Diamondback Energy, Inc. - FORM 8-K - EX-99.5 - EXHIBIT

Attached files

file	filename
8-K - 8-K - Diamondback Energy, Inc.	a20148kacquisitionssept2014.htm
EX-23.1 - EXHIBIT - Diamondback Energy, Inc.	ex23_1diamondbackwesttexas.htm
EX-99.1 - EXHIBIT - Diamondback Energy, Inc.	ex99_1statementsofrev.htm
EX-23.2 - EXHIBIT - Diamondback Energy, Inc.	ex23_2diamondbackguarantor.htm
EX-99.4 - EXHIBIT - Diamondback Energy, Inc.	ex99_4x3311410-qguarantor8k.htm
EX-99.3 - EXHIBIT - Diamondback Energy, Inc.	ex99_3x12311310-kguarantor.htm
EX-99.2 - EXHIBIT - Diamondback Energy, Inc.	ex99_2proformasept20148-k.htm

Exhibit 99.5

TABLE OF CONTENTS

(Unaudited)

		Page

Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013		1
Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2014 and 2013		2
Consolidated Statement of Stockholders’ Equity for the Six Months Ended June 30, 2014		3
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2014 and 2013		4
Notes to Consolidated Financial Statements		6

Table of Contents

Diamondback Energy, Inc. and Subsidiaries

Consolidated Balance Sheets

(Unaudited)



	June 30,			December 31,
	2014			2013

	(In thousands, except par values and share data)
Assets
Current assets:
Cash and cash equivalents	$	36,993		$	15,555
Accounts receivable:
Joint interest and other	24,697			14,437
Oil and natural gas sales	40,648			23,533
Related party	3,310			1,303
Inventories	3,308			5,631
Deferred income taxes	4,327			112
Derivative instruments	—			213
Prepaid expenses and other	1,421			1,184
Total current assets	114,704			61,968
Property and equipment
Oil and natural gas properties, based on the full cost method of accounting ($456,692 and $369,561 excluded from amortization at June 30, 2014 and December 31, 2013, respectively)	2,191,321			1,648,360
Pipeline and gas gathering assets	6,846			6,142
Other property and equipment	4,973			4,071
Accumulated depletion, depreciation, amortization and impairment	(283,152		)	(212,236		)
	1,919,988			1,446,337
Derivative instruments	—			218
Other assets	12,702			13,091
Total assets	$	2,047,394		$	1,521,614
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	23,475		$	2,679
Accounts payable-related party	67			17
Accrued capital expenditures	81,550			74,649
Other accrued liabilities	38,236			34,750
Revenues and royalties payable	15,170			9,225
Derivative instruments	10,379			—
Total current liabilities	168,877			121,320
Long-term debt	496,000			460,000
Asset retirement obligations	5,437			2,989
Deferred income taxes	124,743			91,764
Total liabilities	795,057			676,073
Contingencies (Note 13)
Stockholders’ equity:
Common stock, $0.01 par value, 100,000,000 shares authorized, 50,807,635 issued and outstanding at June 30, 2014; 47,106,216 issued and outstanding at December 31, 2013	509			471
Additional paid-in capital	1,060,537			842,557
Retained earnings	53,855			2,513
Total Diamondback Energy, Inc. stockholders’ equity	1,114,901			845,541
Noncontrolling interest	137,436			—
Total equity	1,252,337			845,541
Total liabilities and equity	$	2,047,394		$	1,521,614

See accompanying notes to consolidated financial statements.

Table of Contents

Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013

	(In thousands, except per share amounts)
Revenues:
Oil sales	$	115,282		$	41,034		$	205,040		$	66,287
Natural gas sales	1,913			988			3,668			1,727
Natural gas sales - related party	2,416			680			3,996			1,092
Natural gas liquid sales	3,304			1,649			5,888			3,471
Natural gas liquid sales - related party	4,089			1,043			6,416			1,726
Total revenues	127,004			45,394			225,008			74,303
Costs and expenses:
Lease operating expenses	10,425			5,103			18,232			9,809
Lease operating expenses - related party	71			392			179			594
Production and ad valorem taxes	8,106			2,672			13,684			4,550
Production and ad valorem taxes - related party	448			116			712			192
Gathering and transportation	102			31			316			106
Gathering and transportation - related party	601			216			969			274
Depreciation, depletion and amortization	40,021			14,815			70,994			25,553
General and administrative expenses (including non-cash stock based compensation, net of capitalized amounts, of $1,128 and $477 for the three months ended June 30, 2014 and 2013, respectively, and $3,318 and $936 for the six months ended June 30, 2014 and 2013, respectively)	3,610			2,355			7,875			4,540
General and administrative expenses - related party	324			266			616			552
Asset retirement obligation accretion expense	104			45			176			88
Total costs and expenses	63,812			26,011			113,753			46,258
Income from operations	63,192			19,383			111,255			28,045
Other income (expense)
Interest expense	(7,739		)	(535		)	(14,244		)	(1,020		)
Other income - related party	30			388			60			777
Other expense	(1,408		)	—			(1,408		)	—
Gain (loss) on derivative instruments, net	(11,088		)	3,037			(15,486		)	3,029
Total other income (expense), net	(20,205		)	2,890			(31,078		)	2,786
Income before income taxes	42,987			22,273			80,177			30,831
Provision for income taxes
Deferred	15,163			7,802			28,764			10,964
Net income	27,824			14,471			51,413			19,867
Less: Net income attributable to noncontrolling interest	71			—			71			—
Net income attributable to Diamondback Energy, Inc.	$	27,753		$	14,471		$	51,342		$	19,867

Earnings per common share
Basic	$	0.55		$	0.37		$	1.03		$	0.52
Diluted	$	0.54		$	0.36		$	1.02		$	0.52
Weighted average common shares outstanding
Basic	50,777			39,402			49,622			38,237
Diluted	51,142			39,719			50,047			38,477

See accompanying notes to consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Consolidated Statement of Stockholders’ Equity

(Unaudited)



				Additional
	Common Stock			Paid-in		Retained		Non-controlling
	Shares	Amount		Capital		Earnings		Interest		Total

	(In thousands)
Balance December 31, 2013	47,106	$	471	$	842,557	$	2,513	$	—	$	845,541
Net proceeds from issuance of common units - Viper Energy Partners LP	—	—		—		—		137,365		137,365
Stock based compensation	—	—		5,906		—		—		5,906
Common shares issued in public offering, net of offering costs	3,450	35		208,394		—		—		208,429
Exercise of stock options and vesting of restricted stock units	251	3		3,680		—		—		3,683
Net income	—	—		—		51,342		71		51,413
Balance June 30, 2014	50,807	$	509	$	1,060,537	$	53,855	$	137,436	$	1,252,337

See accompanying notes to consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)



	Six Months Ended June 30,
	2014			2013

	(In thousands)
Cash flows from operating activities:
Net income	$	51,413		$	19,867
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for deferred income taxes	28,764			10,964
Asset retirement obligation accretion expense	176			88
Depreciation, depletion, and amortization	70,994			25,553
Amortization of debt issuance costs	946			318
Change in fair value of derivative instruments	10,810			(5,429		)
Stock based compensation expense	3,318			936
(Gain) loss on sale of assets, net	1,397			(30		)
Changes in operating assets and liabilities:
Accounts receivable	(18,584		)	(12,185		)
Accounts receivable-related party	(2,007		)	5,110
Inventories	977			(96		)
Prepaid expenses and other	(219		)	(1,517		)
Accounts payable and accrued liabilities	2,076			4,543
Accounts payable and accrued liabilities-related party	—			(74		)
Accrued interest	3,415			—
Revenues and royalties payable	6,230			1,750
Net cash provided by operating activities	159,706			49,798
Cash flows from investing activities:
Additions to oil and natural gas properties	(206,779		)	(102,785		)
Additions to oil and natural gas properties-related party	(2,571		)	(9,298		)
Acquisition of Gulfport properties	—			(18,550		)
Acquisition of leasehold interests	(312,207		)	(6,192		)
Pipeline and gas gathering assets	(1,165		)	—
Purchase of other property and equipment	(934		)	(1,615		)
Proceeds from sale of property and equipment	11			54
Settlement of non-hedge derivative instruments	—			(289		)
Net cash used in investing activities	(523,645		)	(138,675		)
Cash flows from financing activities:
Proceeds from borrowings on credit facility	166,000			49,000
Repayment on credit facility	(130,000		)	(49,000		)
Debt issuance costs	(1,039		)	(72		)
Public offering costs	(946		)	(447		)
Proceeds from public offerings	347,679			144,936
Exercise of stock options	3,683			—
Net cash provided by financing activities	385,377			144,417
Net increase in cash and cash equivalents	21,438			55,540
Cash and cash equivalents at beginning of period	15,555			26,358
Cash and cash equivalents at end of period	$	36,993		$	81,898

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Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows - Continued

(Unaudited)

See accompanying notes to consolidated financial statements.



	Six Months Ended June 30,
	2014		2013

	(In thousands)
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest	$	11,409	$	383
Supplemental disclosure of non-cash transactions:
Asset retirement obligation incurred	$	382	$	111
Asset retirement obligation revisions in estimated liability	$	588	$	—
Asset retirement obligation acquired	$	1,312	$	—
Change in accrued capital expenditures	$	6,901	$	20,645
Capitalized stock based compensation	$	2,715	$	420

See accompanying notes to consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

(Unaudited)

1. DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION

Organization and Description of the Business

Diamondback Energy, Inc. (“Diamondback” or the “Company”) together with its subsidiaries, is an independent oil and gas company currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. Diamondback was incorporated in Delaware on December 30, 2011.

On June 17, 2014, Diamondback entered into a contribution agreement (the “Contribution Agreement”) with Viper Energy Partners LP (the “Partnership”), Viper Energy Partners GP LLC (the “General Partner”) and Viper Energy Partners LLC to transfer Diamondback’s ownership interest in Viper Energy Partners LLC to the Partnership in exchange for 70,450,000 common units, representing an approximate 92% limited partner interest in the Partnership. Diamondback also owns and controls the General Partner, which holds a non-economic general partner interest in the Partnership. On June 23, 2014, the Partnership completed its initial public offering (the “Viper Offering”) of 5,750,000 common units. See Note 4—Viper Energy Partners LP for additional information regarding the Partnership.

The wholly owned subsidiaries of Diamondback, as of June 30, 2014, include Diamondback E&P LLC, a Delaware limited liability company, Diamondback O&G LLC, a Delaware limited liability company, and Viper Energy Partners GP LLC, a Delaware limited liability company. The consolidated subsidiaries include the wholly owned subsidiaries as well as Viper Energy Partners LP, a Delaware limited partnership and Viper Energy Partners LLC, a Delaware limited liability company. Noncontrolling interests represent third-party ownership in the net assets of the consolidated Partnership.

Basis of Presentation

The consolidated financial statements include the accounts of the Company and its subsidiaries after all significant intercompany balances and transactions have been eliminated upon consolidation.

The Partnership is consolidated in the financial statements of the Company. As of June 30, 2014, the Company owned approximately 92% of the common units of the Partnership, Wexford Capital LP (“Wexford”) owned approximately 1% and third party investors owned the remaining approximate 7% of the common units of the Partnership. The third party limited partnership interests in the Partnership are included in “noncontrolling interest” reported on the consolidated balance sheet.

These financial statements have been prepared by the Company without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been omitted pursuant to such rules and regulations, although the Company believes the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10–Q should be read in conjunction with the Company’s most recent Annual Report on Form 10–K for the fiscal year ended December 31, 2013, which contains a summary of the Company’s significant accounting policies and other disclosures.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, asset retirement obligations, the fair value determination of acquired assets and liabilities, stock-based compensation, fair value estimates of commodity derivatives and estimates of income taxes.

3. ACQUISITIONS

2014 Activity

On February 27 and 28, 2014, the Company completed acquisitions of oil and natural gas interests in the Permian Basin from unrelated third party sellers. The Company acquired approximately 6,450 gross (4,785 net) acres with a 74% working interest (56% net revenue interest). The acquisitions were accounted for according to the acquisition method, which requires the recording of net assets acquired and consideration transferred at fair value. These acquisitions were funded in part by the net proceeds of the February 2014 equity offering discussed in Note 8 below.

The following represents the estimated fair values of the assets and liabilities assumed on the acquisition dates. The aggregate consideration transferred was $292,159,000 in cash, subject to post-closing adjustments, resulting in no goodwill or bargain purchase gain.



	(in thousands)
Proved oil and natural gas properties	$	170,174
Unevaluated oil and natural gas properties	123,243
Asset retirement obligations	(1,258		)
Total fair value of net assets	$	292,159

The Company has included in its consolidated statements of operations revenues of $19,183,000 and direct operating expenses of $4,601,000 for the period from February 28, 2014 to June 30, 2014 due to the acquisitions. The disclosure of net earnings is impracticable to calculate due to the full cost method of depletion. The following unaudited summary pro forma combined consolidated statement of operations data of Diamondback for the three months and six months ended June 30, 2014 and 2013 have been prepared to give effect to the February 2014 acquisitions as if they had occurred on January 1, 2013. The pro forma data are not necessarily indicative of financial results that would have been attained had the acquisitions occurred on January 1, 2013. The pro forma data also necessarily exclude various operation expenses related to the properties and the financial statements should not be viewed as indicative of operations in future periods.



	Three Months Ended June 30,				Six Months Ended June 30,
	2014		2013		2014		2013

	(Pro Forma)
	(in thousands, except per share amounts)
Revenues	$	127,004	$	62,209	$	234,983	$	106,600
Income from operations	63,192		26,872		115,385		41,527
Net income	27,823		19,337		54,033		28,511
Basic earnings per common share	$	0.55	$	0.49	$	1.09	$	0.75
Diluted earnings per common share	$	0.54	$	0.49	$	1.08	$	0.74

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

2013 Activity

In September 2013, the Company completed two separate acquisitions of additional leasehold interests in the Permian Basin from unrelated third party sellers for an aggregate purchase price of $165.0 million, subject to certain adjustments. The first of these acquisitions closed on September 4, 2013 when the Company acquired certain assets located in northwestern Martin County, Texas, consisting of a 100% working interest (80% net revenue interest) in 4,506 gross and net acres. The second of these acquisitions closed on September 26, 2013, when the Company acquired certain assets located primarily in southwestern Dawson County, Texas, consisting of a 71% working interest (55% net revenue interest) in 9,390 gross (6,638 net) acres. These acquisitions were funded with a portion of the net proceeds from the August 2013 equity offering discussed in Note 8 below.

On September 19, 2013, the Company completed the acquisition of the mineral interests underlying approximately 14,804 gross (12,687 net) acres in Midland County, Texas in the Permian Basin. As part of the closing of the acquisition, the mineral interests were conveyed from the previous owners to Viper Energy Partners LLC and, subsequently, were contributed to the Partnership on June 17, 2014. See Note 4—Viper Energy Partners LP for additional information regarding the Partnership. The mineral interests entitle the holder of such interests to receive an average 21.4% royalty interest on all production from this acreage with no additional future capital or operating expense required. The $440.0 million purchase price was funded with the net proceeds of the Company’s offering of Senior Notes discussed in Note 7 below.

4. VIPER ENERGY PARTNERS LP

The Partnership is a publicly traded Delaware limited partnership, the common units of which are listed on the NASDAQ Global Market under the symbol “VNOM”. The Partnership was formed by Diamondback on February 27, 2014, to, among other things, own, acquire and exploit oil and natural gas properties in North America. The Partnership is currently focused on oil and natural gas properties in the Permian Basin.

Prior to the completion on June 23, 2014 of the Viper Offering, Diamondback owned all of the general and limited partner interests in the Partnership. The Viper Offering consisted of 5,750,000 common units representing approximately 8% of the limited partner interests in the Partnership at a price to the public of $26.00 per common unit, which included 750,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters on the same terms. The Partnership received net proceeds of approximately $137.2 million from the sale of these common units, net of offering expenses and underwriting discounts and commissions.

In connection with the Viper Offering, Diamondback contributed all of the membership interests in Viper Energy Partners LLC to the Partnership in exchange for 70,450,000 common units. In addition, in connection with the closing of the Viper Offering, the Partnership agreed to distribute to Diamondback all cash and cash equivalents and the royalty income receivable on hand in the aggregate amount of approximately $11.3 million and the net proceeds from the Viper Offering. As of June 30, 2014, the Partnership had distributed $137.5 million to Diamondback and the Partnership recorded a payable balance of approximately $11.3 million. The contribution of Viper Energy Partners LLC to the Partnership was accounted for as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests.

The Company has also entered into the following agreements with the Partnership:

Partnership Agreement

In connection with the closing of the Viper Offering, the General Partner and Diamondback entered into the first amended and restated agreement of limited partnership (the “Partnership Agreement”), dated June 23, 2014. The Partnership Agreement requires the Partnership to reimburse the General Partner for all direct and indirect expenses incurred or paid on the Partnership’s behalf and all other expenses allocable to the Partnership or otherwise incurred by the General Partner in connection with operating the Partnership’s business. The Partnership Agreement does not set a limit on the amount of expenses for which the General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for the Partnership or on its behalf and expenses allocated to the General Partner by its affiliates. The General Partner is entitled to determine the expenses that are allocable to the Partnership.

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Tax Sharing

In connection with the closing of the Viper Offering, the Partnership entered into a tax sharing agreement (the “Tax Sharing Agreement”) with Diamondback pursuant to which the Partnership will reimburse Diamondback for its share of state and local income and other taxes for which the Partnership’s results are included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on June 23, 2014. The amount of any such reimbursement is limited to the tax the Partnership would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its combined or consolidated group, of which the Partnership may be a member for this purpose, to owe less or no tax. In such a situation, the Partnership would reimburse Diamondback for the tax the Partnership would have owed had the tax attributes not been available or used for the Partnership’s benefit, even though Diamondback had no cash tax expense for that period.

See Note 10—Related Party Transactions for details of the the advisory services agreement the Partnership and General Partner entered into with Wexford.

The Partnership has entered into a secured revolving credit facility with Wells Fargo Bank, National Association, (“Wells Fargo”) as administrative agent sole book runner and lead arranger. See Note 7—Debt for a description of this credit facility

5. PROPERTY AND EQUIPMENT

Property and equipment includes the following:



	June 30,			December 31,
	2014			2013

	(in thousands)
Oil and natural gas properties:
Subject to depletion	$	1,734,629		$	1,278,799
Not subject to depletion-acquisition costs
Incurred in 2014	144,516			—
Incurred in 2013	237,540			279,353
Incurred in 2012	73,872			87,252
Incurred in 2011	764			1,598
Incurred in 2010	—			1,358
Total not subject to depletion	456,692			369,561
Gross oil and natural gas properties	2,191,321			1,648,360
Less accumulated depreciation, depletion, amortization and impairment	(281,218		)	(210,837		)
Oil and natural gas properties, net	1,910,103			1,437,523
Pipeline and gas gathering assets	6,846			6,142
Other property and equipment	4,973			4,071
Less accumulated depreciation	(1,934		)	(1,399		)
Other property and equipment, net	3,039			2,672
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment	$	1,919,988		$	1,446,337

The average depletion rate per barrel equivalent unit of production was $24.46 and $24.81 for the three months and six months ended June 30, 2014, respectively, and $24.42 and $24.44 for the three months and six months ended June 30, 2013, respectively. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs not directly associated with exploration and development activities were charged to expense as they were incurred. Capitalized internal costs were approximately $2,632,000 and $4,928,000 for the three months and six months ended June 30, 2014, respectively, and $843,000 and $1,640,000 for the three months and six months ended June 30, 2013, respectively. Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within three to five years.

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

6. ASSET RETIREMENT OBLIGATIONS

The following table describes the changes to the Company’s asset retirement obligation liability for the following periods:



	Six Months Ended
	June 30,
	2014			2013

	(in thousands)
Asset retirement obligation, beginning of period	$	3,029		$	2,145
Additional liability incurred	382			111
Liabilities acquired	1,312			—
Liabilities settled	(10		)	—
Accretion expense	176			88
Revisions in estimated liabilities	588			—
Asset retirement obligation, end of period	5,477			2,344
Less current portion	40			20
Asset retirement obligations - long-term	$	5,437		$	2,324

The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The Company estimates the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance.

7. DEBT

Long-term debt consisted of the following as of the dates indicated:



	June 30,		December 31,
	2014		2013

	(in thousands)
Revolving credit facility	$	46,000	$	10,000
7.625 % Senior Notes due 2021	450,000		450,000
Total long-term debt	$	496,000	$	460,000

Senior Notes

On September 18, 2013, the Company completed an offering of $450.0 million in aggregate principal amount of 7.625% senior unsecured notes due 2021 (the “Senior Notes”). The Senior Notes bear interest at the rate of 7.625% per annum, payable semi-annually, in arrears on April 1 and October 1 of each year, commencing on April 1, 2014 and will mature on October 1, 2021. On June 23, 2014, in connection with the Viper Offering, the Company designated the Partnership, the General Partner and Viper Energy LLC as unrestricted subsidiaries and, upon such designation, Viper Energy LLC, which was a guarantor under the indenture governing of the Senior Notes, was released as a guarantor under the indenture. As a result, the Senior Notes are now fully and unconditionally guaranteed by Diamondback O&G LLC and Diamondback E&P LLC and will also be guaranteed by any future restricted subsidiaries of Diamondback. The net proceeds from the Senior Notes were used to fund the acquisition of mineral interests underlying approximately 14,804 gross (12,687 net) acres in Midland County, Texas in the Permian Basin.

The Senior Notes were issued under, and are governed by, an indenture among the Company, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as the trustee (the “Indenture”). The Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit the Company’s ability and the ability of the restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make other distributions on, or redeem or repurchase, capital stock, prepay subordinated

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

indebtedness, sell assets including capital stock of subsidiaries, agree to payment restrictions affecting the Company’s restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and gas business and designate certain of the Company’s subsidiaries as unrestricted subsidiaries. If the Company experiences certain kinds of changes of control or if it sells certain of its assets, holders of the Senior Notes may have the right to require the Company to repurchase their Senior Notes.

The Company will have the option to redeem the Senior Notes, in whole or in part, at any time on or after October 1, 2016 at the redemption prices (expressed as percentages of principal amount) of 105.719% for the 12-month period beginning on October 1, 2016, 103.813% for the 12-month period beginning on October 1, 2017, 101.906% for the 12-month period beginning on October 1, 2018 and 100.000% beginning on October 1, 2019 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. In addition, prior to October 1, 2016, the Company may redeem all or a part of the Senior Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date, plus a “make-whole” premium at the redemption date. Furthermore, before October 1, 2016, the Company may, at any time or from time to time, redeem up to 35% of the aggregate principal amount of the Senior Notes with the net cash proceeds of certain equity offerings at a redemption price of 107.625% of the principal amount of the Senior Notes being redeemed plus any accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the Senior Notes originally issued under the Indenture remains outstanding immediately after such redemption and the redemption occurs within 120 days of the closing date of such equity offering.

In connection with the issuance of the Senior Notes, the Company and the subsidiary guarantors entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with the initial purchasers on September 18, 2013, pursuant to which the Company and the subsidiary guarantors have agreed to file a registration statement with respect to an offer to exchange the Senior Notes for a new issue of substantially identical debt securities registered under the Securities Act, which registration statement was filed with the SEC on March 14, 2014. Under the Registration Rights Agreement, the Company also agreed to use its commercially reasonable efforts to cause the exchange offer registration statement to become effective within 360 days after the issue date of the Senior Notes and to consummate the exchange offer 30 days after effectiveness. The Company may be required to file a shelf registration statement to cover resales of the Senior Notes under certain circumstances. If the Company fails to satisfy certain of its obligations under the Registration Rights Agreement, the Company agreed to pay additional interest to the holders of the Senior Notes as specified in the Registration Rights Agreement.

Credit Facility-Wells Fargo Bank

The Company’s secured second amended and restated credit agreement, dated November 1, 2013, with a syndication of banks, including Wells Fargo as administrative agent sole book runner and lead arranger, provides for a revolving credit facility in the maximum amount of $600.0 million, subject to scheduled semi-annual and other elective collateral borrowing base redeterminations based on the Company’s oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be re-determined semi-annually with effective dates of April 1st and October 1st. In addition, the Company may request up to three additional redeterminations of the borrowing base during any 12-month period. As of June 30, 2014, the borrowing base was set at $350.0 million and the Company had outstanding borrowings of $46.0 million.

The outstanding borrowings under the credit agreement bear interest at a rate elected by the Company that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.5% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. The Company is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to the borrowing base. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be paid (a) if the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period) and (b) at the maturity date of November 1, 2018.

On June 9, 2014, Diamondback entered into a first amendment (the “First Amendment”) to the second amended and restated credit agreement, dated November 1, 2013. The First Amendment modified certain provisions of the credit agreement to, among other things, allow the Company to designate one or more of our subsidiaries as “Unrestricted

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Subsidiaries” that are not subject to certain restrictions contained in the credit agreement. In connection with the Viper Offering, the Company designated the Partnership, the General Partner and Viper Energy LLC as unrestricted subsidiaries under the credit agreement and, upon such designation, Viper Energy LLC, which was a guarantor under the Indenture, was released as a guarantor under the Indenture. As a result, the loan is now secured by substantially all of the assets of the Company, Diamondback E&P LLC and Diamondback O&G LLC and will also be secured by any future restricted subsidiaries of Diamondback.

The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit 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 the financial ratios described below.



Financial Covenant			Required Ratio
Ratio of total debt to EBITDAX			Not greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreement			Not less than 1.0 to 1.0

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $750.0 million in the form of senior or senior subordinated notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each 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. As of June 30, 2014, the Company had $450.0 million of senior unsecured notes outstanding.

As of June 30, 2014 and December 31, 2013, the Company was in compliance with all financial covenants under its revolving credit facility, as then in effect. The lenders may accelerate all of the indebtedness under the Company’s revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.

Partnership Credit Facility-Wells Fargo Bank

On July 8, 2014, the Partnership entered into a secured revolving credit agreement with Wells Fargo, as the administrative agent, sole book runner and lead arranger. The credit agreement provides for a revolving credit facility in the maximum amount of $500.0 million, subject to scheduled semi-annual and other elective collateral borrowing base redeterminations based on the Partnership’s oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be re-determined semi-annually with effective dates of April 1st and October 1st. In addition, the Partnership may request up to three additional redeterminations of the borrowing base during any 12-month period. As of July 8, 2014, the borrowing base was set at $110.0 million, and Wells Fargo was the only lender under the credit agreement, with a maximum credit amount of $55.0 million. Under the credit agreement, the commitment of the lenders is equal to the lessor of the aggregate maximum credit amounts of the lenders and the borrowing base. As of August 6, 2014, the borrowing base was increased to $110.0 million with Wells Fargo as the only lender under the credit agreement. The Partnership had outstanding borrowings of $50.0 million as of August 6, 2014.

The outstanding borrowings under the credit agreement bear interest at a rate elected by the Partnership that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.5% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. The Partnership is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to the borrowing base. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be paid (a) if the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period) and (b) at the maturity date of July 8, 2019. The loan is secured by substantially all of the assets of the Partnership and its subsidiaries.

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dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.



Financial Covenant			Required Ratio
Ratio of total debt to EBITDAX			Not greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreement			Not less than 1.0 to 1.0
EBITDAX will be annualized beginning with the quarter ending September 30, 2014 and ending with the quarter ended March 31, 2015

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $250.0 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each 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 lenders may accelerate all of the indebtedness under the Partnership’s revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.

8. CAPITAL STOCK AND EARNINGS PER SHARE

As of June 30, 2014, Diamondback had completed the following equity offerings since the closing of its initial public offering on October 17, 2012:

On May 21, 2013, the Company completed an underwritten primary public offering of 5,175,000 shares of common stock, which included 675,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the public at $29.25 per share and the Company received net proceeds of approximately $144.4 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.

In August 2013, the Company completed an underwritten public offering of 4,600,000 shares of common stock, which included 600,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the public at $40.25 per share and the Company received net proceeds of approximately $177.5 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.

In February 2014, the Company completed an underwritten public offering of 3,450,000 shares of common stock, which included 450,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the public at $62.67 per share and the Company received net proceeds of approximately $208.4 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.

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Notes to Consolidated Financial Statements-(Continued)

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Earnings Per Share

The Company’s basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted earnings per share include the effect of potentially dilutive shares outstanding for the period. Additionally, for the diluted earnings per share computation, the per share earnings of the Partnership are included in the consolidated earnings per share computation based on the consolidated group's holdings of the subsidiary. A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:



	Three Months Ended June 30,
	2014						2013
					Per				Per
	Income			Shares	Share		Income	Shares	Share

	(in thousands, except per share amounts)
Basic:
Net income attributable to common stock	$	27,753		50,777	$	0.55	14,471	39,402	$	0.37
Effect of Dilutive Securities:
Dilutive effect of potential common shares issuable	$	(74	)	365			—	317
Diluted:
Net income attributable to common stock	$	27,679		51,142	$	0.54	14,471	39,719	$	0.36



	Six Months Ended June 30,
	2014						2013
					Per				Per
	Income			Shares	Share		Income	Shares	Share

	(in thousands, except per share amounts)
Basic:
Net income attributable to common stock	$	51,342		49,622	$	1.03	19,867	38,237	$	0.52
Effect of Dilutive Securities:
Dilutive effect of potential common shares issuable	$	(74	)	425			—	240
Diluted:
Net income attributable to common stock	$	51,268		50,047	$	1.02	19,867	38,477	$	0.52

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9. STOCK BASED COMPENSATION

For the three months and six months ended June 30, 2014, the Company incurred $2,777,000 and $6,033,000, respectively, of stock based compensation, of which the Company capitalized $1,649,000 and $2,715,000, respectively, pursuant to the full cost method of accounting for oil and natural gas properties. For the three months and six months ended June 30, 2013, the Company incurred $700,000 and $1,356,000, respectively, of stock based compensation, of which the Company capitalized $223,000 and $420,000, respectively, pursuant to the full cost method of accounting for oil and natural gas properties.

On June 17, 2014, in connection with the Viper Offering, the Board of Directors of the General Partner adopted the Viper Energy Partners LP Long Term Incentive Plan (“Viper LTIP”), effective June 17, 2014, for employees, officers, consultants and directors of the General Partner and any of its affiliates, including Diamondback, who perform services for the Partnership. The Viper LTIP provides for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards. A total of 9,144,000 common units has been reserved for issuance pursuant to the Viper LTIP. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The Viper LTIP is administered by the Board of Directors of the General Partner or a committee thereof.

Stock Options

The following table presents the Company’s stock option activity under the 2012 Plan for the six months ended June 30, 2014.



			Weighted Average
			Exercise		Remaining	Intrinsic
	Options		Price		Term	Value
					(in years)	(in thousands)
Outstanding at December 31, 2013	712,955		$	17.96
Granted	—		$	—
Exercised	(205,750	)	$	17.90
Expired/Forfeited	—		$	—
Outstanding at June 30, 2014	507,205		$	17.99	2.23	$	28,076

Vested and Expected to vest at June 30, 2014	507,205		$	17.99	2.23	$	28,076
Exercisable at June 30, 2014	134,955		$	17.50	1.62	$	7,536

The aggregate intrinsic value of stock options that were exercised during the six months ended June 30, 2014 was $10,659,000. As of June 30, 2014, the unrecognized compensation cost related to unvested stock options was $1,212,000. Such cost is expected to be recognized over a weighted-average period of 1.4 years.

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Notes to Consolidated Financial Statements-(Continued)

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Restricted Stock Units

The following table presents the Company’s restricted stock units activity under the 2012 Plan during the six months ended June 30, 2014.



			Weighted Average
	Restricted Stock		Grant-Date
	Units		Fair Value
Unvested at December 31, 2013	132,499		$	19.20
Granted	106,550		$	62.03
Vested	(45,669	)	$	47.69
Forfeited	(900	)	$	41.66
Unvested at June 30, 2014	192,480		$	36.04

The aggregate fair value of restricted stock units that vested during the six months ended June 30, 2014 was $3,051,000. As of June 30, 2014, the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $5,081,000. Such cost is expected to be recognized over a weighted-average period of 1.5 years.

Performance Based Restricted Stock Units

To provide long-term incentives for the executive officers to deliver competitive returns to the Company’s stockholders, the Company has granted performance based restricted stock units to eligible employees. The ultimate number of shares awarded from these conditional restricted stock units is based upon measurement of total stockholder return of the Company’s common stock (“TSR”) as compared to a designated peer group during a three-year performance period. In February 2014, eligible employees received initial performance restricted stock unit awards totaling 79,150 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2013 to December 31, 2015 and cliff vest at December 31, 2015. There were no performance restricted stock units issued or outstanding during the six months ended June 30, 2013.

The fair value of each performance restricted stock unit is estimated at the date of grant using a Monte Carlo simulation, which results in an expected percentage of units to be earned during the performance period. The following table presents a summary of the grant-date fair values of performance restricted stock units granted and the related assumptions.



	2014
Grant-date fair value	$	125.63
Risk-free rate	0.30		%
Company volatility	39.60		%

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Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

The following table presents the Company’s performance restricted stock units activity under the 2012 Plan for the six months ended June 30, 2014.



		Performance	Weighted Average
		Restricted Stock	Grant-Date
		Units	Fair Value
Unvested at December 31, 2013		—	$	—
Granted		79,150	$	125.63
Vested		—	$	—
Forfeited		—	$	—
Unvested at June 30, 2014 ⁽¹⁾		79,150	$	125.63

(1)	A maximum of 158,300 units could be awarded based upon the Company’s final TSR ranking.

As of June 30, 2014, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $8,111,000. Such cost is expected to be recognized over a weighted-average period of 1.5 years.

Partnership Unit Options

In accordance with the Viper LTIP, the exercise price of unit options granted may not be less than the market value of the common units at the date of grant. The units issued under the Viper LTIP will consist of new common units of the Partnership. On June 17, 2014, the Board of Directors of the General Partner granted 2,500,000 unit options to our executive officers of the General Partner. The unit options vest approximately 33% ratably on each of the next three anniversaries of the date of grant. In the event the fair market value per unit as of the exercise date is less than the exercise price per option unit then the vested options will automatically terminate and become null and void as of the exercise date.

The fair value of the unit options on the date of grant is expensed over the applicable vesting period. The Partnership estimates the fair values of unit options granted using a Black-Scholes option valuation model, which requires the Partnership to make several assumptions. At the time of grant the Partnership did not have a history of market prices, thus the expected volatility was determined using the historical volatility for a peer group of companies. The expected term of options granted was determined based on the contractual term of the awards. The risk-free interest rate is based on the U.S. treasury yield curve rate for the expected term of the unit option at the date of grant. The expected dividend yield was based upon projected performance of the Partnership.



	2014
Grant-date fair value	$	4.24
Expected volatility	36.0		%
Expected dividend yield	5.9		%
Expected term (in years)	3.0
Risk-free rate	0.99		%

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Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

The following table presents the unit option activity under the Viper LTIP for the six months ended June 30, 2014.



		Weighted Average
	Unit	Exercise		Remaining	Intrinsic
	Options	Price		Term	Value
				(in years)	(in thousands)
Outstanding at December 31, 2013	—	$	—
Granted	2,500,000	$	26.00
Outstanding at June 30, 2014	2,500,000	$	26.00	2.97	$	19,500

Vested and Expected to vest at June 30, 2014	2,500,000	$	26.00	2.97	$	19,500
Exercisable at June 30, 2014	—	$	—	—	$	—

As of June 30, 2014, the unrecognized compensation cost related to unvested unit options was $10,472,000. Such cost is expected to be recognized over a weighted-average period of 3.0 years.

10. RELATED PARTY TRANSACTIONS

Administrative Services

An entity under common management provided technical, administrative and payroll services to the Company under a shared services agreement which began March 1, 2008. The initial term of this shared service agreement was two years. Since the expiration of such two-year period on March 1, 2010, the agreement, by its terms has continued on a month-to-month basis. For the three months and six months ended June 30, 2014, the Company incurred total costs of $1,000 and $2,000, respectively. For the three months and six months ended June 30, 2013, the Company incurred total costs of $51,000 and $109,000, respectively. Costs incurred unrelated to drilling activities are expensed and costs incurred in the acquisition, exploration and development of proved oil and natural gas properties have been capitalized. As of June 30, 2014 and December 31, 2013, the Company owed the administrative services affiliate no amounts and $17,000, respectively. These amounts are included in accounts payable-related party in the accompanying consolidated balance sheets.

Effective January 1, 2012, the Company entered into an additional shared services agreement with this entity. Under this agreement, the Company provides this entity and, at its request, certain affiliates, with consulting, technical and administrative services. The initial term of the additional shared services agreement was two years. The agreement now continues on a month-to-month basis until canceled by either party upon thirty days prior written notice. Costs that are attributable to and billed to other affiliates are reported as other income-related party. For the three months and six months ended June 30, 2014, the affiliate reimbursed the Company $30,000 and $60,000, respectively, and for the three months and six months ended June 30, 2013, the affiliate reimbursed the Company $388,000 and $777,000, respectively, for services under the shared services agreement. As of June 30, 2014 and December 31, 2013, the affiliate owed the Company no amounts for either period.

Drilling Services

Bison Drilling and Field Services LLC (“Bison”), an entity controlled by Wexford, has performed drilling and field services for the Company under master drilling and field service agreements. Under the Company’s most recent master drilling agreement with Bison, effective as of January 1, 2013, Bison committed to accept orders from the Company for the use of at least two of its rigs. At June 30, 2014, Bison was providing drilling services to the Company using one of its rigs. This master drilling agreement is terminable by either party on 30 days’ prior written notice, although neither party will be relieved of its respective obligations arising from a drilling contract being performed prior to the termination of the master drilling agreement. For the three months and six months ended June 30, 2014, the Company incurred total costs for services performed by Bison of $985,000 and $2,495,000, respectively. For the three months and six months ended June 30, 2013, the Company incurred total costs for services performed by Bison of $4,659,000 and $9,627,000, respectively. The Company owed Bison $56,000 as of June 30, 2014 and no amounts as of December 31, 2013.

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Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Effective September 9, 2013, the Company entered into a master service agreement with Panther Drilling Systems LLC (“Panther Drilling”), an entity controlled by Wexford, Panther Drilling provides directional drilling and other services. This master service agreement is terminable by either party on 30 days’ prior written notice, although neither party will be relieved of its respective obligations arising from work performed prior to the termination of the master service agreement. In the third quarter 2013, the Company began using Panther Drilling’s directional drilling services. For the three months and six months ended June 30, 2014, the Company incurred total costs for services performed by Panther Drilling of $57,000 and $305,000, respectively. The Company owed Panther Drilling $11,000 as of June 30, 2014 and no amounts as of December 31, 2013.

Coronado Midstream

The Company is party to a gas purchase agreement, dated May 1, 2009, as amended, with Coronado Midstream LLC (“Coronado Midstream”), formerly known as MidMar Gas LLC, an entity affiliated with Wexford that owns a gas gathering system and processing plant in the Permian Basin. Under this agreement, Coronado Midstream is obligated to purchase from the Company, and the Company is obligated to sell to Coronado Midstream, 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, Coronado Midstream is obligated to pay the Company 87% of the net revenue received by Coronado Midstream 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 Coronado Midstream’s gas processing plant, and 94.56% of the net revenue received by Coronado Midstream from the sale of such gas components and residue gas, extracted, recovered or otherwise processed at Chevron’s Headlee plant. The Company recognized revenues from Coronado Midstream of $6,505,000 and $10,412,000 for the three months and six months ended June 30, 2014, respectively, and $1,723,000 and $2,818,000 for the three months and six months ended June 30, 2013, respectively. As of June 30, 2014 and December 31, 2013, Coronado Midstream owed the Company $3,310,000 and $1,303,000, respectively, for the Company’s portion of the net proceeds from the sale of gas, gas products and residue gas.

Sand Supply

Muskie Proppant LLC (“Muskie”), an entity affiliated with Wexford, processes and sells fracing grade sand for oil and natural gas operations. The Company began purchasing sand from Muskie in March 2013. On May 16, 2013, the Company entered into a master services agreement with Muskie, pursuant to which Muskie agreed to sell custom natural sand proppant to the Company based on the Company’s requirements. The Company is not obligated to place any orders with, or accept any offers from, Muskie for sand proppant. The agreement may be terminated at the option of either party on 30 days’ notice. The Company incurred no costs for sand purchased from Muskie for the three months and six months ended June 30, 2014, respectively. The Company incurred no costs and costs of $234,000 for sand purchased from Muskie for the three months and six months ended June 30, 2013, respectively. The Company owed Muskie no amounts as of June 30, 2014 or December 31, 2013.

Midland Leases

Effective May 15, 2011, the Company occupied corporate office space in Midland, Texas under a lease with a five-year term. The office space is owned by an entity controlled by an affiliate of Wexford. The Company paid $98,000 and $191,000 for the three months and six months ended June 30, 2014, respectively, and $43,000 and $82,000, for the three months and six months ended June 30, 2013, respectively, under this lease. In the second and third quarters of 2013, the Company amended this agreement to increase the size of the leased premises. The monthly rent under the lease increased from $13,000 to $15,000 beginning on August 1, 2013 and increased further to $25,000 beginning on October 1, 2013. The monthly rent will continue to increase approximately 4% annually on June 1 of each year during the remainder of the lease term.

The Company leased field office space in Midland, Texas from an unrelated third party from March 1, 2011 to March 1, 2014. Effective March 1, 2014, the building was purchased by an entity controlled by an affiliate of Wexford. The remaining term of the lease as of March 1, 2014 is four years. The Company paid rent of $36,000 and $47,000 to the related party for the three months and six months ended June 30, 2014. The monthly base rent is $11,000 which will increase 3% annually on March 1 of each year during the remainder of the lease term.

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(Unaudited)

Oklahoma City Lease

Effective January 1, 2012, the Company occupied corporate office space in Oklahoma City, Oklahoma under a lease with a 67 month term. The office space is owned by an entity controlled by an affiliate of Wexford. The Company paid $62,000 and $126,000 for the three months and six months ended June 30, 2014, respectively, and $58,000 and $111,000 for the three months and six months ended June 30, 2013, respectively, under this lease. Effective April 1, 2013, the Company amended this lease to increase the size of the leased premises, at which time the monthly base rent increased to $19,000 for the remainder of the lease term. The Company is also responsible for paying a portion of specified costs, fees and expenses associated with the operation of the premises.

Advisory Services Agreement & Professional Services from Wexford

The Company entered into an advisory services agreement (the “Advisory Services Agreement”) with Wexford, dated as of October 11, 2012, under which Wexford provides the Company with general financial and strategic advisory services related to the business in return for an annual fee of $500,000, plus reasonable out-of-pocket expenses. The Advisory Services Agreement has a term of two years commencing on October 18, 2012, and will continue for additional one-year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term. It may be terminated at any time by either party upon 30 days prior written notice. In the event the Company terminates such agreement, it is obligated to pay all amounts due through the remaining term. In addition, the Company agreed to pay Wexford to-be-negotiated market-based fees approved by the Company’s independent directors for such services as may be provided by Wexford at the Company’s request in connection with future acquisitions and divestitures, financings or other transactions in which the Company may be involved. The services provided by Wexford under the Advisory Services Agreement do not extend to the Company’s day-to-day business or operations. The Company has agreed to indemnify Wexford and its affiliates from any and all losses arising out of or in connection with the Advisory Services Agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willful misconduct. The Company incurred total costs of $125,000 and $250,000 for the three months and six months ended June 30, 2014, respectively, and $125,000 and $250,000 for the three months and six months ended June 30, 2013, respectively, under the Advisory Services Agreement. As of June 30, 2014 and December 31, 2013, the Company owed Wexford no amounts for either period.

Advisory Services Agreement- Viper Energy Partners LP

In connection with the closing of the Viper Offering, the Partnership and General Partner entered into an advisory services agreement (the “Viper Advisory Services Agreement”) with Wexford, dated as of June 23, 2014, under which Wexford provides the Partnership and our General Partner 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 Viper Advisory Services Agreement has a term of two years commencing on June 23, 2014, and will continue for additional one-year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term. It may be terminated at any time by either party upon 30 days prior written notice. In the event the Partnership or General Partner terminates such agreement, the Partnership is obligated to pay all amounts due through the remaining term. In addition, the Partnership and General Partner have agreed to pay Wexford to-be-negotiated market-based fees approved by the conflict committee of the board of directors of our General Partner for such services as may be provided by Wexford at our request in connection with future acquisitions and divestitures, financings or other transactions in which we may be involved. The services provided by Wexford under the Viper Advisory Services Agreement do not extend to the Partnership or General Partners day-to-day business or operations. The Partnership and General Partner have agreed to indemnify Wexford and its affiliates from any and all losses arising out of or in connection with the Viper Advisory Services Agreement except for losses resulting from Wexford’s or its affiliates’ gross negligence or willful misconduct.

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Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Secondary Offering Costs

On June 27, 2014, Gulfport and certain entities controlled by Wexford completed an underwritten secondary public offering of 2,000,000 shares of the Company’s common stock. The shares were sold to the public at $90.04 per share and the selling stockholders received all proceeds from this offering after deducting the underwriting discount. The Company incurred estimated costs of approximately $40,000 related to this secondary public offering.

On June 24, 2013, Gulfport and certain entities controlled by Wexford completed an underwritten secondary public offering of 6,000,000 shares of the Company’s common stock and, on July 5, 2013, the underwriters purchased an additional 869,222 shares of the Company’s common stock from these selling stockholders pursuant to an option to purchase such additional shares granted to the underwriters. The shares were sold to the public at $34.75 per share and the selling stockholders received all proceeds from this offering after deducting the underwriting discount. The Company incurred costs of approximately $185,000 related to this secondary public offering.

11. DERIVATIVES

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

The Company has used price swap contracts to reduce price volatility associated with certain of its oil sales. With respect to the Company’s fixed price swap contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on Argus Louisiana light sweet pricing.

By using derivative instruments to hedge exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are participants in the secured second amended and restated credit agreement, which is secured by substantially all of the assets of the guarantor subsidiaries; therefore, the Company is not required to post any collateral. The Company does not require collateral from its counterparties. The Company has entered into derivative instruments only with counterparties that are also lenders in our credit facility and have been deemed an acceptable credit risk.

As of June 30, 2014, the Company had open crude oil derivative positions with respect to future production as set forth in the tables below. When aggregating multiple contracts, the weighted average contract price is disclosed.



Crude Oil—Argus Louisiana Light Sweet Fixed Price Swap

Production Period	Volume (Bbls)	Fixed Swap Price
July - December 2014	1,288,000	$	98.64
January - April 2015	331,000	99.71

Balance sheet offsetting of derivative assets and liabilities

The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions that are with the same counterparty and are subject to contractual terms which provide for net settlement.

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Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under master netting arrangements with counterparties and the resulting net amounts presented in the Company’s consolidated balance sheets as of June 30, 2014 and December 31, 2013.



	June 30, 2014

	(in thousands)
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Consolidated Balance Sheet			Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
Derivative liabilities	$	(10,379	)	$	—		$	(10,379	)

	December 31, 2013

	(in thousands)
	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Consolidated Balance Sheet			Net Amounts of Assets Presented in the Consolidated Balance Sheet
Derivative assets	$	998		$	(567	)	$	431

The net amounts are classified as current or noncurrent based on their anticipated settlement dates. The net fair value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:



	June 30,			December 31,
	2014			2013

	(in thousands)
Current Assets: Derivative instruments	$	—		$	213
Noncurrent Assets: Derivative instruments	—			218
Total Assets	$	—		$	431

Current Liabilities: Derivative instruments	$	(10,379	)	$	—
Noncurrent Liabilities: Derivative instruments	—			—
Total Liabilities	$	(10,379	)	$	—

None of the Company’s derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following table summarizes the gains and losses on derivative instruments included in the consolidated statements of operations:



	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013

	(in thousands)
Non-cash gain (loss) on open non-hedge derivative instruments	$	(7,468	)	$	3,893		$	(10,810	)	$	5,428
Loss on settlement of non-hedge derivative instruments	(3,620		)	(856		)	(4,676		)	(2,399		)
Gain (loss) on derivative instruments	$	(11,088	)	$	3,037		$	(15,486	)	$	3,029

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Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

12. FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.

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

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

Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments. The fair values of the Company’s fixed price crude oil swaps are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs.

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of June 30, 2014 and December 31, 2013.



		Fair value measurements at June 30, 2014 using:

	(in thousands)
		Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2			Significant Unobservable Inputs Level 3		Total
Liabilities:
Fixed price swaps		—		(10,379		)	—		(10,379		)

		Fair value measurements at December 31, 2013 using:

	(in thousands)
		Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2			Significant Unobservable Inputs Level 3		Total
Assets:
Fixed price swaps		$	—	$	431		$	—	$	431

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Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated financial statements.



	June 30, 2014				December 31, 2013
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value

	(in thousands)
Debt:
Revolving credit facility	$	46,000	$	46,000	$	10,000	$	10,000
7.625% Senior Notes due 2021	450,000		497,250		450,000		460,406

The fair value of the revolving credit facility approximates its carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes was determined using the June 30, 2014 quoted market price, a Level 1 classification in the fair value hierarchy.

13. CONTINGENCIES

In September 2010, Windsor Permian LLC (“Windsor Permian”) (now known as Diamondback O&G LLC) purchased certain property in Goodhue County, Minnesota, that was prospective for hydraulic fracturing grade sand. Prior to the purchase, the prior owners of the property had entered into a Mineral Development Agreement with the plaintiff and the Company purchased the property subject to that agreement. Windsor Permian subsequently contributed the property to Muskie. In an amended complaint filed in November 2012 by the plaintiff against the prior owners of the property, Windsor Permian and certain affiliates of Windsor Permian in the first judicial district court in Goodhue County, Minnesota, the plaintiff sought damages from the Company and the other defendants alleging, among other things, interference with contractual relationship, interference with prospective advantage and unjust enrichment. In an order filed on May 24, 2013, the judge denied certain motions made by the defendants and set a trial date to determine liability, with a damage phase of the matter to commence on a later date if there is a determination of liability. Following a trial on the liability phase on June 21, 2013, the jury determined that the defendants intentionally interfered with plaintiff’s contract but that the interference did not cause the plaintiff to be unable to acquire mining permits prior to the enactment of the moratorium by Goodhue County. In an order filed on July 10, 2013, the judge ordered the damage phase to be set for trial following a pretrial and scheduling conference. Subsequently, the plaintiff disclosed a new damage theory, and the defendants filed motions with the court to dismiss plaintiff’s claims on the grounds that the damage claim was speculative and that plaintiff could not prove damages as a matter of law. Plaintiff also filed a motion for leave to amend its complaint to assert a punitive damage claim. The motions were argued in December 2013. In March 2014, the judge entered an order granting the defendants’ motions to exclude testimony and for summary judgment. All parties agreed not to pursue an appeal from the order and waived any entitlement to costs, which effectively concluded this matter.

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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Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

14. SUBSEQUENT EVENTS

The Company entered into a definitive purchase agreement dated July 18, 2014 with unrelated third party sellers to acquire additional leasehold interests in Midland, Glasscock, Reagan and Upton Counties, Texas in the Permian Basin, for an aggregate purchase price of approximately $538.0 million, subject to certain adjustments. This transaction includes 16,773 gross (13,136 net) acres with a 78% working interest (approximately 75.1% net revenue interest). The proposed transaction is scheduled to close in early September 2014.

On July 25, 2014, the Company completed an underwritten public offering of 5,750,000 shares of common stock, which included 750,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the public at $87.00 per share and the Company received net proceeds of approximately $484.9 million from the sale of these shares of common stock, net of the underwriting discount and estimated offering expenses. The net proceeds from this offering will be used to partially fund the acquisition described above. To the extent the pending acquisition is not consummated, or the actual purchase price is less than the net proceeds from the offering, the Company intends to use the net proceeds from the offering to fund a portion of its exploration and development activities and for general corporate purposes, which may include leasehold interest and property acquisitions and working capital.

On July 25, 2014, the Company repaid all outstanding amounts under its credit agreement with Wells Fargo with a portion of the proceeds from its equity offering, pending reborrowing to fund a portion of the purchase price of the acquisition described above.

On July 8, 2014, the Partnership entered into a secured revolving credit agreement with Wells Fargo, as the administrative agent, sole book runner and lead arranger. The Partnership had outstanding borrowings of $50.0 million as of August 6, 2014. See Note—7 Debt for additional information.

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Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

15. GUARANTOR FINANCIAL STATEMENTS

Diamondback E&P and Diamondback O&G are unconditional guarantor’s (the “Guarantor Subsidiaries”) of the Senior Notes and the second amended and restated credit agreement. On June 23, 2014, in connection with the initial public offering of Viper Energy Partners LP the Company designated the Partnership, its general partner, Viper Energy Partners GP, and the Partnership’s subsidiary Viper Energy Partners LLC as unrestricted subsidiaries under the Indenture and upon such designation, Viper Energy Partners LLC, which was a guarantor under the Indenture prior to such designation, was released as a guarantor under the Indenture. Viper Energy Partners LLC is a limited liability company formed on September 18, 2013 to own and acquire mineral and other oil and natural gas interests in properties in the Permian Basin in West Texas. The following presents condensed consolidated financial information as of December 31, 2013 and 2012 and for the years ended December 31, 2013, 2012 and 2011 on an issuer (parent company), Guarantor Subsidiaries, Non–Guarantor Subsidiaries and consolidated basis. Elimination entries presented are necessary to combine the entities. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantor Subsidiaries operated as independent entities. The Company has not presented separate financial and narrative information for each of the Guarantor Subsidiaries because it believes such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the Guarantor Subsidiaries.

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Notes to Consolidated Financial Statements-(Continued)

(Unaudited)



Condensed Consolidated Balance Sheet
June 30, 2014
(In thousands)
						Non–
			Guarantor			Guarantor
	Parent		Subsidiaries			Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	7,504	$	22,460		$	7,029		$	—		$	36,993
Accounts receivable	—		58,177			7,168			—			65,345
Accounts receivable - related party	—		3,310			—			—			3,310
Intercompany receivable	1,139,057		1,142,456			—			(2,281,513		)	—
Inventories	—		3,308			—			—			3,308
Deferred income taxes	4,327		—			—			—			4,327
Other current assets	131		1,274			16			—			1,421
Total current assets	1,151,019		1,230,985			14,213			(2,281,513		)	114,704
Property and equipment
Oil and natural gas properties, at cost, based on the full cost method of accounting	—		1,738,012			453,309			—			2,191,321
Pipeline and gas gathering assets	—		6,846			—			—			6,846
Other property and equipment	—		4,973			—			—			4,973
Accumulated depletion, depreciation, amortization and impairment	—		(268,115		)	(16,830		)	1,793			(283,152		)
	—		1,481,716			436,479			1,793			1,919,988
Investment in subsidiaries	613,000		—			—			(613,000		)	—
Other assets	9,750		2,952			—			—			12,702
Total assets	$	1,773,769	$	2,715,653		$	450,692		$	(2,892,720	)	$	2,047,394
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	—	$	22,755		$	720		$	—		$	23,475
Accounts payable-related party	—		67			—			—			67
Intercompany payable	75,450		2,194,196			11,867			(2,281,513		)	—
Other current liabilities	8,675		135,226			1,434			—			145,335
Total current liabilities	84,125		2,352,244			14,021			(2,281,513		)	168,877
Long-term debt	450,000		46,000			—			—			496,000
Asset retirement obligations	—		5,437			—			—			5,437
Deferred income taxes	124,743		—			—			—			124,743
Total liabilities	658,868		2,403,681			14,021			(2,281,513		)	795,057
Commitments and contingencies
Stockholders’ equity:	1,114,901		311,972			436,671			(748,643		)	1,114,901
Noncontrolling interest	—		—			—			137,436			137,436
Total equity	1,114,901		311,972			436,671			(611,207		)	1,252,337
Total liabilities and equity	$	1,773,769	$	2,715,653		$	450,692		$	(2,892,720	)	$	2,047,394

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Notes to Consolidated Financial Statements-(Continued)

(Unaudited)



Condensed Consolidated Balance Sheet
December 31, 2013
(In thousands)
						Non–
			Guarantor			Guarantor
	Parent		Subsidiaries			Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	526	$	14,267		$	762		$	—		$	15,555
Accounts receivable	—		28,544			—			9,426			37,970
Accounts receivable - related party	—		1,303			—			—			1,303
Royalty income receivable	—		—			9,426			(9,426		)	—
Intercompany receivable	715,169		413,744			—			(1,128,913		)	—
Intercompany note receivable	440,000		—			—			(440,000		)	—
Inventories	—		5,631			—			—			5,631
Deferred income taxes	112		—			—			—			112
Other current assets	—		1,397			—			—			1,397
Total current assets	1,155,807		464,886			10,188			(1,568,913		)	61,968
Property and equipment
Oil and natural gas properties, at cost, based on the full cost method of accounting	—		1,200,326			448,034			—			1,648,360
Pipeline and gas gathering assets	—		6,142			—			—			6,142
Other property and equipment	—		4,071			—			—			4,071
Accumulated depletion, depreciation, amortization and impairment	—		(207,037		)	(5,199		)	—			(212,236		)
	—		1,003,502			442,835			—			1,446,337
Investment in subsidiaries	235,334		—			—			(235,334		)	—
Other assets	10,207		3,102			—			—			13,309
Total assets	$	1,401,348	$	1,471,490		$	453,023		$	(1,804,247	)	$	1,521,614
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	—	$	2,679		$	—		$	—		$	2,679
Accounts payable-related party	—		17			—			—			17
Intercompany payable	3,920		1,115,214			87			(1,119,221		)	—
Intercompany accrued interest	—		—			9,692			(9,692		)	—
Other current liabilities	10,123		108,245			256			—			118,624
Total current liabilities	14,043		1,226,155			10,035			(1,128,913		)	121,320
Long-term debt	450,000		10,000			—			—			460,000
Intercompany note payable	—		—			440,000			(440,000		)	—
Asset retirement obligations	—		2,989			—			—			2,989
Deferred income taxes	91,764		—			—			—			91,764
Total liabilities	555,807		1,239,144			450,035			(1,568,913		)	676,073
Commitments and contingencies
Stockholders’ equity:	845,541		232,346			2,988			(235,334		)	845,541
Total equity	845,541		232,346			2,988			(235,334		)	845,541
Total liabilities and equity	$	1,401,348	$	1,471,490		$	453,023		$	(1,804,247	)	$	1,521,614

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Notes to Consolidated Financial Statements-(Continued)

(Unaudited)



Condensed Consolidated Statement of Operations
Three Months Ended June 30, 2014
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues:
Oil sales	$	—		$	99,573		$	—		$	15,709		$	115,282
Natural gas sales	—			3,738			—			591			4,329
Natural gas liquid sales	—			6,444			—			949			7,393
Royalty income	—			—			17,249			(17,249		)	—
Total revenues	—			109,755			17,249			—			127,004
Costs and expenses:
Lease operating expenses	—			10,496			—			—			10,496
Production and ad valorem taxes	—			7,162			1,392			—			8,554
Gathering and transportation	—			703			—			—			703
Depreciation, depletion and amortization	—			34,616			5,405			—			40,021
General and administrative expenses	3,428			287			219			—			3,934
Asset retirement obligation accretion expense	—			104			—			—			104
Intercompany charges	—			—			78			—			—
Total costs and expenses	3,428			53,368			7,094			—			63,812
Income (loss) from operations	(3,428		)	56,387			10,155			—			63,192
Other income (expense)
Interest income - intercompany	5,387			—			—			(5,387		)	—
Interest expense	(6,657		)	(1,082		)	—			—			(7,739		)
Interest expense - intercompany	—			—			(5,387		)	5,387			—
Other income - related party	—			108			—			(78		)	30
Other expense	—			(1,408		)	—			—			(1,408		)
Gain (loss) on derivative instruments, net	—			(11,088		)	—			—			(11,088		)
Total other income (expense), net	(1,270		)	(13,470		)	(5,387		)	(78		)	(20,205		)
Income (loss) before income taxes	(4,698		)	42,917			4,768			(78		)	42,987
Provision for income taxes	15,163			—			—			—			15,163
Net income (loss)	(19,861		)	42,917			4,768			(78		)	27,824
Less: Net income attributable to noncontrolling interest	—			—			—			71			71
Net income (loss) attributable to Diamondback Energy, Inc.	$	(19,861	)	$	42,917		$	4,768		$	(149	)	$	27,753

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Notes to Consolidated Financial Statements-(Continued)

(Unaudited)



Condensed Consolidated Statement of Operations
Three Months Ended June 30, 2013
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries		Eliminations		Consolidated
Revenues:
Oil sales	$	—		$	41,034		$	—	$	—	$	41,034
Natural gas sales	—			1,668			—		—		1,668
Natural gas liquid sales	—			2,692			—		—		2,692
Total revenues	—			45,394			—		—		45,394
Costs and expenses:
Lease operating expenses	—			4,968			—		—		4,968
Production and ad valorem taxes	—			3,315			—		—		3,315
Gathering and transportation	—			247			—		—		247
Depreciation, depletion and amortization	—			14,815			—		—		14,815
General and administrative expenses	955			1,666			—		—		2,621
Asset retirement obligation accretion expense	—			45			—		—		45
Total costs and expenses	955			25,056			—		—		26,011
Income (loss) from operations	(955		)	20,338			—		—		19,383
Other income (expense)
Interest expense	—			(535		)	—		—		(535		)
Other income - related party	—			388			—		—		388
Gain on derivative instruments, net	—			3,037			—		—		3,037
Total other income (expense), net	—			2,890			—		—		2,890
Income (loss) before income taxes	(955		)	23,228			—		—		22,273
Provision for income taxes	7,802			—			—		—		7,802
Net income (loss)	$	(8,757	)	$	23,228		$	—	$	—	$	14,471

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)



Condensed Consolidated Statement of Operations
Six Months Ended June 30, 2014
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues:
Oil sales	$	—		$	176,868		$	—		$	30,671		$	207,539
Natural gas sales	—			8,168			—			1,169			9,337
Natural gas liquid sales	—			6,416			—			1,716			8,132
Royalty income	—			—			33,102			(33,102		)	—
Total revenues	—			191,452			33,102			454			225,008
Costs and expenses:
Lease operating expenses	—			18,411			—			—			18,411
Production and ad valorem taxes	—			12,065			2,331			—			14,396
Gathering and transportation	—			1,285			—			—			1,285
Depreciation, depletion and amortization	—			60,417			10,577			—			70,994
General and administrative expenses	7,413			793			285			—			8,491
Asset retirement obligation accretion expense	—			176			—			—			176
Intercompany charges	—			—			156			(156		)	—
Total costs and expenses	7,413			93,147			13,349			(156		)	113,753
Income (loss) from operations	(7,413		)	98,305			19,753			610			111,255
Other income (expense)
Interest income - intercompany	10,755			—			—			(10,755		)	—
Interest expense	(12,544		)	(1,700		)	—			—			(14,244		)
Interest expense - intercompany	—			—			(10,755		)	10,755			—
Other income - related party	—			216			—			(156		)	60
Other expense	—			(1,408		)	—			—			(1,408		)
Gain (loss) on derivative instruments, net	—			(15,486		)	—			—			(15,486		)
Total other income (expense), net	(1,789		)	(18,378		)	(10,755		)	(156		)	(31,078		)
Income (loss) before income taxes	(9,202		)	114,519			7,962			(33,102		)	80,177
Provision for income taxes	28,764			—			—			—			28,764
Net income (loss)	(37,966		)	114,519			7,962			(33,102		)	51,413
Less: Net income attributable to noncontrolling interest	—			—			—			71			71
Net income (loss) attributable to Diamondback Energy, Inc.	$	(37,966	)	$	114,519		$	7,962		$	(33,173	)	$	51,342

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)



Condensed Consolidated Statement of Operations
Six Months Ended June 30, 2013
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries		Eliminations		Consolidated
Revenues:
Oil sales	$	—		$	66,287		$	—	$	—	$	66,287
Natural gas sales	—			2,819			—		—		2,819
Natural gas liquid sales	—			5,197			—		—		5,197
Total revenues	—			74,303			—		—		74,303
Costs and expenses:
Lease operating expenses	—			10,403			—		—		10,403
Production and ad valorem taxes	—			4,742			—		—		4,742
Gathering and transportation	—			380			—		—		380
Depreciation, depletion and amortization	—			25,553			—		—		25,553
General and administrative expenses	1,696			3,396			—		—		5,092
Asset retirement obligation accretion expense	—			88			—		—		88
Total costs and expenses	1,696			44,562			—		—		46,258
Income (loss) from operations	(1,696		)	29,741			—		—		28,045
Other income (expense)
Interest expense	—			(1,020		)	—		—		(1,020		)
Other income - related party	—			777			—		—		777
Gain (loss) on derivative instruments, net	—			3,029			—		—		3,029
Total other income (expense), net	—			2,786			—		—		2,786
Income (loss) before income taxes	(1,696		)	32,527			—		—		30,831
Provision for income taxes	10,964			—			—		—		10,964
Net income (loss)	$	(12,660	)	$	32,527		$	—	$	—	$	19,867

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)



Condensed Consolidated Statement of Cash Flows
Six Months Ended June 30, 2014
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Net cash provided by operating activities	$	(2,145	)	$	138,172		$	14,064		$	9,615		$	159,706

Cash flows from investing activities:
Additions to oil and natural gas properties	—			(204,075		)	(5,275		)	—			(209,350		)
Acquisition of leasehold interests	—			(312,207		)	—			—			(312,207		)
Intercompany transfers	(203,169		)	223,169			—			(20,000		)	—
Other investing activities	—			(2,088		)	—			—			(2,088		)
Net cash used in investing activities	(203,169		)	(295,201		)	(5,275		)	(20,000		)	(523,645		)
Cash flows from financing activities:
Proceeds from borrowing on credit facility	—			166,000			—			—			166,000
Repayment on credit facility	—			(130,000		)	—			—			(130,000		)
Proceeds from public offerings	208,644			—			139,035			—			347,679
Distribution to parent	—			—			(137,500		)	137,500			—
Intercompany transfers	—			130,000			—			(130,000		)	—
Other financing activities	3,648			(778		)	(4,057		)	2,885			1,698
Net cash provided by (used in) financing activities	212,292			165,222			(2,522		)	10,385			385,377

Net increase in cash and cash equivalents	6,978			8,193			6,267			—			21,438
Cash and cash equivalents at beginning of period	526			14,267			762			—			15,555
Cash and cash equivalents at end of period	$	7,504		$	22,460		$	7,029		$	—		$	36,993

Table of Contents

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)



Condensed Consolidated Statement of Cash Flows
Six Months Ended June 30, 2013
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries		Eliminations		Consolidated
Net cash provided by operating activities	$	6		$	49,792		$	—	$	—	$	49,798

Cash flows from investing activities:
Additions to oil and natural gas properties	—			(112,083		)	—		—		(112,083		)
Acquisition of leasehold interests	—			(24,742		)	—		—		(24,742		)
Intercompany transfers	(20,132		)	20,132			—		—		—
Other investing activities	—			(1,850		)	—		—		(1,850		)
Net cash used in investing activities	(20,132		)	(118,543		)	—		—		(138,675		)
Cash flows from financing activities:
Proceeds from borrowing on credit facility	—			49,000			—		—		49,000
Repayment on credit facility	—			(49,000		)	—		—		(49,000		)
Proceeds from public offerings	144,936			—			—		—		144,936
Distribution to parent	—			—			—		—		—
Intercompany transfers	(49,000		)	49,000			—		—		—
Other financing activities	(447		)	(72		)	—		—		(519		)
Net cash provided by (used in) financing activities	95,489			48,928			—		—		144,417

Net increase in cash and cash equivalents	75,363			(19,823		)	—		—		55,540
Cash and cash equivalents at beginning of period	14			26,344			—		—		26,358
Cash and cash equivalents at end of period	$	75,377		$	6,521		$	—	$	—	$	81,898

Diamondback Energy, Inc. - FORM 8-K - EX-99.5 - EXHIBIT - September 12, 2014

Attached files

Diamondback Energy, Inc. Reports