gathering systems will help reduce our lease operating expense in future periods.

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Production Tax Expense. Production taxes as a percentage of oil and natural gas sales were 4.9% for both the nine months ended September 30, 2012, and 2011. Production taxes are primarily based on the market value of our production at the wellhead and may vary across the different counties in which we operate. Total production taxes increased $736,000, from $1,629,000 during the nine months ended September 30, 2011 to $2,365,000 during the nine months ended September 30, 2012, as a result of higher production and an increase in the market value of our production.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $5,181,000, or 47%, from $11,121,000 for the nine months ended September 30, 2011 to $16,302,000 for the nine months ended September 30, 2012. This increase was due to an increase in our full cost pool as a result of our capital activities.

General and Administrative Expense. General and administrative expense increased $2,292,000 from $2,176,000 for the nine months ended September 30, 2011 to $4,468,000 for the nine months ended September 30, 2012. This increase was due primarily to increases in salary and equity based compensation expense, legal and professional service expenses related to our IPO, and contract labor. 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 payments due to increased drilling activity. In connection with our initial public offering, we incurred a non-recurring charge to our fourth quarter general and administrative expense of approximately $3.0 million for executive bonuses associated with such offering.

Net Interest Expense. Net interest expense for the nine months ended September 30, 2012 was $3,181,000, as compared to $1,806,000 for the nine months ended September 30, 2011, an increase of $1,375,000. This increase is due to an increase in our weighted average outstanding borrowings under our credit agreement to $97,330,000 for the nine months ended September 30, 2012 from $63,223,000 for the same period in 2011.

Liquidity and Capital Resources

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

Liquidity and cash flow

Our cash flows for the nine months ended September 30, 2012 and 2011 are presented below:



	Nine Months Ended September 30,
	2012			2011
Net cash provided by operating activities	$	31,782,000		$	14,040,000
Net cash used in investing activities	(85,281,000		)	(50,490,000		)
Net cash provided by financing activities	$	47,972,000		$	35,578,000
Net change in cash	$	(5,527,000	)	$	(872,000	)

Operating Activities

Net cash provided by operating activities was $31,782,000 for the nine months ended September 30, 2012 as compared to $14,040,000 for the nine months ended September 30, 2011. The increase in operating cash flows is due to an overall increase in production revenues, partially offset by increased expenses. The increase in production is largely a result of our increased drilling activities throughout 2012 and 2011. For a summary of our commodity prices, production, costs and expenses, refer to the “ Results of Operations ” of this Item 2. For additional detail of changes in operating assets and liabilities, see the statement of consolidated cash flows in Item 1, Financial Statements of this Form 10-Q.

Investing Activities

We used cash for investing activities of $85,281,000 and $50,490,000 during the nine months ended September 30, 2012 and 2011, respectively.

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During the nine months ended September 30, 2012, we spent $71,881,000 on capital expenditures in conjunction with our drilling program in which we participated in the drilling of 33 gross (24 net) wells. We spent an additional $7,948,000 on leasehold costs, $778,000 for the purchase of other property and equipment and $4,700,000, net, on the settlement of derivative transactions.

Our investing activities for the nine months ended September 30, 2012 and 2011 are summarized in the following table:



	Nine Months Ended September 30,
	2012			2011
Drilling and completion of wells	$	(71,881,000	)	$	(47,775,000	)
Purchase of leasehold acquisitions	(7,948,000		)	(1,881,000		)
Purchase of other property and equipment	(778,000		)	(6,950,000		)
Proceeds from sale of property and equipment	26,000			55,000
Settlement of non-hedge derivative instruments	(7,025,000		)	(3,091,000		)
Receipt (payment) on derivative margins	2,325,000			3,152,000
Proceeds from equity investment, net	—			6,000,000
Net cash used in investing activities	$	(85,281,000	)	$	(50,490,000	)

Financing Activities

Net cash provided by financing activities for the nine months ended September 30, 2012 was $47,972,000 as compared to $35,578,000 for the first nine months of 2011. During the first nine months of 2012 and 2011, we borrowed $15,000,000 and $35,233,000, respectively, under our revolving credit facility. During the first nine months of 2012, we borrowed $30,045,000 under our subordinate note with Wexford, our equity sponsor. During the first nine months of 2012 and 2011, we received capital contributions from our members of $4,008,000 and $710,000, respectively. These proceeds were used primarily to fund our drilling costs and purchase property and equipment. During the nine months ended September 30, 2012, we paid $1,009,000 for costs associated with our initial public offering.

Credit Facility

On October 15, 2010, we entered into a secured loan agreement with BNP Paribas, or BNP, as the administrative agent, sole book runner and lead arranger. 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 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 us that is based on the prime, LIBOR or federal funds rate plus margins ranging from 1.25% to 3.50% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base.

Principal may be optionally repaid from time to time and is required to be paid (a) if the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise and (b) at the maturity date of October 15, 2014. We are obligated to pay a quarterly commitment fee equal to 0.5% per year of the unused portion of the borrowing base. The loan is secured by substantially all of our assets. The borrowing base is re-determined semi-annually with effective dates of April 1st and October 1st. In addition, we may request up to three additional redeterminations of the borrowing base during any 12-month period. The borrowing base was $45.0 million at December 31, 2010. The borrowing base was increased several times during 2011 as a result of redeterminations and at December 31, 2011 the borrowing base was $100.0 million. Under the terms of the revolving credit agreement upon the closing of our initial public offering on October 15, 2012, the borrowing base was reduced to $90.0 million, subject to the periodic and elective borrowing base redeterminations described above. We expect that our borrowing base will be increased above the $90.0 million borrowing base level as a result of our acquisition of the oil and gas properties included in the Gulfport transaction and those properties owned by Windsor UT. Notwithstanding future redeterminations of the borrowing base, the aggregate maximum credit amount under the revolving credit agreement is $250.0 million. As of September 30, 2012, the Company has classified $10.0 million of the outstanding borrowings under this credit facility as short term based on management’s expectation of the closing of our initial public offering. As of September 30, 2012 and December 31, 2011, the Company had outstanding borrowings of $100.0 million and $85.0 million, respectively. Outstanding borrowings under the credit facility bore a weighted average interest rate of 3.72% and 3.30% as of September 30, 2012 and December 31, 2011,

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respectively. We repaid all outstanding borrowings under our revolving credit facility with a portion of the net proceeds from our initial public offering.

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

As of July 24, 2012, our 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 4.5 to 1.0
Ratio of total debt to EBITDAX (after closing date of IPO)			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

Our revolving credit agreement defines EBITDAX, for any period, as the sum of our consolidated net income for such period plus the following expenses or charges to the extent deducted from our consolidated net income 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 our consolidated net income.

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, including any such indebtedness evidenced by the Company’s subordinated note with an affiliate of Wexford described in more detail under “-Subordinated Note” below, waived compliance with our current ratio covenant for the quarter ending September 30, 2012 and increased the aggregate limitation on lease payments during any period of twelve consecutive months from $250,000 to $550,000.

As of September 30, 2012 and December 31, 2011, we were in compliance with all financial covenants under the revolving bank credit facility as in effect on the applicable date. The lenders may accelerate all of the indebtedness under the revolving bank credit facility upon the occurrence of any event of default unless the Company cures any such default within any applicable grace period. For payments of principal and interest under the revolving bank credit facility, the Company generally has a three business day grace period, and a 30-day cure period for most covenant defaults, but not for defaults of certain specific covenants, including the financial covenants and negative covenants.

Subordinated Note

Effective May 14, 2012, we executed an unsecured subordinated note with an affiliate of Wexford pursuant to which, as amended, the Wexford affiliate could, from time to time, advance up to an aggregate $45.0 million. These advances were solely at Wexford’s discretion and neither Wexford nor any of its affiliates had any commitment or obligation to provide further capital support to us. 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 our initial public offering. Any indebtedness evidenced by this note was subordinate in the right of payment to any indebtedness outstanding under our revolving credit facility. As of September 30, 2012, there was $30.0 million in

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aggregate principal amount outstanding under this note. We repaid the outstanding borrowings under this note in full on October 15, 2012, with a portion of the net proceeds from our initial public offering and the note was canceled.

Capital Requirements and Sources of Liquidity

We currently anticipate our 2012 capital budget for drilling and infrastructure will be approximately $150.0 million to $160.0 million after giving pro forma effect to the Windsor UT and Gulfport transactions. We intend to allocate these expenditures as follows:


•	$126.0 million for the drilling and completion of operated wells;


•	$11.0 million for our participation in the drilling and completion of non-operated wells;


•	$6.0 million for leasehold interest and property acquisitions; and


•	$12.0 million for the construction of infrastructure to support production, including investments in water disposal infrastructure and gathering line projects.

During the nine months ended September 30, 2012, our actual aggregate capital expenditures for drilling, infrastructure and leasehold acquisitions were $79.8 million.

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

Based upon current oil and natural gas price expectations for 2012, we believe that our cash flow from operations, proceeds from our initial public offering and borrowings under our revolving credit facility will be sufficient to fund our operations through year-end 2013. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. We cannot assure you that operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our capital expenditure budget for 2012 allocates $6.0 million to leasehold interest and property acquisitions. In the event we make additional acquisitions and the amount of capital required is greater than the amount we have available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures and/or seek additional capital. If we require additional capital for that or other reasons, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financings, asset sales, offerings of debt and equity securities or other means. We cannot assure you that needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our current drilling programs, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves.

Critical Accounting Policies

There have been no changes in our critical accounting policies from those disclosed in our final prospectus dated October 11, 2012 and filed with the SEC on October 15, 2012.

Recent accounting pronouncements

Fair Value

In December 2011, the FASB issued Accounting Standards Update No. 2011-11, which increases disclosures about offsetting assets and liabilities. New disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under GAAP and International Financial Reporting Standards related to the offsetting of financial instruments. The existing GAAP guidance allowing balance sheet offsetting, including industry-specific guidance, remains unchanged. The guidance in ASU No. 2011-11 is effective for annual and interim reporting periods beginning on or after January 1, 2013. The disclosures should be applied retrospectively for all prior periods presented. We do not expect the adoption of this new guidance to have a significant impact on our financial position, results of operations or cash flow.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

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

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

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

At September 30, 2012, we had a net liability derivative position of $7,741,000 related to our price swap derivatives. Following our IPO, we have continued to monitor commodity prices. As these prices are approaching our current swap contract pricing and taking into account the transaction costs associated with replacing the existing swap contracts, we have determined not to settle our existing swap contracts at this time.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from joint interest receivables (approximately $12,278,000 at September 30, 2012) and receivables from the sale of our oil and natural gas production (approximately $5,817,000 at September 30, 2012).

We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. For the nine months ended September 30, 2012, three purchasers accounted for more than 10% of our revenue: Plains Marketing, L.P. (59%); Occidental Energy Marketing, Inc. (12%); and Andrews Oil Buyers Inc. (12%). For the year ended December 31, 2011, Windsor Midstream LLC, an entity controlled by Wexford, accounted for approximately 78% of our revenue. No other customer accounted for more than 10% of our revenue during these periods.

Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells. At September 30, 2012, we had two customers that represented approximately 78% of our total joint operations receivables. At December 31, 2011, we had one customer that represented approximately 68% of our total joint operations receivables.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facility with BNP. The terms of our revolving credit facility with BNP provide for interest on borrowings at a floating rate equal to prime, LIBOR or federal funds rate plus margins ranging from 1.25% to 3.50%

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depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. Borrowings under the credit facility bore interest at a weighted average rate of 3.72% as of September 30, 2012. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our net income (loss) of approximately $1.0 million, based on the $100.0 million outstanding in the aggregate under our revolving credit facility with Wells Fargo as of September 30, 2012, and assuming no interest is capitalized. Pending use of the net proceeds from this offering to fund our exploration and development activities and for general corporate purposes, we repaid the outstanding borrowings under our revolving credit facility.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Control and Procedures . Under the direction of our Chief Executive Officer and Vice President and Chief Financial Officer, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act, that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Vice President and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

As of September 30, 2012, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Vice President and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Vice President and Chief Financial Officer have concluded that as of September 30, 2012, our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over financial reporting that occurred during our third quarter ended September 30, 2012 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

PART II. OTHER INFORMATION


ITEM 1.	LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS.

Our business faces many risks. Any of the risks discussed in this Form 10-Q and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.

For a discussion of our potential risks and uncertainties, see the information in our final prospectus dated October 11, 2012 and filed with the SEC pursuant to Rule 424(b) under the Securities Act on October 15, 2012. There have been no material changes in our risk factors from those described in our prospectus filed pursuant to Rule 424(b) on October 15, 2012.


ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS


(a)	On October 11, 2012, in connection with the merger of Diamondback Energy LLC with and into Diamondback Energy, Inc., we issued 14,697,496 shares of our common stock to DB Energy Holdings LLC. In addition, on October 11, 2012, we issued 7,914,036 shares of our common stock to Gulfport in

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connection with Gulfport’s contribution to us of all of Gulfport’s oil and natural gas properties located in the Permian Basin.

The shares of our common stock described in this Item 2 were issued in reliance upon the exemption from the registration requirements of the Securities Act provided by Section 4(2) of the Securities Act as sales by an issuer not involving any public offering.

(b)

On October 11, 2012, our registration statement on Form S-1 (File No. 333-179502) was declared effective for our initial public offering, and on October 17, 2012, we consummated our initial public offering consisting of 12,500,000 shares of our common stock issued and sold by us at a public offering price of $17.50 per share. On October 23, 2012, we settled the underwriters’ exercise of their over-allotment option for an additional 1,875,000 shares issued and sold by us at a public offering price of $17.50 per share. Credit Suisse Securities (USA) LLC acted as the representative of the underwriters in the offering. Following the sale of the shares in connection with the closing of our initial public offering, the offering terminated. As a result of the offering, including the underwriters’ over-allotment option, we received total net proceeds of approximately $235.3 million, after deducting underwriting discounts and commissions of approximately $14.4 million and total estimated offering expenses of approximately $1.9 million. No payments for such expenses were made directly or indirectly to (i) any of our officers or directors or their associates, (ii) any persons owning 10% or more of any class of our equity securities or (iii) any of our affiliates. Of the net proceeds from our initial public offering, we used:


•	$100.0 million to repay the outstanding borrowings under our revolving credit facility;


•	approximately $63.6 million to repay the Gulfport transaction note; and


•	$30.0 million to repay the outstanding borrowings under our subordinated note with an affiliate of Wexford.

We intend to use the balance of the proceeds from our initial public offering to fund a portion of our exploration and development activities and for general corporate purposes, which may include leasehold interest and property acquisitions, working capital and the post-closing cash adjustment payable to Gulfport under the terms of the Gulfport transaction.


(c)	We do not have a share repurchase program, and during the three months ended September 30, 2012, we did not purchase any shares of our common stock.


ITEM 3.	DEFAULTS UPON SENIOR SECURITIES

Not applicable.


ITEM 4.	MINE SAFETY DISCLOSURES.

Not applicable.


ITEM 5.	OTHER INFORMATION

(a) On November 14, 2012, Paul Jacobi resigned as a director of our Company, effective immediately. On November 14, 2012, our board of directors, upon the recommendation of its nominating and corporate governance committee, appointed Travis D. Stice, our Chief Executive Officer, as a director of our Company to fill the vacancy on the board of directors created by Mr. Jacobi’s resignation. Mr. Stice will assume and perform his duties and responsibilities as a director, in addition to his duties as our Chief Executive Officer, effective immediately.

Mr. Stice, 50, has served as our Chief Executive Officer since January 2012. Prior to his current position with us, he served as our President and Chief Operating Officer from April 2011 to January 2012. Mr. Stice has also served on the board of managers of MidMar Gas LLC, or MidMar, an entity that owns a gas gathering system and processing plant, since 2011 and as Vice President and Secretary of MidMar since April 2012. From November 2010 to April 2011, Mr. Stice served as a Production Manager of Apache Corporation, an oil and gas exploration company. Mr. Stice served as a Vice President of Laredo Petroleum Holdings, Inc, an oil and gas exploration company, from September 2008 to September 2010. From April 2006 until August 2008, Mr. Stice served as a Development Manager of ConocoPhillips/Burlington Resources Mid-Continent Business Unit, an oil and gas

exploration company. Prior to that, Mr. Stice held a series of positions at Burlington Resources, an oil and gas exploration company, most recently as a General Manager, Engineering, Operations and Business Reporting of its Mid Continent Division from January 2001 until Burlington Resources’ acquisition by ConocoPhillips in March 2006. Mr. Stice has over 26 years of industry experience in production operations, reservoir engineering, production engineering and unconventional oil and gas exploration and over 18 years of management experience. Mr. Stice graduated from Texas A&M University with a Bachelor of Science degree in Petroleum Engineering. Mr. Stice is a registered engineer in the State of Texas, and is a 25-year member of the Society of Petroleum Engineers.

As a Chief Executive Officer of our Company, Mr. Stice is a party to an employment agreement with us, the terms of which are described in our final prospectus dated October 11, 2012, filed with the SEC pursuant to Rule 424(b) under the Securities Act on October 15, 2012, which description is incorporated herein by reference. Mr. Stice will not receive any additional compensation from us for his services as a director.

As indicated above, Mr. Stice has served as a manager on MidMar’s board of managers since April 2011 and as Vice President and Secretary of MidMar since April 2012. A description of our relationships and related party transactions with MidMar is set forth in our Rule 424(b) prospectus filed with the SEC on October 15, 2012, which description is incorporated herein by reference.

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ITEM 6. EXHIBITS



Exhibit Number		Description


1.1		Underwriting Agreement, dated October 11, 2012, by and between Diamondback Energy, Inc. and Credit Suisse Securities (USA) LLC, as representative of the several underwriters (incorporated by reference to Exhibit 1.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on October 17, 2012).

3.1*		Amended and Restated Certificate of Incorporation of the Company.

3.2*		Amended and Restated Bylaws of the Company.

4.1		Specimen certificate for shares of common stock, par value $0.01 per share, of the Company (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).

4.2*		Registration Rights Agreement, dated as of October 11, 2012, by and between the Company and DB Energy Holdings LLC.

4.3*		Investor Rights Agreement, dated as of October 11, 2012, by and between the Company and Gulfport Energy Corporation.

10.1*		Equity Incentive Plan.

10.2		Form of Stock Option Agreement (incorporated by reference to Exhibit 10.13 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).

10.3		Form or Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.14 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
10.4*		Advisory Services Agreement, dated as of October 11, 2012, by and between Diamondback Energy, Inc. and Wexford Capital LP.
10.5*		Merger Agreement, dated as of October 11, 2012, by and between the Company and Diamondback Energy LLC.
10.6		Amended and Restated Employment Agreement, dated as of August 20, 2012, by and between Travis Stice and Windsor Permian LLC (incorporated by reference to Exhibit 10.29 to Amendment No. 5 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on October 2, 2012).
10.7		Amended and Restated Employment Agreement, dated as of January 1, 2012, by and between Teresa Dick and Windsor Permian LLC (incorporated by reference to Exhibit 10.30 to Amendment No. 3 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on July 5, 2012).
10.8		Amended and Restated Employment Agreement, dated as of January 1, 2012, by and between Jeff White and Windsor Permian LLC (incorporated by reference to Exhibit 10.31 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
10.9		Amended and Restated Credit Agreement, dated July 24, 2012, by and among Diamondback Energy LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.33 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
10.10		First Amendment to Credit Agreement, dated July 31, 2012, by and among Diamondback Energy LLC, as borrower, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.34 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
10.11		Lease Amendment No. 5 to Lease Agreement, dated as of July 25, 2012, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.36 to Amendment No. 5 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on October 2, 2012).

31.1*		Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.

31.2*		Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.

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32.1*		Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.

32.2*		Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.

101.INS**		XBRL Instance Document.

101.SCH**		XBRL Taxonomy Extension Schema Document.

101.CAL**		XBRL Taxonomy Extension Calculation Linkbase.

101.DEF**		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB**		XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE**		XBRL Taxonomy Extension Presentation Linkbase Document.



*	Filed herewith.



**	To be filed by amendment during the 30-day grace period provided by Rule 405(a)(2) of Regulation S-T. Pursuant to Rule 406T of Regulation S-T, these interactive data files will be furnished and will not be deemed filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, will not be deemed filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under these sections.

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SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		DIAMONDBACK ENERGY, INC.

Date:	November 16, 2012
		/s/ Travis D. Stice
		Travis D. Stice
		Chief Executive Officer

		/s/ Teresa L. Dick
		Teresa L. Dick
		Chief Financial Officer

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Item 2. Management's Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II. Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Item 3. Defaults Upon Senior Securities Item 4. Mine Safety Disclosures Item 5. Other Information Item 6. Exhibits

Large Accelerated Filer

Accelerated Filer

Non-Accelerated Filer

Smaller Reporting Company