UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



ý	QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED ~~September 30, 2014~~March 31, 2015



¨o	TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934

Commission File Number 001-35700

Diamondback Energy, Inc.

(Exact Name of Registrant As Specified in Its Charter)



Delaware		45-4502447
(State or Other Jurisdiction of Incorporation or Organization)		(IRS Employer Identification Number)

500 West Texas, Suite 1200 Midland, Texas		79701
(Address of Principal Executive Offices)		(Zip Code)

(432) 221-7400

(Registrant Telephone Number, Including Area Code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No ý

As of ~~October 29, 2014, 56,752,819~~May 5, 2015, 59,009,236 shares of the registrant’s common stock were outstanding.

~~DIAMONDBACK ENERGY, INC.~~ ~~TABLE OF CONTENTS~~

		Page
PART I. FINANCIAL INFORMATION
ITEM1.	Consolidated Financial Statements of Diamondback Energy, Inc. (unaudited)	1
	Consolidated Balance Sheets as of ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013~~2014	1
	Consolidated ~~Statements~~Statement of Operations for the Three ~~and Nine~~ Months Ended ~~September 30, 2014 and 2013~~March 31, 2015	2
	Consolidated Statement of Stockholders’ Equity for the ~~Nine~~Three Months Ended ~~September 30, 2014~~March 31, 2015	3
	Consolidated ~~Statements~~Statement of Cash Flows for the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2015 and 2014 ~~and 2013~~	4
	Notes to Consolidated Financial Statements	6
ITEM 2.	Management’s Discussion and Analysis of Financial Conditions and Results of Operations	3732
ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk	5142
ITEM 4.	Controls and Procedures	5243
PART II OTHER INFORMATION
ITEM 1.	Legal Proceedings	5444
ITEM 1A.	Risk Factors	5444
ITEM 6.	Exhibits	5445
Signatures		5647

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a description of the meanings of some of the oil and natural gas industry terms used throughout this report:

3-D seismic. Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.

Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.

Bbls/d. Bbls per day.

Brent. Brent sweet light crude oil.

BOE. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

BOE/d. BOE per day.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Exploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Finding and development costs. Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.

Fracturing. The process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle with a specified interval.

LLS. Light Louisiana sweet crude oil.

MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.

MBOE. One thousand barrels of crude oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Mcf. Thousand cubic feet of natural gas.

Mcf/d. Mcf per day.

MMBtu. Million British Thermal Units.

MMcf. Million cubic feet of natural gas.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.

Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

PDP. Proved developed producing.

Play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

PUD. Proved undeveloped.

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

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves. The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Recompletion. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Stratigraphic play. An oil or natural gas formation contained within an area created by permeability and porosity changes characteristic of the alternating rock layer that result from the sedimentation process.

Structural play. An oil or natural gas formation contained within an area created by earth movements that deform or rupture (such as folding or faulting) rock strata.

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

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

WTI. West Texas Intermediate, also known as Texas light sweet crude oil.

iii

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, or the Exchange Act. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this ~~quarterly~~ report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” ~~“project,”~~“project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed in this ~~quarterly report~~Quarterly Report on Form 10–Q and detailed under

Part II, Item 1A. Risk Factorsin this report and our Annual Report on Form 10–K for the year ended December 31, ~~2013~~

2014 could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted or implied in such forward-looking statements.

Forward-looking statements may include statements about our:

business strategy;

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

oil and natural gas reserves;

identified drilling locations;

ability to obtain permits and governmental approvals;

technology;

financial strategy;

realized oil and natural gas prices;

production;

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

future operating results; and

plans, objectives, expectations and intentions.

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

Table of Contents

Diamondback Energy, Inc. and Subsidiaries

Consolidated Balance Sheets

(Unaudited)



	March 31,			December 31,
	2015			2014

	(In thousands, except par values and share data)
Assets
Current assets:
Cash and cash equivalents	$	31,643		$	30,183
Restricted cash	500			500
Accounts receivable:
Joint interest and other	44,563			50,943
Oil and natural gas sales	38,647			43,050
Related party	—			4,001
Inventories	2,847			2,827
Derivative instruments	92,335			115,607
Prepaid expenses and other	4,837			4,600
Total current assets	215,372			251,711
Property and equipment
Oil and natural gas properties, based on the full cost method of accounting ($737,197 and $773,520 excluded from amortization at March 31, 2015 and December 31, 2014, respectively)	3,211,981			3,118,597
Pipeline and gas gathering assets	7,174			7,174
Other property and equipment	48,338			48,180
Accumulated depletion, depreciation, amortization and impairment	(441,821		)	(382,144		)
	2,825,672			2,791,807
Derivative instruments	—			1,934
Other assets	51,437			50,029
Total assets	$	3,092,481		$	3,095,481
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	8,801		$	26,230
Accrued capital expenditures	75,272			129,397
Other accrued liabilities	50,952			41,149
Revenues and royalties payable	16,546			30,000
Deferred income taxes	32,459			39,953
Total current liabilities	184,030			266,729
Long-term debt	611,579			673,500
Asset retirement obligations	8,844			8,447
Deferred income taxes	171,511			161,592
Total liabilities	975,964			1,110,268
Contingencies (Note 14)
Stockholders’ equity:
Common stock, $0.01 par value, 100,000,000 shares authorized, 59,008,403 issued and outstanding at March 31, 2015; 57,887,583 issued and outstanding at December 31, 2014	590			569
Additional paid-in capital	1,680,394			1,554,174
Retained earnings	202,117			196,268
Total Diamondback Energy, Inc. stockholders’ equity	1,883,101			1,751,011
Noncontrolling interest	233,416			234,202
Total equity	2,116,517			1,985,213
Total liabilities and equity	$	3,092,481		$	3,095,481

September 30, December 31,
2014 2013

(In thousands, except par values and share data)
Assets
Current assets:
Cash and cash equivalents $ 40,644
$ 15,555
Accounts receivable:
Joint interest and other 39,626
14,437
Oil and natural gas sales 46,687
23,533
Related party 3,915
1,303
Inventories 3,105
5,631
Deferred income taxes —
112
Derivative instruments 6,061
213
Prepaid expenses and other 3,223
1,184
Total current assets 143,261
61,968
Property and equipment
Oil and natural gas properties, based on the full cost method of accounting ($867,479 and $369,561 excluded from amortization at September 30, 2014 and December 31, 2013, respectively) 2,900,293
1,648,360
Pipeline and gas gathering assets 7,102
6,142
Other property and equipment 47,286
4,071
Accumulated depletion, depreciation, amortization and impairment (328,522 ) (212,236 )
2,626,159
1,446,337
Derivative instruments —
218
Other assets 51,135
13,091
Total assets $ 2,820,555
$ 1,521,614
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade $ 8,009
$ 2,679
Accounts payable-related party —
17
Accrued capital expenditures 118,514
74,649
Other accrued liabilities 50,768
34,750
Revenues and royalties payable 17,951
9,225
Deferred income taxes 1,044
—
Total current liabilities 196,286
121,320
Long-term debt 590,000
460,000
Asset retirement obligations 8,115
2,989
Deferred income taxes 140,308
91,764
Total liabilities 934,709
676,073
Contingencies (Note 13)

Stockholders’ equity:
Common stock, $0.01 par value, 100,000,000 shares authorized, 56,680,359 issued and outstanding at September 30, 2014; 47,106,216 issued and outstanding at December 31, 2013 567
471
Additional paid-in capital 1,553,367
842,557
Retained earnings 97,594
2,513
Total Diamondback Energy, Inc. stockholders’ equity 1,651,528
845,541
Noncontrolling interest 234,318

—
Total equity 1,885,846
845,541
Total liabilities and equity $ 2,820,555
$ 1,521,614

See accompanying notes to combined consolidated financial statements.

Table of Contents

Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

(Unaudited)

Three Months Ended September 30, Nine Months Ended September 30,
2014 2013 2014 2013

(In thousands, except per share amounts)
Revenues:
Oil sales $ 126,406
$ 53,086
$ 331,446
$ 119,373
Natural gas sales 2,338
859
6,006
2,586
Natural gas sales - related party 2,374
704
6,370
1,796
Natural gas liquid sales 3,619
1,970
9,507
5,441
Natural gas liquid sales - related party 4,390
1,172
10,806
2,898
Total revenues 139,127
57,791
364,135
132,094
Costs and expenses:
Lease operating expenses 13,766
4,718
31,998
14,527
Lease operating expenses - related party 39
246
218
840
Production and ad valorem taxes 8,634
3,420
22,318
7,970
Production and ad valorem taxes - related party 320
133
1,032
325
Gathering and transportation 110
69
426
175
Gathering and transportation - related party 750
192
1,719
466
Depreciation, depletion and amortization 45,370
17,423
116,364
42,976
General and administrative expenses (including non-cash stock based compensation, net of capitalized amounts, of $2,069 and $490 for the three months ended September 30, 2014 and 2013, respectively, and $5,387 and $1,426 for the nine months ended September 30, 2014 and 2013, respectively) 6,016
1,810
13,891
6,350
General and administrative expenses - related party 479
311
1,095
863
Asset retirement obligation accretion expense 127
46
303
134
Total costs and expenses 75,611
28,368
189,364
74,626
Income from operations 63,516
29,423
174,771
57,468
Other income (expense)
Interest income —
1
—
1
Interest expense (9,846 ) (1,089 ) (24,090 ) (2,109 )
Other income 17
—
17
—
Other income - related party 31
270
91
1,047
Other expense (8 ) —
(1,416 ) —
Gain (loss) on derivative instruments, net 14,909
(4,910 ) (577 ) (1,881 )
Total other income (expense), net 5,103
(5,728 ) (25,975 ) (2,942 )
Income before income taxes 68,619
23,695
148,796
54,526
Provision for income taxes
Current 3,982
—
3,982
—
Deferred 19,996
9,099
48,760
20,063
Net income 44,641
14,596
96,054
34,463
Less: Net income attributable to noncontrolling interest 902
—
973
—
Net income attributable to Diamondback Energy, Inc. $ 43,739
$ 14,596
$ 95,081
$ 34,463

Earnings per common share
Basic $ 0.79
$ 0.33
$ 1.85
$ 0.85
Diluted $ 0.79
$ 0.33
$ 1.83
$ 0.85
Weighted average common shares outstanding
Basic 55,152
44,385
51,489
40,309
Diluted 55,442
44,698
51,888
40,524



	Three Months Ended March 31,
	2015			2014

	(In thousands, except per share amounts)
Revenues:
Oil sales	$	92,916		$	89,758
Natural gas sales	1,708			1,755
Natural gas sales - related party	2,640			1,580
Natural gas liquid sales	1,593			2,584
Natural gas liquid sales - related party	2,544			2,327
Total revenues	101,401			98,004
Costs and expenses:
Lease operating expenses	22,456			7,807
Lease operating expenses - related party	—			108
Production and ad valorem taxes	8,242			5,578
Production and ad valorem taxes - related party	153			264
Gathering and transportation	61			214
Gathering and transportation - related party	969			368
Depreciation, depletion and amortization	59,677			30,973
General and administrative expenses (including non-cash stock based compensation, net of capitalized amounts, of $4,924 and $2,190 for the three months ended March 31, 2015 and 2014, respectively)	7,751			4,265
General and administrative expenses - related party	485			292
Asset retirement obligation accretion expense	170			72
Total costs and expenses	99,964			49,941
Income from operations	1,437			48,063
Other income (expense)
Interest expense	(10,497		)	(6,505		)
Other income	492			—
Other income - related party	23			30
Gain (loss) on derivative instruments, net	18,354			(4,398		)
Total other income (expense), net	8,372			(10,873		)
Income before income taxes	9,809			37,190
Provision for income taxes
Current	945			—
Deferred	2,425			13,601
Net income	6,439			23,589
Less: Net income attributable to noncontrolling interest	590			—
Net income attributable to Diamondback Energy, Inc.	$	5,849		$	23,589

Earnings per common share
Basic	$	0.10		$	0.49
Diluted	$	0.10		$	0.48
Weighted average common shares outstanding
Basic	58,386			48,447
Diluted	58,626			48,867

See accompanying notes to combined consolidated financial statements.

Table of Contents

Diamondback Energy, Inc. and Subsidiaries

Consolidated Statement of Stockholders’ Equity

(Unaudited)


																	Retained
				Additional											Additional		Earnings/
	Common Stock			Paid-in		Retained		Non-controlling				Common Stock			Paid-in		(Accumulated		Non-controlling
	Shares	Amount		Capital		Earnings		Interest		Total		Shares	Amount		Capital		Deficit)		Interest			Total

	(In thousands)
Balance December 31, 2013	47,106	$	471	$	842,557	$	2,513	$	—	$	845,541	47,106	$	471	$	842,557	$	2,513	$	—		$	845,541

Net proceeds from issuance of common units - Viper Energy Partners LP	—	—		—		—		232,334		232,334		—	—		—		—		—			—
Unit-based compensation	—	—		—		—		1,011		1,011		—	—		—		—		—			—
Distribution to non-controlling interest												—	—		—		—		—			—
Stock based compensation	—	—		9,134		—		—		9,134		—	—		3,256		—		—			3,256
Tax benefits related to stock-based compensation	—	—		3,173		—		—		3,173		—	—		—		—		—			—
Common shares issued in public offering, net of offering costs	9,200	92		693,289		—		—		693,381		3,450	35		208,410		—		—			208,445
Exercise of stock options and vesting of restricted stock units	380	4		5,214		—		—		5,218		145	2		2,076		—		—			2,078
Equity payment- Wexford Advisory Services (See Note 11)												—	—		—		—		—			—
Net income	—	—		—		95,081		973		96,054		—	—		—		23,589		—			23,589
Balance September 30, 2014	56,686	$	567	$	1,553,367	$	97,594	$	234,318	$	1,885,846
Balance March 31, 2014												50,701	$	508	$	1,056,299	$	26,102	$	—		$	1,082,909

Balance December 31, 2014												56,888	$	569	$	1,554,174	$	196,268	$	234,202		$	1,985,213

Unit-based compensation												—	—		—		—		939			939
Stock-based compensation												—	—		6,125		—		—			6,125
Distribution to noncontrolling interest												—	—		—		—		(2,315		)	(2,315		)
Common shares issued in public offering, net of offering costs												2,012	20		119,208		—		—			119,228
Exercise of stock options and vesting of restricted stock units												108	1		887		—		—			888
Net income												—	—		—		5,849		590			6,439
Balance March 31, 2015												59,008	$	590	$	1,680,394	$	202,117	$	233,416		$	2,116,517

See accompanying notes to combined consolidated financial statements.

Table of Contents

Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)


	Nine Months Ended September 30,						Three Months Ended March 31,
	2014			2013			2015			2014

	(In thousands)						(In thousands)
Cash flows from operating activities:
Net income	$	96,054		$	34,463		$	6,439		$	23,589
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for deferred income taxes	48,760			20,063			2,425			13,601
Excess tax benefit from stock-based compensation	749			—
Asset retirement obligation accretion expense	303			134			170			72
Depreciation, depletion, and amortization	116,364			42,976			59,677			30,973
Amortization of debt issuance costs	1,505			526			630			458
Change in fair value of derivative instruments	(5,630		)	(3,733		)	25,206			3,342
Stock based compensation expense	5,387			1,426			4,924			2,190
(Gain) loss on sale of assets, net	1,405			(31		)	—			(11		)
Changes in operating assets and liabilities:
Accounts receivable	(33,985		)	(13,262		)	7,005			(12,490		)
Accounts receivable-related party	(2,612		)	(350		)	—			(995		)
Inventories	915			309			(20		)	(258		)
Prepaid expenses and other	(5,681		)	(1,376		)	(237		)	(311		)
Accounts payable and accrued liabilities	7,812			7,324			(16,226		)	7,590
Accounts payable and accrued liabilities-related party	(17		)	(82		)	14,128			296
Accrued interest	11,940			—			8,476			—
Revenues and royalties payable	8,726			3,260			(13,454		)	3,420
Net cash provided by operating activities	251,995			91,647			99,143			71,466
Cash flows from investing activities:
Additions to oil and natural gas properties	(309,009		)	(188,201		)	(144,397		)	(84,211		)
Additions to oil and natural gas properties-related party	(3,410		)	(11,594		)	(7,000		)	(1,650		)
Acquisition of Gulfport properties	—			(18,550		)
Acquisition of mineral interests	(57,688		)	(440,000		)
Acquisition of leasehold interests	(840,482		)	(166,635		)	(2,000		)	(312,207		)
Pipeline and gas gathering assets	(1,437		)	—			—			(532		)
Purchase of other property and equipment	(43,215		)	(4,965		)	(158		)	(595		)
Proceeds from sale of property and equipment	11			62			—			11
Cost method investment	(33,851		)	—
Settlement of non-hedge derivative instruments	—			(289		)
Net cash used in investing activities	(1,289,081		)	(830,172		)	(153,555		)	(399,184		)
Cash flows from financing activities:
Proceeds from borrowings on credit facility	425,900			49,000			57,501			127,000
Repayment on credit facility	(295,900		)	(49,000		)	(119,422		)	—
Proceeds from senior notes	—			450,000
Debt issuance costs	(2,358		)	(9,524		)	(8		)	(82		)
Public offering costs	(2,203		)	(505		)	(194		)	(75		)
Proceeds from public offerings	928,432			322,680			119,422			208,644
Exercise of stock options	5,131			2,616			888			1,990
Excess tax benefits of stock-based compensation	3,173			—
Distribution to non-controlling interest							(2,315		)	—
Net cash provided by financing activities	1,062,175			765,267			55,872			337,477
Net increase in cash and cash equivalents	25,089			26,742			1,460			9,759
Cash and cash equivalents at beginning of period	15,555			26,358			30,183			15,555
Cash and cash equivalents at end of period	$	40,644		$	53,100		$	31,643		$	25,314

~~See accompanying notes to consolidated financial statements.~~

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Diamondback Energy, Inc. and Subsidiaries

Combined Consolidated Statements of Cash Flows - Continued

(Unaudited)


	Nine Months Ended September 30,				Three Months Ended March 31,
	2014		2013		2015			2014

	(In thousands)				(In thousands)
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest	$	12,729	$	383	$	1,389		$	149
Supplemental disclosure of non-cash transactions:
Asset retirement obligation incurred	$	567	$	162	$	102		$	214
Asset retirement obligation revisions in estimated liability	$	588	$	—	$	78		$	588
Asset retirement obligation acquired	$	3,678	$	471	$	47		$	1,294
Change in accrued capital expenditures	$	43,865	$	25,793	$	(45,854	)	$	(6,932	)
Capitalized stock based compensation	$	4,758	$	679	$	2,139		$	1,066

See accompanying notes to combined 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. 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, and the Company’s common units represented an approximate 92% limited partner interest in the Partnership. On September 19, 2014, the Partnership completed an underwritten public offering of 3,500,000 common units. At the completion of this offering, the Company owned approximately 88% of the common units of the Partnership. See Note 4—Viper Energy Partners LP for additional information regarding the Partnership.

The ~~wholly owned~~wholly-owned subsidiaries of Diamondback, as of ~~September 30, 2014,~~March 31, 2015, include Diamondback E&P LLC, a Delaware limited liability company, Diamondback O&G LLC, a Delaware limited liability company, Viper Energy Partners GP LLC, a Delaware limited liability company, and White Fang Energy LLC, a Delaware limited liability company. The consolidated subsidiaries include the ~~wholly owned~~wholly-owned subsidiaries as well as Viper Energy Partners LP, a Delaware limited partnership, and Viper Energy Partners LLC, a Delaware limited liability company.

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 ~~September 30, 2014,~~March 31, 2015, the Company owned approximately 88% of the common units of the Partnership and the Company’s wholly owned subsidiary, Viper Energy Partners GP LLC, is the General Partner of the Partnership.

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~~,2014, 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

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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.

~~Recent~~New Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers”. ASU 2014-09 supersedes most of the existing revenue recognition requirements in ~~accounting principles generally accepted in the United States~~GAAP and requires (i) an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) requires expanded disclosures regarding the nature, amount, timing, and certainty of revenue and cash flows from contracts with customers. The standard will be effective for annual and interim reporting periods beginning after December 15, 2016, with early application not permitted. The standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The ~~Company~~Partnership is currently evaluating the impact, ~~this standard~~if any, that the adoption of ASU 2014-09 will have on ~~its~~the Partnership’s financial position, results of operations, ~~or cash flows.~~and liquidity.

In April 2015, the Financial Accounting Standards Board issued ASU 2015-03, “Interest—Imputation of Interest”. ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from that debt liability, consistent with the presentation of a debt discount to simplify the presentation of debt issuance costs. The standard will be effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within fiscal years beginning after December 15, 2016. Early application will be permitted for financial statements that have not previously been issued.

3. ACQUISITIONS

2014 Activity

On September 9, 2014, the Company completed the acquisition of oil and natural gas interests in the Permian Basin from unrelated third party sellers. The Company acquired approximately 17,617 gross (12,967 net) acres with an approximate 74% working interest (approximately 75% net revenue interest). The acquisition was accounted for according to the acquisition method, which requires the recording of net assets acquired and consideration transferred at fair value. This acquisition was funded ~~in part by~~with the net proceeds of the July 2014 equity offering discussed in Note 9 below and borrowings under the Company’s revolving credit facility discussed in Note 8 below.

~~The following represents~~There were no material changes from the ~~estimated fair values of~~purchase price allocation disclosed in the ~~assets and liabilities assumed~~Company’s Annual Report on Form 10-K for the ~~acquisition date. The aggregate consideration transferred was $523,260,000 in cash, subject to post-closing adjustments, resulting in no goodwill or bargain purchase gain.~~

(in thousands)
Joint interest receivables $ 42
Proved oil and natural gas properties 128,589
Unevaluated oil and natural gas properties 400,527
Total assets acquired 529,158
Accrued production and ad valorem taxes 358
Revenues payable 3,174
Asset retirement obligations 2,366
Total liabilities assumed 5,898
Total fair value of net assets $ 523,260
year ended December 31, 2014.

The Company has included in its combined consolidated statements of operations revenues of ~~$2,804,000~~$5.3 million and direct operating expenses of ~~$1,424,000~~$3.7 million for the ~~period from September 9, 2014 to September 30, 2014~~three months ended March 31, 2015 due to the acquisition. The disclosure of net earnings is impracticable to calculate due to the full cost method of depletion.

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~~Diamondback Energy, Inc. and Subsidiaries~~

~~Notes to Consolidated Financial Statements-(Continued)~~

~~(Unaudited)~~

On August 25, 2014, the Company completed an acquisition of surface rights in the Permian Basin from an unrelated third party seller. The Company acquired surface rights to approximately 4,200 acres for approximately $41.9 million.

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~~with the net proceeds of the February 2014 equity offering discussed in Note 9 below and borrowings under the Company’s revolving credit facility discussed in Note 8 below.

~~The following represents~~There were no material changes from the ~~estimated fair values of~~purchase price allocation disclosed in the ~~assets and liabilities assumed~~Company’s Annual Report on Form 10-K for 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
Total assets acquired 293,417
Asset retirement obligations 1,258
Total liabilities assumed 1,258
Total fair value of net assets $ 292,159
year ended December 31, 2014.

The Company has included in its combined consolidated statements of operations revenues of ~~$30,965,000~~$6.8 million and direct operating expenses of ~~$4,738,000~~$3.0 million for the three months ended March 31, 2015 and operations revenues of

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

$4.9 million and direct operating expenses of $1.1 million for the period from February 28, 2014 to ~~September 30,~~March 31, 2014, due to the acquisitions. The disclosure of net earnings is impracticable to calculate due to the full cost method of depletion.

During the nine months ended September 30, 2014, the Partnership acquired (i) mineral interests underlying an aggregate of approximately 10,565 gross (3,461) net acres in the Midland and Delaware basins for approximately $57.7 million and (ii) a minor equity interest in an entity that owns mineral, overriding royalty, net profits, leasehold and other similar interests for approximately $33.9 million. The equity interest is so minor that we have no influence over partnership operating and financial polices and is accounted for under the cost method.

Pro Forma Financial Information

The following unaudited summary pro forma combined consolidated statement of operations data of Diamondback for the three months ~~and nine months~~ ended ~~September 30,~~March 31, 2014 ~~and 2013~~ have been prepared to give effect to the February 27 and 28, 2014 acquisitions and the September 9, 2014 acquisition 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.


									Pro Forma
	Three Months Ended September 30,				Nine Months Ended September 30,				(Unaudited)
	2014		2013		2014		2013		Three Months Ended
									March 31, 2014
	(Pro Forma)
	(in thousands, except per share amounts)								(in thousands)
Revenues	$	139,127	$	87,809	$	409,520	$	214,671	$	119,944
Income from operations	63,516		44,300		186,483		90,967		54,698
Net income	43,739		23,760		102,583		55,576		27,797
Basic earnings per common share	$	0.74	$	0.46	$	1.74	$	1.09
Diluted earnings per common share	$	0.74	$	0.46	$	1.73	$	1.08

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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 a ~~21.4%~~ ~~royalty interest on all production on an acreage weighted basis 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. Viper Energy Partners GP LLC, a ~~fully~~fully- consolidated subsidiary of Diamondback, serves as the general partner of, and holds a non-economic general partner interest in, the Partnership. As of ~~September 30, 2014,~~March 31, 2015, the Company owned approximately 88% of the common units of the Partnership.

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 $11.6 million and the net proceeds from the Viper Offering. As of September 30, 2014, the Partnership had distributed $148.8 million to Diamondback. 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. During the three months ended March 31, 2015, the Partnership distributed $17.6 million to Diamondback in respect of its common units.

On September 19, 2014, the Partnership completed an underwritten public offering of 3,500,000 common units. The common units were sold to the public at $28.50 per unit and the Partnership received net proceeds of approximately $95.1 million from the sale of these common units, net of offering expenses and underwriting discounts and commissions.

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~~Diamondback Energy, Inc. and Subsidiaries~~

~~Notes to Consolidated Financial Statements-(Continued)~~

~~(Unaudited)~~

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.

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.

Other Agreements

See Note ~~10—~~11—Related Party Transactions for details of ~~the~~ the advisory services agreement the Partnership and General Partner entered into with Wexford Capital LP (“Wexford”).

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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—8—Debt for a description of this credit facility.

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~~Diamondback Energy, Inc. and Subsidiaries~~

~~Notes to Consolidated Financial Statements-(Continued)~~

~~(Unaudited)~~

5. PROPERTY AND EQUIPMENT

Property and equipment includes the following:


	September 30,			December 31,			March 31,			December 31,
	2014			2013			2015			2014

	(in thousands)						(in thousands)
Oil and natural gas properties:
Subject to depletion	$	2,032,814		$	1,278,799		$	2,474,784		$	2,345,077
Not subject to depletion-acquisition costs
Incurred in 2015							3,906			—
Incurred in 2014	594,465			—			563,091			576,802
Incurred in 2013	203,863			279,353			106,139			130,474
Incurred in 2012	68,387			87,252			63,297			65,480
Incurred in 2011	764			1,598			764			764
Incurred in 2010	—			1,358
Total not subject to depletion	867,479			369,561			737,197			773,520
Gross oil and natural gas properties	2,900,293			1,648,360			3,211,981			3,118,597
Less accumulated depreciation, depletion, amortization and impairment	(326,228		)	(210,837		)
Less accumulated depletion							(438,720		)	(379,481		)
Oil and natural gas properties, net	2,574,065			1,437,523			2,773,261			2,739,116
Pipeline and gas gathering assets, net	6,998			6,142
Other property and equipment, net	45,096			2,672
Pipeline and gas gathering assets							7,174			7,174
Other property and equipment							48,338			48,180
Less accumulated depreciation							(3,101		)	(2,663		)
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment	$	2,626,159		$	1,446,337		$	2,825,672		$	2,791,807

~~The average depletion rate per barrel equivalent unit of production was~~ ~~$23.71~~ ~~and $24.39 for the~~ ~~three months and nine months endedSeptember 30, 2014, respectively, and~~ ~~$25.24~~ ~~and $24.76 for the three months and nine months ended September 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 $~~2,383,000~~4.7 million and ~~$7,311,000 for the~~ ~~three months and nine months endedSeptember 30, 2014, respectively, and $1,038,000 and $2,678,000~~$2.3 million for the three months ended March 31, 2015 and ~~nine months ended September 30, 2013,~~2014, 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.

119

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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:


	Nine Months Ended
	September 30,						Three Months Ended March 31,
	2014			2013			2015		2014

	(in thousands)						(in thousands)
Asset retirement obligation, beginning of period	$	3,029		$	2,145		$	8,486	$	3,029
Additional liability incurred	567			162			102		214
Liabilities acquired	3,678			471			47		1,294
Liabilities settled	(10		)	(14		)	—		(10		)
Accretion expense	303			134			170		72
Revisions in estimated liabilities	588			—			78		588
Asset retirement obligation, end of period	8,155			2,898			8,883		5,187
Less current portion	40			20			39		40
Asset retirement obligations - long-term	$	8,115		$	2,878		$	8,844	$	5,147

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. EQUITY METHOD INVESTMENTS

In October 2014, the Company paid $0.6 million for a minority interest in an entity that was formed to develop, own and operate an integrated water management system to gather, store, process, treat, distribute and dispose of water to exploration and production companies operating in Midland, Martin and Andrews Counties, Texas. The board of this entity may also authorize the entity to offer these services to other counties in the Permian Basin and to pursue other business opportunities. The Company has committed to invest an aggregate amount of $5.0 million in this entity, and several other third parties have committed to invest an aggregate of $15.0 million. The Company will retain a minority interest after all commitments are received. The entity was formed as a limited liability company and maintains a specific ownership account for each investor, similar to a partnership capital account structure. Therefore the Company accounts for this investment under the equity method of accounting.

8. DEBT

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


	September 30,		December 31,		March 31,		December 31,
	2014		2013		2015		2014

	(in thousands)				(in thousands)
Revolving credit facility	$	140,000	$	10,000	$	161,579	$	223,500
7.625 % Senior Notes due 2021	450,000		450,000		450,000		450,000
Partnership revolving credit facility					—		—
Total long-term debt	$	590,000	$	460,000	$	611,579	$	673,500

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 of ~~September 30, 2014,~~March 31, 2015, the Senior Notes are ~~now~~ fully and unconditionally guaranteed by Diamondback O&G LLC, Diamondback E&P LLC and White Fang Energy 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, as ~~amended and~~ supplemented (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

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~~Diamondback Energy, Inc. and Subsidiaries~~

~~Notes to Consolidated Financial Statements-(Continued)~~

~~(Unaudited)~~

repurchase, capital stock, prepay subordinated 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

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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 declared effective by the SEC on September 15, 2014 and the exchange offer completed on October 23, 2014.

Credit Facility-Wells Fargo Bank

~~The Company’s secured~~On June 9, 2014, Diamondback entered into a first amendment (the “first amendment”) and on November 13, 2014, Diamondback entered into a second amendment (the “second amendment”) to the second amended and restated credit agreement, dated November 1, 2013 (together, the “credit agreement”). The first amendment modified certain provisions of the credit agreement to, among other things, allow the Company to designate one or more of its subsidiaries as “Unrestricted Subsidiaries” that are not subject to certain restrictions contained in the credit agreement. In connection with ~~a syndication~~the Viper Offering, the Company designated the Partnership, the General Partner and Viper Energy LLC as unrestricted subsidiaries under the credit agreement. As of ~~banks, including Wells Fargo as administrative agent sole book runner~~March 31, 2015, the loan is guaranteed by Diamondback, Diamondback E&P LLC and ~~lead arranger, provides for a revolving~~White Fang Energy LLC and will also be guaranteed by any future restricted subsidiaries of Diamondback. The credit ~~facility in~~agreement is also secured by substantially all of the assets of the Company, Diamondback O&G LLC and the guarantors.

The second amendment increased the maximum amount of the credit facility to $~~600.0 million~~2.0 billion, ~~subject~~modified the dates and deadlines of the credit agreement relating to the 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”). and added new provisions that allow the Company to elect a commitment amount that is less than its borrowing base as determined by the lenders. The borrowing base is scheduled to be re-determined semi-annually with effective dates of ~~April~~May 1st and ~~October~~November 1st. In addition, the Company may request up to three additional redeterminations of the borrowing base during any 12-month period. As of ~~September 30, 2014~~March 31, 2015, the borrowing base was set at $~~350.0~~750.0 million, of which the Company had elected a commitment amount of $500.0 million, and the Company had outstanding borrowings of ~~$140.0~~$161.6 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 (together, the “Credit Agreement”). The First Amendment modified certain provisions of the credit agreement to, among other things, allow the Company to designate one or more of its subsidiaries as “Unrestricted 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. As of September 30, 2014, the loan is guaranteed by Diamondback, Diamondback E&P LLC and White Fang Energy LLC and will also be

~~Table of Contents~~

~~Diamondback Energy, Inc. and Subsidiaries~~

~~Notes to Consolidated Financial Statements-(Continued)~~

~~(Unaudited)~~

~~guaranteed by any future restricted subsidiaries of Diamondback. The credit agreement is also secured by substantially all of the assets of the Company, Diamondback O&G LLC and the guarantors.~~

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.

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)



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 ~~September 30, 2014,~~March 31, 2015, the Company had $450.0 million of senior unsecured notes outstanding.

As of ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, 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, which was amended August 15, 2014 to add additional lenders to the lending group, 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 ~~September 30, 2014,~~March 31, 2015, the borrowing base was set at $110.0 million. The Partnership had no outstanding borrowings as of ~~September 30, 2014.~~March 31, 2015.

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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~~Diamondback Energy, Inc. and Subsidiaries~~

~~Notes to Consolidated Financial Statements-(Continued)~~

~~(Unaudited)~~



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 ended September 30, 2014 and ending with the quarter ending 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.

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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.

8.9. CAPITAL STOCK AND EARNINGS PER SHARE

As of ~~September 30, 2014,~~March 31, 2015, 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.~~January 1, 2014:

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.

OnIn 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 $485.0 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.

In January 2015, the Company completed an underwritten public offering of 1,750,000 shares of common stock, which included 262,500 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the underwriters at $59.34 per share and the Company received net proceeds of approximately $119.4 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.

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~~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 March 31, 2015
				Per
	Income		Shares	Share

	(in thousands, except per share amounts)
Basic:
Net income attributable to common stock	$	5,849	58,386	$	0.10
Effect of Dilutive Securities:
Dilutive effect of potential common shares issuable	$	—	240
Diluted:
Net income attributable to common stock	$	5,849	58,626	$	0.10

1513

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)


	Three Months Ended September 30,
	2014						2013					Three Months Ended March 31, 2014
					Per					Per					Per
	Income			Shares	Share		Income		Shares	Share		Income		Shares	Share

	(in thousands, except per share amounts)											(in thousands, except per share amounts)
Basic:
Net income attributable to common stock	$	43,739		55,152	$	0.79	$	14,596	44,385	$	0.33	$	23,589	48,447	$	0.49
Effect of Dilutive Securities:
Dilutive effect of potential common shares issuable	$	(53	)	290			—		313			$	—	420
Diluted:
Net income attributable to common stock	$	43,686		55,442	$	0.79	$	14,596	44,698	$	0.33	$	23,589	48,867	$	0.48

Nine Months Ended September 30,
2014 2013
Per Per
Income Shares Share Income Shares Share

(in thousands, except per share amounts)
Basic:
Net income attributable to common stock $ 95,081
51,489
$ 1.85
$ 34,463
40,309
$ 0.85
Effect of Dilutive Securities:
Dilutive effect of potential common shares issuable $ 16
399
—
215

Diluted:
Net income attributable to common stock $ 95,097
51,888
$ 1.83
$ 34,463
40,524
$ 0.85

9.10. STOCK AND UNIT BASED COMPENSATION

~~For~~The following table presents the ~~three months~~effects of the equity and ~~nine months endedSeptember 30, 2014, the Company incurred~~ ~~$4,112,000~~ ~~and~~ ~~$10,145,000, respectively, of~~ stock based compensation ~~of which the Company capitalized~~ ~~$2,043,000~~plans and ~~$4,758,000, respectively, pursuant to the full cost method of accounting for oil and natural gas properties. For the~~ ~~three months and nine months endedSeptember 30, 2013, the Company incurred~~ ~~$749,000~~ ~~and~~ ~~$2,105,000, respectively, of stock based compensation, of which the Company capitalized~~ ~~$259,000~~ ~~and~~ ~~$679,000, respectively, pursuant to the full cost method of accounting for oil and natural gas properties.~~related costs:



	2015		2014


General and administrative expenses	$	4,924	$	2,190
Stock based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	2,139		1,066
Related income tax benefit	770		384

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.

~~Table of Contents~~

~~Diamondback Energy, Inc. and Subsidiaries~~

~~Notes to Consolidated Financial Statements-(Continued)~~

~~(Unaudited)~~

Stock Options

The following table presents the Company’s stock option activity under the 2012 Plan for the ~~nine~~three months ended ~~September 30, 2014~~March 31, 2015.

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Weighted Average
Exercise Remaining Intrinsic
Options Price Term Value
(in years) (in thousands)
Outstanding at December 31, 2013 712,955
$ 17.96

Granted —
$ —

Exercised (293,450 ) $ 17.78

Expired/Forfeited —
$ —

Outstanding at September 30, 2014 419,505
$ 18.09
1.97 $ 23,783

Vested and Expected to vest at September 30, 2014 419,505
$ 18.09
1.97 $ 23,783
Exercisable at September 30, 2014 159,755
$ 17.50
1.47 $ 9,151



			Weighted Average
			Exercise		Remaining	Intrinsic
	Options		Price		Term	Value
					(in years)	(in thousands)
Outstanding at December 31, 2014	313,105		$	18.29
Granted	—		$	—
Exercised	(46,750	)	$	19.00
Expired/Forfeited	—		$	—
Outstanding at March 31, 2015	266,355		$	18.16	1.73	$	11,097

Vested and Expected to vest at March 31, 2015	266,355		$	18.16	1.73	$	11,097
Exercisable at March 31, 2015	34,855		$	17.84	1.62	$	1,474

The aggregate intrinsic value of stock options that were exercised during the ~~nine~~three months ended ~~September 30, 2014~~March 31, 2015 and 2014 was ~~$16,778,000.~~$2,129,000 and $5,310,000, respectively. As of ~~September 30, 2014~~March 31, 2015, the unrecognized compensation cost related to unvested stock options was $~~959,000~~453,000. Such cost is expected to be recognized over a weighted-average period of ~~1.2~~1.1 years.

Restricted Stock Units

The following table presents the Company’s restricted stock units activity under the 2012 Plan during the ~~nine~~three months ended ~~September 30, 2014~~March 31, 2015.


			Weighted Average				Weighted Average
	Restricted Stock		Grant-Date		Restricted Stock		Grant-Date
	Units		Fair Value		Units		Fair Value
Unvested at December 31, 2013	132,499		$	19.20
Unvested at December 31, 2014					167,291		$	49.99
Granted	148,722		$	66.93	90,252		$	68.46
Vested	(98,560	)	$	38.31	(63,136	)	$	56.43
Forfeited	(1,200	)	$	41.66	(821	)	$	74.97
Unvested at September 30, 2014	181,461		$	47.80
Unvested at March 31, 2015					193,586		$	49.82

The aggregate fair value of restricted stock units that vested during the ~~nine~~three months ended ~~September 30, 2014~~March 31, 2015 and 2014 was ~~$7,248,000.~~$4,074,000 and $2,003,000, respectively. As of ~~September 30, 2014~~March 31, 2015, the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $~~6,703,000~~7,987,000. Such cost is expected to be recognized over a weighted-average period of ~~1.6~~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~~In February 2015, eligible employees received additional performance restricted stock unit awards totaling 90,249 units ~~issued or outstanding during the nine months ended September 30, 2013.~~

~~Table~~from which a minimum of ~~Contents~~

~~Diamondback Energy, Inc.~~0% and ~~Subsidiaries~~

~~Notes~~a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2014 to ~~Consolidated Financial Statements-(Continued)~~December 31, 2016 and cliff vest at December 31, 2016.

~~(Unaudited)~~

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.~~assumptions for the February 2014 award.

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)



	2015
Grant-date fair value	$	125.63
Risk-free rate	0.30		%
Company volatility	39.60		%

The following table presents a summary of the grant-date fair values of performance restricted stock units granted and the related assumptions for the February 2015 award.


		2014				2015
Grant-date fair value	Grant-date fair value	$	125.63		Grant-date fair value	$	137.14
Risk-free rate	Risk-free rate	0.30		%	Risk-free rate	0.49		%
Company volatility	Company volatility	39.60		%	Company volatility	43.36		%

The following table presents the Company’s performance restricted stock units activity under the 2012 Plan for the ~~nine~~three months ended ~~September 30, 2014~~March 31, 2015.


		Performance	Weighted Average			Performance	Weighted Average
		Restricted Stock	Grant-Date			Restricted Stock	Grant-Date
		Units	Fair Value			Units	Fair Value
Unvested at December 31, 2013	Unvested at December 31, 2013	—	$	—	Unvested at December 31, 2013	79,150	$	125.63
Granted	Granted	79,150	$	125.63	Granted	90,249	$	137.14
Vested	Vested	—	$	—	Vested	—	$	—
Forfeited	Forfeited	—	$	—	Forfeited	—	$	—
Unvested at September 30, 2014 ⁽¹⁾		79,150	$	125.63
Unvested at December 31, 2014 ⁽¹⁾					Unvested at December 31, 2014 ⁽¹⁾	169,399	$	131.76

(1)	A maximum of 158,300 units could be awarded based upon the Company’s final TSR ranking.				A maximum of 338,798 units could be awarded based upon the Company’s final TSR ranking.

As of ~~September 30, 2014~~March 31, 2015, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was ~~$6,751,000.~~$15,459,000. Such cost is expected to be recognized over a weighted-average period of ~~1.3~~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.

1816

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)



	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		%

The following table presents the unit option activity under the Viper LTIP for the ~~nine~~three months ended ~~September 30, 2014.~~March 31, 2015.

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 September 30, 2014 2,500,000
$ 26.00
2.72
$ —

Vested and Expected to vest at September 30, 2014 2,500,000
$ 26.00
2.72
$ —
Exercisable at September 30, 2014 —
$ —
—
$ —



		Weighted Average
	Unit	Exercise		Remaining	Intrinsic
	Options	Price		Term	Value
				(in years)	(in thousands)
Outstanding at December 31, 2014	2,500,000	$	26.00
Granted	—	$	—
Outstanding at March 31, 2015	2,500,000	$	26.00	2.22	$	—

Vested and Expected to vest at March 31, 2015	2,500,000	$	26.00	2.22	$	—
Exercisable at March 31, 2015	—	$	—	—	$	—

As of ~~September 30, 2014,~~March 31, 2015, the unrecognized compensation cost related to unvested unit options was ~~$9,589,000.~~$7.8 million. Such cost is expected to be recognized over a weighted-average period of ~~2.7~~2.2 years.

Phantom Units

Under the Viper LTIP, the Board of Directors of the General Partner is authorized to issue phantom units to eligible employees. The Partnership estimates the fair value of phantom units as the closing price of the Partnership’s common units on the grant date of the award, which is expensed over the applicable vesting period. Upon vesting the phantom unit entitles the recipient one common unit of the Partnership for each phantom unit.

The following table presents the phantom unit activity under the Viper LTIP for the three months ended March 31, 2015.



		Weighted Average
	Phantom	Grant-Date
	Units	Fair Value
Unvested at December 31, 2014	17,776	$	19.51
Granted	—	$	—
Vested	—	$	—
Forfeited	—	$	—
Unvested at March 31, 2015	17,776	$	19.51

As of March 31, 2015, the unrecognized compensation cost related to unvested phantom units was $0.3 million. Such cost is expected to be recognized over a weighted-average period of 1.2 years.

~~10.~~11. RELATED PARTY TRANSACTIONS

Administrative Services

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

An entity under common management provided technical, administrative and payroll services to the Company under a shared services agreement ~~which~~that 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 continued on a month-to-month basis. Effective August 31, 2014, this agreement was mutually terminated. For the three months ended March 31, 2015 and ~~nine months endedSeptember 30,~~ 2014,, the Company incurred total costs of $~~3,000~~0 and ~~$6,000, respectively. For the~~ ~~three months and nine months ended~~ ~~September 30, 2013, the Company incurred total costs of $70,000 and $179,000,~~$1,000, 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~~The Company had ~~September 30, 2014~~no outstanding amounts payable at March 31, 2015 and December 31, ~~2013~~2014~~, 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 provided 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. Thereafter, the agreement continued on a month-to-month basis subject to the right of either party to terminate the agreement upon thirty days prior written notice. Effective August 31, 2014, this agreement was mutually terminated. Costs that are attributable to and billed to other affiliates are reported as other income-related party. For the three months ended March 31, 2015 and ~~nine months endedSeptember 30,~~ 2014,, the affiliate reimbursed the Company $~~31,000~~0 and ~~$91,000, respectively, and for the~~ ~~three months and nine months ended~~ ~~September 30, 2013, the affiliate reimbursed the Company $270,000 and $1,047,000,~~$30,000, respectively, for services under the shared services agreement. ~~As of~~The Company had no outstanding amounts payable at ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013~~2014~~, the affiliate owed the Company~~ no ~~amounts for either period.~~.

~~Table of Contents~~

~~Diamondback Energy, Inc. and Subsidiaries~~

~~Notes to Consolidated Financial Statements-(Continued)~~

~~(Unaudited)~~

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 ~~September 30, 2014~~March 31, 2015, the Company was not utilizing any Bison rigs. This master drilling agreement is terminable by either party on 30 days’ prior written notice, although neither party will be relieved of its respective obligations arising from a drilling contract being performed prior to the termination of the master drilling agreement. For the three months ended March 31, 2015 and ~~nine months endedSeptember 30,~~ 2014,, the Company incurred total costs for services performed by Bison of ~~$907,000~~$7,000 and ~~$3,402,000, respectively. For the~~ ~~three months and nine months ended~~ ~~September 30, 2013, the Company incurred total costs for services performed by Bison of $2,168,000 and $11,795,000,~~$1,510,000, respectively. The Company ~~owed Bison~~had no outstanding amounts payable to Bison as of ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013~~2014.

Effective September 9, 2013, the Company entered into a master service agreement with Panther Drilling Systems LLC (“Panther Drilling”), an entity controlled by Wexford, under which 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, however the amount~~services. The Company incurred no costs and $248,000 for services performed ~~by Panther Drilling during~~for the ~~nine~~three months ended ~~September 30, 2013 was not material. For the~~ ~~three months~~March 31, 2015 and ~~nine months endedSeptember 30,~~ 2014,~~, the Company incurred total costs for services performed by Panther Drilling of zero and $305,000,~~ respectively. The Company ~~owed~~had no outstanding amounts payable to Panther Drilling ~~no amounts~~ as of ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013~~2014.

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. An entity controlled by Wexford had owned an approximately 28% equity interest in Coronado Midstream until Coronado Midstream was sold in March 2015. Coronado Midstream is no longer a related party. The Company recognized revenues from Coronado Midstream of $~~6,764,000~~5,184,000 and ~~$17,176,000~~$3,907,000 for the three months ended March 31, 2015 and ~~nine months endedSeptember 30,~~ 2014,~~, respectively, and $1,877,000 and $4,694,000 for the~~ ~~three months and nine months ended~~ ~~September 30, 2013,~~ respectively. The Company recognized production and ad valorem taxes and gathering and transportation expenses from Coronado Midstream of ~~$1,070,000~~$1,122,000 and ~~$2,751,000~~$632,000 for the three~~three months~~

Diamondback Energy, Inc. and ~~nine~~ Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

months ended~~September 30,~~ March 31, 2015 and 2014,~~, respectively, and $325,000 and $791,000 for the~~ ~~three months and nine months ended~~ ~~September 30, 2013,~~ respectively. As of ~~September 30, 2014~~ ~~and~~ December 31, ~~2013~~2014, Coronado Midstream owed the Company $~~3,915,000~~3,986,000 ~~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 ~~purchased no~~did not purchase sand from Muskie ~~and incurred~~during either the three months ended March 31, 2015 or 2014. The Company had no ~~costs~~outstanding amounts payable to Muskie ~~for the~~ ~~three months and nine months endedSeptember 30, 2014, respectively. The Company incurred no costs and costs of $234,000 for sand purchased from Muskie for the~~ ~~three months and nine months ended~~ ~~September 30, 2013, respectively. The Company owed Muskie no amounts~~ as of ~~September 30, 2014~~March 31, 2015 or December 31, ~~2013~~2014.

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~~Diamondback Energy, Inc. and Subsidiaries~~

~~Notes to Consolidated Financial Statements-(Continued)~~

~~(Unaudited)~~

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 $~~97,000~~184,000 and ~~$288,000~~$93,000 for the three months ended March 31, 2015 and ~~nine months endedSeptember 30,~~ 2014,~~, respectively, and $49,000 and $131,000, for the~~ ~~three months and nine months ended~~ ~~September 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. In the second and fourth quarters of 2014, the Company amended this agreement to further increase the size of the leased premises. The monthly rent increased from $25,000 to $27,000 in the second quarter of 2014 and from $27,000 to $53,000 in the fourth quarter of 2014. The monthly rent will continue to increase approximately 4% annually on June 1 of each year during the remainder of the lease term. In November 2014, the Company further amended the lease, including extending the term of the lease for an additional ten-year period. In April 2015, the Company again amended this lease to increase the size of the leased premises. The monthly rent for the additional space is $23,000. Upon commencement of the extension in June 2016, the monthly base rent will increase to $94,000, with an increase of approximately 2% annually.

Field Office Lease

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 ~~$37,000 and $84,000~~$39,000 to the related party for the three months ~~and nine months~~ ended ~~September 30, 2014~~March 31, 2015. 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. During the third quarter of 2014, the Company negotiated a sublease with Bison, in which Bison will lease the field office space for the same term as the initial lease and will pay the monthly rent of $11,000 which will increase 3% annually on March 1 of each year during the remainder of the lease ~~term~~term.

Oklahoma City Lease

Effective January 1, 2012, the Company occupied corporate office space in Oklahoma City, Oklahoma under a lease with a 67 month term. The office space is owned by an entity controlled by an affiliate of Wexford. The Company paid $~~74,000~~0 and ~~$199,000~~$64,000 for the three months ended March 31, 2015 and ~~nine months endedSeptember 30,~~ 2014,~~, respectively, and $67,000 and $178,000 for the~~ ~~three months and nine months ended~~ ~~September 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 was also responsible for paying a portion of specified costs, fees and expenses associated with the operation of the premises. Effective September 23, 2014, this lease agreement was mutually terminated.

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

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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~~137,000 and ~~$375,000~~$125,000 for the three months ended March 31, 2015 and ~~nine months endedSeptember 30,~~ 2014,~~, respectively, and $125,000 and $375,000 for the~~ ~~three months and nine months ended~~ ~~September 30, 2013,~~ respectively, under the Advisory Services Agreement. As of ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013~~2014, the Company ~~owed Wexford~~had no outstanding amounts payable to Wexford 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

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~~Diamondback Energy, Inc. and Subsidiaries~~

~~Notes to Consolidated Financial Statements-(Continued)~~

~~(Unaudited)~~

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. For the three months ~~and nine months~~ ended ~~September 30, 2014~~March 31, 2015, the Partnership incurred costs of $~~143,000~~125,000 ~~and~~ ~~$143,000, respectively,~~ under the agreement. As of ~~September 30,~~March 31, 2015 and December 31, 2014, the Partnership ~~owed Wexford~~had no ~~amounts.~~

~~Secondary Offering Costs~~

On September 23, 2014, Gulfport Energy Corporation (“Gulfport”) and certain entities controlled by Wexford completed an underwritten secondary public offering of 2,500,000 shares of the Company’s common stock. The Company incurred estimated costs of approximately $100,000 relatedoutstanding amounts payable to ~~this secondary public offering.~~

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 costs of approximately $129,000 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.Wexford.

~~11.~~12. 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 combined 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.~~pricing, New York Mercantile Exchange West Texas Intermediate pricing or Inter–Continental Exchange (“ICE”) pricing for Brent crude oil.

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.

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

As of ~~September 30, 2014~~March 31, 2015, the Company had open crude oil derivative positions with respect to future production as set forth in the table 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

Volume (Bbls)

Fixed Swap Price

October - December 2014

644,000

98.64

January - April 2015

331,000

99.71

April- December 2015

855,000

91.31

Crude Oil—NYMEX West Texas Intermediate Fixed Price Swap

Production Period

Volume (Bbls)

Fixed Swap Price

April - December 2015

1,375,000

84.10

Crude Oil—ICE Brent Fixed Price Swap

Production Period

Volume (Bbls)

Fixed Swap Price

April - December 2015

550,000

88.78

January - February 2016

91,000

88.72

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.

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 ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013~~2014.


	September 30, 2014							March 31, 2015

	(in thousands)							(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		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	$	6,061	$	—		$	6,061	$	92,335	$	—	$	92,335

	December 31, 2013							December 31, 2014

	(in thousands)							(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		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	$	117,541	$	—	$	117,541

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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:


	September 30,		December 31,		March 31,		December 31,
	2014		2013		2015		2014

	(in thousands)				(in thousands)
Current Assets: Derivative instruments	$	6,061	$	213	$	92,335	$	115,607
Noncurrent Assets: Derivative instruments	—		218		—		1,934
Total Assets	$	6,061	$	431	$	92,335	$	117,541

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~~Diamondback Energy, Inc. and Subsidiaries~~

~~Notes to Consolidated Financial Statements-(Continued)~~

~~(Unaudited)~~

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

Three Months Ended September 30, Nine Months Ended September 30,
2014 2013 2014 2013

(in thousands)
Non-cash gain (loss) on open non-hedge derivative instruments $ 16,440
$ (1,695 ) $ 5,630
$ 3,733
Loss on settlement of non-hedge derivative instruments (1,531 ) (3,215 ) (6,207 ) (5,614 )
Gain (loss) on derivative instruments $ 14,909
$ (4,910 ) $ (577 ) $ (1,881 )



	March 31,			December 31,
	2015			2014


Change in fair value of open non-hedge derivative instruments	$	(25,206	)	$	(3,342	)
Gain (loss) on settlement of non-hedge derivative instruments	43,560			(1,056		)
Gain (loss) on derivative instruments	$	18,354		$	(4,398	)

~~12.~~13. 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.

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~~Diamondback Energy, Inc. and Subsidiaries~~

~~Notes to Consolidated Financial Statements-(Continued)~~

~~(Unaudited)~~

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013~~2014.

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)


			Fair value measurements at September 30, 2014 using:										Fair value measurements at March 31, 2015 using:

		(in thousands)										(in thousands)
			Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3		Total				Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3		Total
Assets:	Assets:										Assets:
Fixed price swaps	Fixed price swaps		$	—	$	6,061	$	—	$	6,061	Fixed price swaps		$	—	$	92,335	$	—	$	92,335

			Fair value measurements at December 31, 2013 using:										Fair value measurements at December 31, 2014 using:

		(in thousands)										(in thousands)
			Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3		Total				Quoted Prices in Active Markets Level 1		Significant Other Observable Inputs Level 2		Significant Unobservable Inputs Level 3		Total
Assets:	Assets:										Assets:
Fixed price swaps	Fixed price swaps		$	—	$	431	$	—	$	431	Fixed price swaps		$	—	$	117.541	$	—	$	117.541

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.~~balance sheets.


	September 30, 2014				December 31, 2013				March 31, 2015				December 31, 2014
	Carrying				Carrying				Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value		Amount		Fair Value		Amount		Fair Value

	(in thousands)								(in thousands)
Debt:
Revolving credit facility	$	140,000	$	140,000	$	10,000	$	10,000	$	161,579	$	161,579	$	223,500	$	10,000
7.625% Senior Notes due 2021	450,000		486,000		450,000		460,406		450,000		477,563		450,000		440,438
Partnership revolving credit facility	—		—		—		—		—		—		—		—

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 ~~September 30, 2014~~March 31, 2015 quoted market price, a Level 1 classification in the fair value hierarchy. The fair value of the Partnership’s revolving credit facility approximates its carrying value based on borrowing rates available to us for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The Partnership had no outstanding borrowings as of ~~September 30, 2014.~~March 31, 2015.

14. COMMITMENTS AND CONTINGENCIES

Lease Commitments

The following is a schedule of minimum future lease payments with commitments that have initial or remaining noncancelable lease terms in excess of one year as of March 31, 2015:

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

~~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.



Year Ending December 31,	Drilling Rig Commitments	Office and Equipment Leases

2016	27,317	$	1,583
2017	19,892	1,734
2018	13,031	1,649
2019	—	1,509
2020	—	1,324
Thereafter	—	7,641
Total	60,240	$	15,440

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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~~Diamondback Energy, Inc. and Subsidiaries~~

~~Notes to Consolidated Financial Statements-(Continued)~~

~~(Unaudited)~~

~~14.~~15. SUBSEQUENT EVENTS

~~Subsequent to September 30, 2014, the Company entered into new commodity contracts. The contracts are fixed price oil swaps that will settle against the weighted average price per barrel of~~ ~~Argus Louisiana light sweet or NYMEX West Texas Intermediate during the calculation period. The following table presents the terms of the contracts:~~

Fixed Swap
Volumes (Bbls) Price Production Period
Crude Oil—Argus Louisiana Light Sweet Fixed Price Swap 183,000
$ 82.95
November 2014 - December 2014
Crude Oil—Argus Louisiana Light Sweet Fixed Price Swap 1,095,000
$ 90.99
January 2015 - December 2015
Crude Oil—NYMEX West Texas Intermediate Fixed Price Swap 1,825,000
$ 84.10
January 2015 - December 2015
Crude Oil—ICE Brent Fixed Price Swap

640,000
$ 88.78
February 2015 - January 2016
Crude Oil—ICE Brent Fixed Price Swap
91,000
$ 88.72
January 2016 - February 2016

~~The Company’s lead lender under its revolving credit agreement recently approved an increase in the Company’s borrowing base to $750.0 million, however~~Since January 1, 2015, the Company has ~~elected~~acquired or has entered into definitive purchase agreements to ~~limit~~acquire from unrelated third party sellers an aggregate of approximately 15,940 gross (11,948 net) acres in the ~~lenders’~~Midland Basin, primarily in northwest Howard County, in the Permian Basin, for an aggregate ~~commitment~~purchase price of approximately $437.8 million, subject to ~~$500.0~~certain adjustments. The Company has offered an average approximate 1.5% overriding royalty interest in certain of the acreage subject to these acquisitions to the Partnership for $33.7 million. This offer is subject to the approval of the conflicts committee of the Partnership’s general partner and the Company’s completion of the acquisitions, and there can be no assurance that this transaction will be completed on these terms or at all. The Company intends to finance the acquisitions, subject to market conditions and other factors, primarily with proceeds from one or more capital market transactions, which may include debt or equity offerings. The Company anticipates that all of these acquisitions will be completed by the end of June 2015. However, substantially all of the transactions remain subject to completion of due diligence and satisfaction of other closing conditions. There can be no assurance that the Company will acquire all or any portion of the acreage described above.

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~~Diamondback Energy, Inc. and Subsidiaries~~

~~Notes to Consolidated Financial Statements-(Continued)~~

~~(Unaudited)~~

~~15.~~16. GUARANTOR FINANCIAL STATEMENTS

Diamondback E&P, Diamondback O&G and White Fang Energy LLC (the “Guarantor Subsidiaries”) are guarantors under the Indenture relating to the Senior Notes. 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 (the “Non-Guarantor Subsidiaries”) as unrestricted

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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 combined consolidated financial information for the Company (“Parent”), the Guarantor Subsidiaries, the Non–Guarantor Subsidiaries and on a 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
September 30, 2014
March 31, 2015															March 31, 2015
(In thousands)
						Non–															Non–
			Guarantor			Guarantor												Guarantor			Guarantor
	Parent		Subsidiaries			Subsidiaries			Eliminations			Consolidated				Parent		Subsidiaries			Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	6,518	$	20,622		$	13,504		$	—		$	40,644			$	54	$	21,768		$	9,821		$	—		$	31,643
Restricted cash																—		—			500			—			500
Accounts receivable	—		76,346			9,965			2			86,313				—		76,124			7,084			2			83,210
Accounts receivable - related party	—		3,915			—			—			3,915
Intercompany receivable	1,634,314		1,716,401			—			(3,350,715		)	—				1,798,170		2,466,740			—			(4,264,910		)	—
Inventories	—		3,105			—			—			3,105				—		2,847			—			—			2,847
Other current assets	336		8,381			567			—			9,284				337		96,343			492			—			97,172
Total current assets	1,641,168		1,828,770			24,036			(3,350,713		)	143,261				1,798,561		2,663,822			17,897			(4,264,908		)	215,372
Property and equipment
Oil and natural gas properties, at cost, based on the full cost method of accounting	—		2,389,296			510,997			—			2,900,293				—		2,700,982			510,999			—			3,211,981
Pipeline and gas gathering assets	—		7,102			—			—			7,102				—		7,174			—			—			7,174
Other property and equipment	—		47,286			—			—			47,286				—		48,338			—			—			48,338
Accumulated depletion, depreciation, amortization and impairment	—		(306,187		)	(24,801		)	2,466			(328,522		)		—		(401,507		)	(41,700		)	1,386			(441,821		)
	—		2,137,497			486,196			2,466			2,626,159				—		2,354,987			469,299			1,386			2,825,672
Investment in subsidiaries	693,594		—			—			(693,594		)	—				844,250		—			—			(844,250		)	—
Other assets	9,395		6,664			35,076			—			51,135				8,833		7,654			34,950			—			51,437
Total assets	$	2,344,157	$	3,972,931		$	545,308		$	(4,041,841	)	$	2,820,555			$	2,651,644	$	5,026,463		$	522,146		$	(5,107,772	)	$	3,092,481
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	—	$	8,009		$	—		$	—		$	8,009			$	1	$	8,794		$	6		$	—		$	8,801
Intercompany payable	83,318		3,267,397			—			(3,350,715		)	—				96,230		4,168,678			—			(4,264,908		)	—
Other current liabilities	19,003		167,485			1,789			—			188,277				50,801		123,733			695			—			175,229
Total current liabilities	102,321		3,442,891			1,789			(3,350,715		)	196,286				147,032		4,301,205			701			(4,264,908		)	184,030
Long-term debt	450,000		140,000			—			—			590,000				450,000		161,579			—			—			611,579
Asset retirement obligations	—		8,115			—			—			8,115				—		8,844			—			—			8,844
Deferred income taxes	140,308		—			—			—			140,308				171,511		—			—			—			171,511
Total liabilities	692,629		3,591,006			1,789			(3,350,715		)	934,709				768,543		4,471,628			701			(4,264,908		)	975,964
Commitments and contingencies
Stockholders’ equity:	1,651,528		381,925			543,519			(925,444		)	1,651,528				1,883,101		554,835			521,445			(1,076,280		)	1,883,101
Noncontrolling interest	—		—			—			234,318			234,318				—		—			—			233,416			233,416
Total equity	1,651,528		381,925			543,519			(691,126		)	1,885,846				1,883,101		554,835			521,445			(842,864		)	2,116,517
Total liabilities and equity	$	2,344,157	$	3,972,931		$	545,308		$	(4,041,841	)	$	2,820,555			$	2,651,644	$	5,026,463		$	522,146		$	(5,107,772	)	$	3,092,481

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Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

																														Condensed Consolidated Balance Sheet
December 31, 2013
December 31, 2014															December 31, 2014
(In thousands)
						Non–															Non–
			Guarantor			Guarantor												Guarantor			Guarantor
	Parent		Subsidiaries			Subsidiaries			Eliminations			Consolidated				Parent		Subsidiaries			Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	526	$	14,267		$	762		$	—		$	15,555			$	6	$	15,067		$	15,110		$	—		$	30,183
Restricted cash																—		—			500			—			500
Accounts receivable	—		28,544			—			9,426			37,970				—		85,752			8,239			2			93,993
Accounts receivable - related party	—		1,303			—			—			1,303				—		4,001			—			—			4,001
Royalty income receivable	—		—			9,426			(9,426		)	—
Intercompany receivable	715,169		413,744			—			(1,128,913		)	—				1,658,215		2,167,434			—			(3,825,649		)	—
Intercompany note receivable	440,000		—			—			(440,000		)	—
Inventories	—		5,631			—			—			5,631				—		2,827			—			—			2,827
Deferred income taxes	112		—			—			—			112
Other current assets	—		1,397			—			—			1,397				562		119,392			253			—			120,207
Total current assets	1,155,807		464,886			10,188			(1,568,913		)	61,968				1,658,783		2,394,473			24,102			(3,825,647		)	251,711
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				—		2,607,513			511,084			—			3,118,597
Pipeline and gas gathering assets	—		6,142			—			—			6,142				—		7,174			—			—			7,174
Other property and equipment	—		4,071			—			—			4,071				—		48,180			—			—			48,180
Accumulated depletion, depreciation, amortization and impairment	—		(207,037		)	(5,199		)	—			(212,236		)		—		(351,200		)	(32,799		)	1,855			(382,144		)
	—		1,003,502			442,835			—			1,446,337				—		2,311,667			478,285			1,855			2,791,807
Investment in subsidiaries	235,334		—			—			(235,334		)	—				839,217		—			—			(839,217		)	—
Other assets	10,207		3,102			—			—			13,309				9,155		7,793			35,015			—			51,963
Total assets	$	1,401,348	$	1,471,490		$	453,023		$	(1,804,247	)	$	1,521,614			$	2,507,155	$	4,713,933		$	537,402		$	(4,663,009	)	$	3,095,481
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	—	$	2,679		$	—		$	—		$	2,679			$	—	$	26,224		$	6		$	—		$	26,230
Accounts payable-related party	—		17			—			—			17
Intercompany payable	3,920		1,115,214			87			(1,119,221		)	—				95,362		3,730,287			—			(3,825,649		)	—
Intercompany accrued interest	—		—			9,692			(9,692		)	—
Other current liabilities	10,123		108,245			256			—			118,624				49,190		189,264			2,045			—			240,499
Total current liabilities	14,043		1,226,155			10,035			(1,128,913		)	121,320				144,552		3,945,775			2,051			(3,825,649		)	266,729
Long-term debt	450,000		10,000			—			—			460,000				450,000		223,500			—			—			673,500
Intercompany note payable	—		—			440,000			(440,000		)	—
Asset retirement obligations	—		2,989			—			—			2,989				—		8,447			—			—			8,447
Deferred income taxes	91,764		—			—			—			91,764				161,592		—			—			—			161,592
Total liabilities	555,807		1,239,144			450,035			(1,568,913		)	676,073				756,144		4,177,722			2,051			(3,825,649		)	1,110,268
Commitments and contingencies
Stockholders’ equity:	845,541		232,346			2,988			(235,334		)	845,541				1,751,011		536,211			535,351			(1,071,562		)	1,751,011
Noncontrolling interest																—		—			—			234,202			234,202
Total equity	845,541		232,346			2,988			(235,334		)	845,541				1,751,011		536,211			535,351			(837,360		)	1,985,213
Total liabilities and equity	$	1,401,348	$	1,471,490		$	453,023		$	(1,804,247	)	$	1,521,614			$	2,507,155	$	4,713,933		$	537,402		$	(4,663,009	)	$	3,095,481

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Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

																																Condensed Consolidated Statement of Operations
Three Months Ended September 30, 2014
Three Months Ended March 31, 2015																Three Months Ended March 31, 2015
(In thousands)
							Non–																Non–
				Guarantor			Guarantor													Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated				Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues:
Oil sales	$	—		$	105,202		$	—		$	21,204		$	126,406			$	—		$	77,384		$	—		$	15,532		$	92,916
Natural gas sales	—			3,824			—			888			4,712				—			3,779			—			569			4,348
Natural gas liquid sales	—			6,880			—			1,129			8,009				—			3,693			—			444			4,137
Royalty income	—			—			22,767			(22,767		)	—				—			—			16,545			(16,545		)	—
Total revenues	—			115,906			22,767			454			139,127				—			84,856			16,545			—			101,401
Costs and expenses:
Lease operating expenses	—			13,805			—			—			13,805				—			22,456			—			—			22,456
Production and ad valorem taxes	—			7,475			1,460			19			8,954				—			7,067			1,328			—			8,395
Gathering and transportation	—			866			—			(6		)	860				—			1,030			—			—			1,030
Depreciation, depletion and amortization	—			38,028			9,025			(1,683		)	45,370				—			50,307			8,901			469			59,677
General and administrative expenses	4,063			1,039			2,143			(750		)	6,495				4,518			2,166			1,552			—			8,236
Asset retirement obligation accretion expense	—			127			—			—			127				—			170			—			—			170
Total costs and expenses	4,063			61,340			12,628			(2,420		)	75,611				4,518			83,196			11,781			469			99,964
Income (loss) from operations	(4,063		)	54,566			10,139			2,874			63,516				(4,518		)	1,660			4,764			(469		)	1,437
Other income (expense)
Interest income - intercompany																	—			—			—			—			—
Interest expense	(8,821		)	(708		)	(317		)	—			(9,846		)		(8,910		)	(1,419		)	(168		)	—			(10,497		)
Interest expense - intercompany																	—			—			—			—			—
Other income	6			31			11			—			48				—			29			486			—			515
Other income - intercompany	—			750			—			(750		)	—
Other expense	—			(8		)	—			—			(8		)
Other expense - intercompany	—			—			(750		)	750			—
Gain (loss) on derivative instruments, net	—			14,909			—			—			14,909
Gain on derivative instruments, net																	—			18,354			—			—			18,354
Total other income (expense), net	(8,815		)	14,974			(1,056		)	—			5,103				(8,910		)	16,964			318			—			8,372
Income (loss) before income taxes	(12,878		)	69,540			9,083			2,874			68,619				(13,428		)	18,624			5,082			(469		)	9,809
Provision for income taxes	23,978			—			—			—			23,978				3,370			—			—			—			3,370
Net income (loss)	(36,856		)	69,540			9,083			2,874			44,641				(16,798		)	18,624			5,082			(469		)	6,439
Less: Net income attributable to noncontrolling interest	—			—			—			902			902				—			—			—			590			590
Net income (loss) attributable to Diamondback Energy, Inc.	$	(36,856	)	$	69,540		$	9,083		$	1,972		$	43,739			$	(16,798	)	$	18,624		$	5,082		$	(1,059	)	$	5,849

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Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

																																Condensed Consolidated Statement of Operations
Three Months Ended September 30, 2013
Three Months Ended March 31, 2014																Three Months Ended March 31, 2014
(In thousands)
							Non–																Non–
				Guarantor			Guarantor													Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated				Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues:
Oil sales	$	—		$	51,745		$	—		$	1,341		$	53,086			$	—		$	74,796		$	—		$	14,962		$	89,758
Natural gas sales	—			1,527			—			36			1,563				—			2,757			—			578			3,335
Natural gas liquid sales	—			3,080			—			62			3,142				—			4,144			—			767			4,911
Royalty income	—			—			1,439			(1,439		)	—				—			—			15,853			(15,853		)	—
Total revenues	—			56,352			1,439			—			57,791				—			81,697			15,853			454			98,004
Costs and expenses:
Lease operating expenses	—			4,964			—			—			4,964				—			7,915			—			—			7,915
Production and ad valorem taxes	—			3,460			93			—			3,553				—			4,903			921			18			5,842
Gathering and transportation	—			260			1			—			261				—			588			—			(6		)	582
Depreciation, depletion and amortization	—			16,944			445			34			17,423				—			25,801			5,567			(395		)	30,973
General and administrative expenses	703			1,418			9			(9		)	2,121				3,985			506			144			(78		)	4,557
Asset retirement obligation accretion expense	—			46			—			—			46				—			72			—			—			72
Intercompany charges																	—			—			—			—			—
Total costs and expenses	703			27,092			548			25			28,368				3,985			39,785			6,632			(461		)	49,941
Income (loss) from operations	(703		)	29,260			891			(25		)	29,423				(3,985		)	41,912			9,221			915			48,063
Other income (expense)
Interest income	1			—			—			—			1				—			—			—			—			—
Interest income - intercompany																	5,368			—			—			(5,368		)	—
Interest expense	(68		)	(399		)	(622		)	—			(1,089		)		(5,887		)	(618		)	—			—			(6,505		)
Interest expense - intercompany																	—			—			(5,368		)	5,368			—
Other income	—			270			—			—			270				—			—			—			—			—
Gain on derivative instruments, net	—			(4,910		)	—			—			(4,910		)
Other income (expense)- intercompany																	—			108			—			(78		)	30
Loss on derivative instruments, net																	—			(4,398		)				—			(4,398		)
Total other income (expense), net	(67		)	(5,039		)	(622		)	—			(5,728		)		(519		)	(4,908		)	(5,368		)	(78		)	(10,873		)
Income (loss) before income taxes	(770		)	24,221			269			(25		)	23,695				(4,504		)	37,004			3,853			837			37,190
Provision for income taxes	9,099			—			—			—			9,099				13,601			—			—			—			13,601
Net income (loss)	$	(9,869	)	$	24,221		$	269		$	(25	)	$	14,596			$	(18,105	)	$	37,004		$	3,853		$	837		$	23,589

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Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Condensed Consolidated Statement of Operations
Nine Months Ended September 30, 2014
(In thousands)
Non–
Guarantor Guarantor
Parent Subsidiaries Subsidiaries Eliminations Consolidated
Revenues:
Oil sales $ —
$ 280,024
$ —
$ 51,422
$ 331,446
Natural gas sales —
10,394
—
1,982
12,376
Natural gas liquid sales —
17,394
—
2,919
20,313
Royalty income —
—
55,869
(55,869 ) —
Total revenues —
307,812
55,869
454
364,135
Costs and expenses:
Lease operating expenses —
32,216
—
—
32,216
Production and ad valorem taxes —
19,540
3,791
19
23,350
Gathering and transportation —
2,151
—
(6 ) 2,145
Depreciation, depletion and amortization —
98,445
19,602
(1,683 ) 116,364
General and administrative expenses 11,476
1,832
2,584
(906 ) 14,986
Asset retirement obligation accretion expense —
303
—
—
303
Total costs and expenses 11,476
154,487
25,977
(2,576 ) 189,364
Income (loss) from operations (11,476 ) 153,325
29,892
3,030
174,771
Other income (expense)
Interest income - intercompany 10,755
—
—
(10,755 ) —
Interest expense (21,365 ) (2,408 ) (317 ) —
(24,090 )
Interest expense - intercompany —
—
(10,755 ) 10,755
—
Other income 6
91
11
—
108
Other income - intercompany —
906
—
(906 ) —
Other expense —
(1,416 ) —
—
(1,416 )
Other expense - intercompany —
—
(906 ) 906
—
Gain (loss) on derivative instruments, net —
(577 ) —
—
(577 )
Total other income (expense), net (10,604 ) (3,404 ) (11,967 ) —
(25,975 )
Income (loss) before income taxes (22,080 ) 149,921
17,925
3,030
148,796
Provision for income taxes 52,742
—
—
—
52,742
Net income (loss) (74,822 ) 149,921
17,925
3,030
96,054
Less: Net income attributable to noncontrolling interest —
—
—
973
973
Net income (loss) attributable to Diamondback Energy, Inc. $ (74,822 ) $ 149,921
$ 17,925
$ 2,057
$ 95,081



Condensed Consolidated Statement of Cash Flows
Three Months Ended March 31, 2015
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Net cash provided (used in) by operating activities	$	(1,970	)	$	86,560		$	14,553		$	—		$	99,143

Cash flows from investing activities:
Additions to oil and natural gas properties	—			(150,963		)	85			—			(150,878		)
Acquisition of leasehold interests	—			(2,519		)	—			—			(2,519		)
Purchase of other property and equipment	—			(158		)	—			—			(158		)
Intercompany transfers	(16,280		)	16,280			—			—			—
Other investing activities	—			—			—			—			—
Net cash provided by (used in) investing activities	(16,280		)	(137,360		)	85			—			(153,555		)
Cash flows from financing activities:
Proceeds from borrowing on credit facility	—			57,501			—			—			57,501
Repayment on credit facility	—			(119,422		)	—			—			(119,422		)
Proceeds from public offerings	119,422			—			—			—			119,422
Distribution from subsidiary	17,612			—			—			(17,612		)	—
Distribution to non-controlling interest	—			—			(19,927		)	17,612			(2,315		)
Intercompany transfers	(119,422		)	119,422			—			—			—
Other financing activities	686			—			—			—			686
Net cash provided by (used in) financing activities	18,298			57,501			(19,927		)	—			55,872

Net increase (decrease) in cash and cash equivalents	48			6,701			(5,289		)	—			1,460
Cash and cash equivalents at beginning of period	6			15,067			15,110			—			30,183
Cash and cash equivalents at end of period	$	54		$	21,768		$	9,821		$	—		$	31,643

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Condensed Consolidated Statement of Operations
Nine Months Ended September 30, 2013
(In thousands)
Non–
Guarantor Guarantor
Parent Subsidiaries Subsidiaries Eliminations Consolidated
Revenues:
Oil sales $ —
$ 118,032
$ —
$ 1,341
$ 119,373
Natural gas sales —
4,346
—
36
4,382
Natural gas liquid sales —
8,277
—
62
8,339
Royalty income —
—
1,439
(1,439 ) —
Total revenues —
130,655
1,439
—
132,094
Costs and expenses:
Lease operating expenses —
15,367
—
—
15,367
Production and ad valorem taxes —
8,202
93
—
8,295
Gathering and transportation —
640
1
—
641
Depreciation, depletion and amortization —
42,497
445
34
42,976
General and administrative expenses 2,399
4,814
9
(9 ) 7,213
Asset retirement obligation accretion expense —
134
—
—
134
Total costs and expenses 2,399
71,654
548
25
74,626
Income (loss) from operations (2,399 ) 59,001
891
(25 ) 57,468
Other income (expense)
Interest income 1
—
—
—
1
Interest expense (68 ) (1,419 ) (622 ) —
(2,109 )
Other income —
1,047
—
—
1,047
Gain on derivative instruments, net —
(1,881 ) —
—
(1,881 )
Total other income (expense), net (67 ) (2,253 ) (622 ) —
(2,942 )
Income (loss) before income taxes (2,466 ) 56,748
269
(25 ) 54,526
Provision for income taxes 20,063
—
—
—
20,063
Net income (loss) $ (22,529 ) $ 56,748
$ 269
$ (25 ) $ 34,463

~~Table of Contents~~

~~Diamondback Energy, Inc. and Subsidiaries~~

~~Notes to Consolidated Financial Statements-(Continued)~~

~~(Unaudited)~~

																															Condensed Consolidated Statement of Cash Flows
Nine Months Ended September 30, 2014
Three Months Ended March 31, 2014															Three Months Ended March 31, 2014
(In thousands)
							Non–															Non–
				Guarantor			Guarantor												Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations		Consolidated				Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Net cash provided by operating activities	$	1,915		$	220,447		$	29,633		$	—	$	251,995			$	3,323		$	67,588		$	6,543		$	(5,988	)	$	71,466

Cash flows from investing activities:
Additions to oil and natural gas properties	—			(307,144		)	(5,275		)	—		(312,419		)		—			(78,983		)	(6,878		)	—			(85,861		)
Acquisition of leasehold interests	—			(840,482		)	—			—		(840,482		)		—			(312,207		)	—			—			(312,207		)
Acquisition of mineral interests	—			—			(57,688		)	—		(57,688		)		—			—			—			—			—
Purchase of other property and equipment	—			(43,215		)	—			—		(43,215		)		—			(595		)	—			—			(595		)
Cost method investment	—			—			(33,851		)	—		(33,851		)
Intercompany transfers	(631,100		)	631,100			—			—		—				(204,544		)	197,619			—			6,925			—
Other investing activities	—			(1,426		)	—			—		(1,426		)		—			(521		)	—			—			(521		)
Net cash used in investing activities	(631,100		)	(561,167		)	(96,814		)	—		(1,289,081		)		(204,544		)	(194,687		)	(6,878		)	6,925			(399,184		)
Cash flows from financing activities:
Proceeds from borrowing on credit facility	—			347,900			78,000			—		425,900				—			127,000			—			—			127,000
Repayment on credit facility	—			(217,900		)	(78,000		)	—		(295,900		)
Proceeds from public offerings	693,886			—			234,546			—		928,432				208,644			—			—			—			208,644
Distribution to parent	—			—			(148,760		)	—		(148,760		)
Distribution from subsidiary	148,760			—			—			—		148,760
Intercompany transfers	(217,900		)	217,900			—			—		—
Other financing activities	10,431			(825		)	(5,863		)	—		3,743				1,967			(9		)	(28		)	(97		)	1,833
Net cash provided by (used in) financing activities	635,177			347,075			79,923			—		1,062,175				210,611			126,991			(28		)	(97		)	337,477

Net increase in cash and cash equivalents	5,992			6,355			12,742			—		25,089
Net increase (decrease) in cash and cash equivalents																9,390			(108		)	(363		)	840			9,759
Cash and cash equivalents at beginning of period	526			14,267			762			—		15,555				526			14,267			762			—			15,555
Cash and cash equivalents at end of period	$	6,518		$	20,622		$	13,504		$	—	$	40,644			$	9,916		$	14,159		$	399		$	840		$	25,314

3531

~~Table of Contents~~

~~Diamondback Energy, Inc. and Subsidiaries~~

~~Notes to Consolidated Financial Statements-(Continued)~~

~~(Unaudited)~~

Condensed Consolidated Statement of Cash Flows
Nine Months Ended September 30, 2013
(In thousands)
Non–
Guarantor Guarantor
Parent Subsidiaries Subsidiaries Eliminations Consolidated
Net cash provided by operating activities $ (182 ) $ 91,243
$ 586
$ —
$ 91,647

Cash flows from investing activities:
Additions to oil and natural gas properties —
(199,209 ) (586 ) —
(199,795 )
Acquisition of leasehold interests —
(185,185 ) —
—
(185,185 )
Acquisition of mineral interests —
—
(440,000 ) —
(440,000 )
Purchase of other property and equipment —
(4,965 ) —
—
(4,965 )
Intercompany transfers (245,680 ) 245,680
—
—
—
Other investing activities —
(227 ) —
—
(227 )
Net cash used in investing activities (245,680 ) (143,906 ) (440,586 ) —
(830,172 )
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 senior notes 10,000
—
440,000
—
450,000
Proceeds from public offerings 322,680
—
—
—
322,680
Distribution to parent —
—
—
—
—
Intercompany transfers (49,000 ) 49,000
—
—
—
Other financing activities (7,267 ) (146 ) —
—
(7,413 )
Net cash provided by (used in) financing activities 276,413
48,854
440,000
—
765,267

Net increase in cash and cash equivalents 30,551
(3,809 ) —
—
26,742
Cash and cash equivalents at beginning of period 14
26,344
—
—
26,358
Cash and cash equivalents at end of period $ 30,565
$ 22,535
$ —
$ —
$ 53,100

~~Table of Contents~~

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

The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10–Q as well as our audited combined consolidated financial statements and notes thereto included in our Annual Report on Form ~~10–K~~10-K for the year ended December 31, ~~2013.~~2014. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See “Part ~~II,~~II. Item 1A. Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Overview

We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. Our activities are primarily directed at the Clearfork, Spraberry, Wolfcamp, Cline, Strawn and Atoka formations which we refer to as the Wolfberry play. We intend to grow our reserves and production through development drilling, exploitation and exploration activities on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves. Substantially all of our revenues are generated through the sale of oil, natural gas liquids and natural gas production. Our production was approximately ~~75%~~77% oil, ~~14% natural gas liquids and 11% natural gas for the three months ended~~ ~~September 30, 2014, and the three months ended~~ ~~September 30, 2013. Our production was approximately 76% oil, 14%~~13% natural gas liquids and 10% natural gas for the ~~nine~~three months ended ~~September 30, 2014,~~March 31, 2015, and was approximately ~~74%~~79% oil, ~~14%~~11% natural gas liquids and ~~12%~~10% natural gas for the ~~nine~~three months ended ~~September 30, 2013.~~March 31, 2014. On ~~September 30, 2014~~March 31, 2015, our net acreage position in the Permian Basin was approximately ~~84,746~~77,866 net acres. ~~See Note 1 to our unaudited consolidated financial statements included elsewhere in this Quarterly Report for additional information regarding the organization and description of our business.~~

Recent Developments

~~Viper Energy Partners LP~~

Viper Energy Partners LP, or 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 us 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 Partnership’s initial public offering, or the Viper Offering, we owned all of the general and limited partner interests in the Partnership. The Viper Offering consisted of 5,750,000 common units representing limited partner interests 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, we 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 $11.6 million and the net proceeds from the Viper Offering. As of September 30, 2014, the Partnership had distributed $148.8 million to Diamondback. 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.

~~Acquisitions~~

On February 27 and 28, 2014, we completed acquisitions of oil and natural gas interests from unrelated third party sellers of additional leasehold interests in Martin County, Texas, in the Permian Basin, for an aggregate purchase price of approximately $292.2 million, subject to certain adjustments. These transactions included 6,450 gross (4,785 net) acres with a 74% working interest (56% net revenue interest). We funded these acquisitions with the net proceeds from an underwritten public offering of our common stock completed on February 26, 2014 and borrowings under our revolving credit facility. Upon completion of these acquisitions, we became the operator of this acquired acreage.

~~Table of Contents~~

On September 9, 2014, we completed the acquisition of oil and natural gas interests from unrelated third party sellers of additional leasehold interests in Midland, Glasscock, Reagan and Upton Counties, Texas in the Permian Basin, for an aggregate purchase price of approximately $523.3 million, subject to certain adjustments. This transaction included 17,617 gross (12,967 net) acres with an approximate 74% working interest (approximately 75% net revenue interest). We funded this acquisition with the net proceeds from an underwritten public offering of our common stock completed on July 25, 2014 and borrowings under our revolving credit facility. Upon completion of these acquisitions, we became the operator of this acquired acreage.

Common stock transactions

In ~~February 2014,~~January 2015, we completed an underwritten public offering of ~~3,450,000~~1,750,000 shares of common stock, which included ~~450,000~~262,500 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the ~~public~~underwriters at ~~$62.67~~$59.34 per share and we received net proceeds of approximately ~~$208.4~~$119.4 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions.

~~On July 25, 2014,~~Recent and pending acquisitions

Since January 1, 2015, we ~~completed~~have acquired or have entered into definitive purchase agreements to acquire from unrelated third party sellers an ~~underwritten public offering~~aggregate of ~~5,750,000 shares~~approximately 15,940 gross (11,948 net) acres in the Midland Basin, primarily in northwest Howard County, in the Permian Basin, for an aggregate purchase price of ~~common stock,~~approximately $437.8 million, subject to certain adjustments. During April 2015, based on information reported by the sellers, net production attributable to this acreage is estimated to have been approximately 2,500 BOE/d (on a three-stream basis) (approximately 54% oil) from 117 gross producing vertical wells and three horizontal wells. Based on our evaluation and interpretation of reserve and production information provided by the sellers, as well as our analysis of available geologic and other data, we estimate net proved reserves as of the effective date for the for the acquisition of the applicable assets were approximately 4,347 MBOE. Our estimate of proved reserves has not been reviewed by our independent reserve engineers, and we may revise our estimates following ownership and operation of these properties. Approximately 83% of this acreage is held by production. We believe the acreage is prospective for horizontal drilling in the Lower Spraberry, Wolfcamp A and Wolfcamp B horizons, and have identified an aggregate of approximately 232 net potential horizontal drilling locations in these horizons based on 660 foot spacing between wells. We currently estimate that approximately 42% of the potential horizontal locations will have approximately 10,000 foot laterals, which ~~included 750,000 shares~~can provide higher rates of ~~common stock issued pursuant~~return and capital efficiency than shorter laterals. The average lateral length for these potential horizontal locations is estimated to be approximately 8,357 feet. We also believe that additional development potential may exist in the Middle Spraberry horizon. Salt water disposal infrastructure is already in place on the acreage in Northwest Howard County, and the acquisitions include 3-D seismic data that can be used to geosteer the drilling of horizontal wells. We have offered an ~~option~~average approximate 1.5% overriding royalty interest in certain of the acreage subject to ~~purchase additional shares granted~~these acquisitions to Viper for $33.7 million. This offer is subject to the ~~underwriters. The stock was sold~~approval of the conflicts committee of Viper’s general partner and our completion of the acquisitions, and there can be no assurance that this transaction will be completed on these terms or at all. We intend to finance the ~~public at $87.00 per share~~acquisitions, subject to market conditions and other factors, primarily with proceeds from one or more capital market transactions, which may include debt or equity offerings. We anticipate that we ~~received net proceeds~~will become the operator of approximately ~~$485.0 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions. The net proceeds~~93% of this ~~offering were used~~net acreage following the completion of these

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acquisitions, all of which are expected to ~~partially fund~~have been completed by the ~~September 9, 2014 acquisition~~end of June 2015. However, substantially all of the transactions remain subject to completion of due diligence and satisfaction of other closing conditions. There can be no assurance that we will acquire all or any portion of the acreage described above.

~~Unit transactions~~

Operating Results Overview

During the three months ended ~~September 30, 2014~~,March 31, 2015, our average daily production was approximately ~~20,636~~30,636 BOE/d, consisting of ~~15,503~~23,687 Bbls/d of oil, ~~13,058~~17,765 Mcf/d of natural gas and ~~2,957~~3,988 Bbls/d of natural gas liquids, an increase of ~~13,217~~17,084 BOE/d, or ~~178%~~126%, from average daily production of ~~7,419~~13,552 BOE/d for the three months ended ~~September 30, 2013~~,March 31, 2014, consisting of ~~5,596~~10,663 Bbls/d of oil, ~~4,850~~7,871 Mcf/d of natural gas and ~~1,014~~1,578 Bbls/d of natural gas liquids.

During the nine months ended September 30, 2014, our average daily production was approximately 17,367 BOE/d, consisting of 13,176 Bbls/d oil, 10,619 Mcf/d of natural gas and 2,422 Bbls/d of natural gas liquids, an increase of 11,092 BOE/d, or 177%, from average daily production of 6,275 BOE/d for the nine months ended September 30, 2013, consisting of 4,627 Bbls/d of oil, 4,417 Mcf/d of natural gas and 912 Bbls/d of natural gas liquids.

During the three months ended ~~September 30, 2014~~,March 31, 2015, we drilled 2715 gross ~~(23~~(13 net) horizontal wells and ~~participated in one~~two gross ~~non-operated well,~~(one net) vertical wells and did not participate in the ~~Permian Basin. During the nine months ended September 30, 2014, we drilled 82 gross (66 net) wells, and participated in an additional three gross (one net)~~drilling of any non-operated wells in the Permian Basin. ~~Additionally,~~In April 2015, we completed our first Lower Spraberry test well on ~~properties~~the acreage we acquired in Southwest Martin County in 2014. The Kimberly 714LS has a 7,472 foot lateral and was completed with 32 frac stages. This well is in initial flowback and is still cleaning up. In April 2015, we drilled an approximate 8,200 foot lateral (measured depth of approximately 18,000 feet) in Southwest Martin County in 12 days. In February 2015, we drilled a two-well pad in Midland County with an average lateral length of approximately 10,000 feet (average measured depth of approximately 19,000 feet) in 31 days from the spudding of the first well to total depth of the second well.

As commodity prices have strengthened during the second quarter of 2015 and we have received cost concessions from our service providers of up to 20% to 30% as compared to their peak pricing during 2014, we no longer plan to defer completions and, instead, intend to add a second dedicated completion crew in June to work on our backlog of drilled but uncompleted horizontal wells. Further, if cost concessions hold and commodity prices remain stable or strengthen, we expect to increase our horizontal rig count from three currently to five later this year ~~there were four~~and, potentially, to seven or eight in 2016. We now intend to complete 55 to 65 gross ~~(four net)~~horizontal wells ~~drilled~~ during 2015, an increase from our prior estimated range of 50 to 60 gross wells. In light of our continuing operational efficiencies and the ~~three months ended September 30, 2014~~cost concessions we have seen, we expect to complete these additional wells without an increase in our estimated $400.0 million to $450.0 million of capital expenditures in 2015. In addition, we are projecting that at $60/bbl for WTI, our leading edge cost savings and ~~ten gross (eight net) wells drilled during the nine months ended September 30, 2014 by the original operator between the effective date~~our efficiency gains will allow us to generate estimated project rates of return comparable to those generated when WTI was $75/bbl, but involved higher drilling and ~~closing date on the property acquired.~~completion costs.

~~Table of Contents~~

Sources of our revenue

Our revenues are derived from the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from our natural gas during processing. Our oil and natural gas revenues do not include the effects of derivatives. For the three months ended ~~September 30, 2014~~ ~~and~~ ~~2013~~,March 31, 2015, our revenues were derived ~~91% and~~ 92%~~, respectively,~~ from oil sales, ~~6% and 5%, respectively,~~4% from natural gas liquids sales and ~~3% and 3%, respectively,~~4% from natural gas sales. For the ~~nine~~three months ended ~~September 30,~~March 31, 2014, ~~and~~ ~~2013~~, our revenues were derived ~~91% and 90%, respectively,~~92% from oil sales, ~~6% and 7%, respectively,~~5% from natural gas liquids sales and 3% ~~and 3%, respectively,~~ from natural gas sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold, production mix or commodity prices.

Since our production consists primarily of oil, our revenues are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas liquids or natural gas prices. Oil, natural gas liquids and natural gas prices have historically been volatile. During ~~2013,~~2014, West Texas Intermediate posted prices ranged from ~~$86.65~~$53.45 to ~~$110.62~~$107.95 per Bbl and the Henry Hub spot market price of natural gas ranged from ~~$3.08~~$2.74 to ~~$4.52~~$8.15 per MMBtu. On ~~December~~March 31, ~~2013,~~2015, the West Texas Intermediate posted price for crude oil was ~~$98.17~~$47.72 per Bbl and the Henry Hub spot market price of natural gas was ~~$4.31~~$2.65 per MMBtu.

The industry has recently observed a decline in oil prices from over $105.00 per Bbl in June 2014 to below ~~$80.00~~$50.00 per Bbl ~~currently,~~during the majority of the three months ended March 31, 2015, combined with increasing service costs. While we ~~have not finalized our drilling plans for 2014, we intend to enter~~entered 2015 running ~~our current~~ five horizontal ~~rigs. However, if service costs are not reduced or commodity prices don’t improve,~~rigs and one vertical rig, we ~~expect to respond by drilling fewer wells next year than we initially anticipated, although we intend to continue to run~~released two horizontal rigs ~~on our~~and the one vertical rig in February 2015 and continue with three horizontal rigs, two of which are operating in Spanish ~~Trail acreage.~~Trail. Our decision to ~~maintain or possibly~~ reduce our ~~current~~ rig count, rather than increase it as previously contemplated, ~~will be~~is based on our goal of maximizing return on capital and minimizing debt until we can get a more attractive return on our assets.

3933

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Results of Operations

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


	Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended March 31,
	2014			2013			2014				2013			2015			2014
	(unaudited)													(in thousands, except Bbl, Mcf and BOE amounts)
	(in thousands, except Bbl, Mcf and BOE amounts)
Operating Results:
Revenues
Oil and natural gas revenues	$	139,127		$	57,791		$	364,135			$	132,094		$	101,401		$	98,004
Operating Expenses
Lease operating expense	13,805			4,964			32,216				15,367			22,456			7,915
Production and ad valorem taxes	8,954			3,553			23,350				8,295			8,395			5,842
Gathering and transportation expense	860			261			2,145				641			1,030			582
Depreciation, depletion and amortization	45,370			17,423			116,364				42,976			59,677			30,973
General and administrative	6,495			2,121			14,986				7,213			8,236			4,557
Asset retirement obligation accretion expense	127			46			303			��	134			170			72
Total expenses	75,611			28,368			189,364				74,626			99,964			49,941
Income from operations	63,516			29,423			174,771				57,468			1,437			48,063
Net interest expense	(9,846		)	(1,088		)	(24,090		)		(2,108		)	(10,497		)	(6,505		)
Other income	48			270			108				1,047			515			30
Other expense	(8		)	—			(1,416		)		—			—			—
Gain (loss) on derivative instruments, net	14,909			(4,910		)	(577		)		(1,881		)	18,354			(4,398		)
Loss from equity investment														—			—
Total other income (expense), net	5,103			(5,728		)	(25,975		)		(2,942		)	8,372			(10,873		)
Income before income taxes	68,619			23,695			148,796				54,526			9,809			37,190
Income tax provision	23,978			9,099			52,742				20,063			3,370			13,601
Net income	44,641			14,596			96,054				34,463
Net income (loss)														6,439			23,589
Less: Net income attributable to noncontrolling interest	902			—			973				—			590			—
Net income attributable to Diamondback Energy, Inc.	$	43,739		$	14,596		$	95,081			$	34,463
Net income (loss) attributable to Diamondback Energy, Inc.														$	5,849		$	23,589

Production Data:
Oil (Bbls)	1,426,271			514,853			3,596,983				1,263,097			2,131,829			959,631
Natural gas (Mcf)	1,201,296			446,195			2,899,097				1,205,763			1,598,810			708,419
Natural gas liquids (Bbls)	272,013			93,329			661,160				249,018			358,924			142,023
Combined volumes (BOE)	1,898,500			682,548			4,741,326				1,713,076			2,757,221			1,219,724
Daily combined volumes (BOE/d)	20,636			7,419			17,367				6,275			30,636			13,552

Average Prices⁽¹⁾:
Oil (per Bbl)	$	88.63		$	103.11		$	92.15			$	94.51		$	43.59		$	93.53
Natural gas (per Mcf)	3.92			3.50			4.27				3.63			2.72			4.71
Natural gas liquids (per Bbl)	29.44			33.67			30.72				33.49			11.53			34.58
Combined (per BOE)	73.28			84.67			76.80				77.11			36.78			80.35

Average Costs (per BOE)
Lease operating expense	$	7.27		$	7.27		$	6.79			$	8.97		$	8.14		$	6.49
Gathering and transportation expense	0.45			0.38			0.45				0.37			0.37			0.48
Production and ad valorem taxes	4.72			5.21			4.92				4.84			3.04			4.79
Production and ad valorem taxes as a % of sales	6.4		%	6.1		%	6.4		%		6.3		%	8.3		%	6.0		%
Depreciation, depletion, and amortization	23.90			25.53			24.54				25.09			21.64			25.39
General and administrative⁽²⁾	3.42			3.11			3.16				4.21			2.99			3.74
Interest expense	5.19			1.59			5.08				1.23			3.81			5.33

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(1)		After giving effect to our derivative instruments, the average prices per Bbl of oil and per BOE were ~~$87.55~~$64.01 and ~~$72.48,~~$52.57, respectively, during the three months ended ~~September 30, 2014,~~March 31, 2015 and ~~$96.86~~$92.43 and ~~$79.96,~~$79.48, respectively, during the three months ended September 30, 2013. After giving effect to our derivative instruments, the average prices per Bbl of oil and per BOE were $90.42 and $75.49, respectively, during the nine months ended September 30, 2014, and $90.06 and $73.83, respectively, during the nine months ended September 30, 2013.March 31, 2014.

(2)		General and administrative includes non-cash stock based compensation, net of capitalized amounts, of ~~$2,069~~$4,924 and ~~$490~~$2,190 for the three months ended ~~September 30,~~March 31, 2015 and 2014, ~~and 2013,~~ respectively. Excluding stock based compensation from the above metric results in general and administrative cost per BOE of ~~$2.33~~$1.20 and ~~$2.39~~$1.94 for the three months ended ~~September 30,~~March 31, 2015 and 2014, and 2013, respectively. General and administrative includes non-cash stock based compensation, net of capitalized amounts, of $5,387 and $1,426 for the nine months ended September 30, 2014 and 2013, respectively. Excluding stock based compensation from the above metric results in general and administrative cost per BOE of $2.03 and $3.38 for the nine months ended September 30, 2014 and 2013, respectively.

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Comparison of the Three Months Ended ~~September 30,~~March 31, 2015 and 2014 ~~and 2013~~

Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $~~81,336,000~~3.4 million, or ~~141%~~3%, to $~~139,127,000~~101.4 million for the three months ended ~~September 30, 2014~~March 31, 2015 from $~~57,791,000~~98.0 million for the three months ended ~~September 30, 2013~~.March 31, 2014. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by ~~13,217~~17,084 BOE/d to ~~20,636~~30,636 BOE/d during the three months ended ~~September 30, 2014~~March 31, 2015 from ~~7,419~~13,552 BOE/d during the three months ended ~~September 30, 2013~~.March 31, 2014. The total increase in revenue of approximately $~~81,336,000~~3.4 million is largely attributable to higher oil, natural gas liquids and natural gas production volumes for the three months ended ~~September 30, 2014~~March 31, 2015 as compared to the three months ended ~~September 30, 2013~~.March 31, 2014, substantially offset by lower average sales prices. The increases in production volumes were due to a combination of increased drilling activity and growth through acquisitions. Our production increased by ~~911,418~~1,172,198 Bbls of oil, ~~178,684~~216,901 Bbls of natural gas liquids and ~~755,101~~890,391 Mcf of natural gas for the three months ended ~~September 30, 2014~~March 31, 2015 as compared to the three months ended ~~September 30, 2013~~.March 31, 2014. The net dollar effect of the decreases in prices of approximately $~~21,300,000~~117.9 million (calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas liquids and natural gas) and the net dollar effect of the increase in production of approximately $~~102,636,000~~121.3 million (calculated as the increase in period-to-period volumes for oil, natural gas liquids and natural gas multiplied by the period average prices) are shown below.

Change in prices
Production volumes⁽¹⁾
Total net dollar effect of change
(in thousands)
Effect of changes in price:
Oil $ (14.48 ) 1,426,271
$ (20,655 )
Natural gas liquids $ (4.23 ) 272,013
$ (1,149 )
Natural gas $ 0.42
1,201,296
$ 504
Total revenues due to change in price $ (21,300 )

Change in production volumes⁽¹⁾
Prior period average prices Total net dollar effect of change
(in thousands)
Effect of changes in production volumes:
Oil 911,418
$ 103.11
$ 93,975
Natural gas liquids 178,684
$ 33.67
$ 6,016
Natural gas 755,101
$ 3.50
$ 2,645
Total revenues due to change in production volumes $ 102,636
Total change in revenues $ 81,336



	Change in prices			Production volumes⁽¹⁾		Total net dollar effect of change
						(in thousands)
Effect of changes in price:
Oil	$	(49.94	)	2,131,829		$	(106,472	)
Natural gas liquids	$	(23.05	)	358,924		$	(8,275	)
Natural gas	$	(1.99	)	1,598,810		$	(3,182	)
Total revenues due to change in price						$	(117,929	)

	Change in production volumes⁽¹⁾			Prior period average prices		Total net dollar effect of change
						(in thousands)
Effect of changes in production volumes:
Oil	1,172,198			$	93.53	$	109,635
Natural gas liquids	216,901			$	34.58	$	7,500
Natural gas	890,391			$	4.71	$	4,191
Total revenues due to change in production volumes						$	121,326
Total change in revenues						$	3,397




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

Lease Operating Expense. Lease operating expense, or LOE, was $~~13,805,000~~22.5 million ($~~7.27~~8.14 per BOE) for the three months ended ~~September 30, 2014~~,March 31, 2015, an increase of $~~8,841,000~~14.5 million, or ~~178%~~184%, from $~~4,964,000~~7.9 million ($~~7.27~~6.49 per BOE) for the three months ended ~~September 30, 2013~~.March 31, 2014. The increase is due to increased drilling activity and acquisitions, which resulted in 152 additional producing wells, for the three months ended ~~September 30, 2014~~March 31, 2015 as compared to the three months ended ~~September 30, 2013~~.March 31, 2014. Upon becoming the operator of wells acquired in our acquisitions, we seek to achieve the efficiencies in those wells that we have established with our existing portfolio of wells. ~~On a per BOE basis, LOE remained stable as new volumes came on line and expenses were held in line or were reduced.~~

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Production and Ad Valorem Tax Expense. Production and ad valorem taxes increased to $~~8,954,000~~8.4 million for the three months ended ~~September 30, 2014~~March 31, 2015 from $~~3,553,000~~5.8 million for the three months ended ~~September 30, 2013~~.March 31, 2014. In general, production taxes and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices. During the three months ended ~~September 30, 2014~~,March 31, 2015, our production taxes per BOE decreased by ~~$0.54~~$1.75 as compared to the three months ended ~~September 30, 2013~~,March 31, 2014, primarily reflecting the impact of lower oil and natural gas prices on production taxes. Our ad valorem taxes have increased primarily as a result of increased valuations on our properties.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization, or DD&A, expense increased $~~27,947,000~~28.7 million, or ~~160%~~93%, from $~~17,423,000~~31.0 million for the three months ended ~~September 30, 2013~~March 31, 2014 to $~~45,370,000~~59.7 million for the three months ended ~~September 30, 2014~~.March 31, 2015.

The following table provides components of our DD&A expense for the periods presented:


	Three Months Ended September 30,				Three Months Ended March 31,
	2014		2013		2015		2014

	(in thousands, except BOE amounts)				(in thousands, except BOE amounts)
Depletion of proved oil and natural gas properties	$	45,010	$	17,227	$	59,255	$	30,724
Depreciation of other property and equipment	360		196		422		249
DD&A	$	45,370	$	17,423	$	59,677	$	30,973

Oil and natural gas properties DD&A per BOE	$	23.71	$	25.24	$	21.49	$	25.19
Total DD&A per BOE	$	23.90	$	25.53	$	21.64	$	25.39

The increases in depletion of proved oil and natural gas properties of ~~$27,783,000~~$28.5 million for the three months ended ~~September 30, 2014~~March 31, 2015 as compared to the three months ended ~~September 30, 2013~~March 31, 2014 resulted primarily from higher total production levels, increased net book value on new reserves added and an increase in capitalized interest to the full cost pool. On a per BOE basis, DD&A decreased primarily due to the increased net book value on new reserves and acquisitions.

General and Administrative Expense. General and administrative expense increased $~~4,374,000~~3.7 million from $~~2,121,000~~4.6 million for the three months ended ~~September 30, 2013~~March 31, 2014 to $~~6,495,000~~8.2 million for the three months ended ~~September 30, 2014~~.March 31, 2015. The increase was due to increases in stock based compensation ~~salary, legal, common stock offering, professional service~~ and ~~advisory service expenses. These increases were partially offset by increases in general~~salaries and ~~administrative costs related to exploration and development activity capitalized to the full cost pool and increases in COPAS overhead reimbursements due to increased drilling activity.~~benefits expense.

Net Interest Expense. Net interest expense for the three months ended ~~September 30, 2014~~March 31, 2015 was $~~9,846,000~~10.5 million as compared to $~~1,088,000~~6.5 million for the three months ended ~~September 30, 2013~~,March 31, 2014, an increase of $~~8,758,000~~4.0 million. This increase was due primarily to the ~~issuance~~higher average level of ~~$450.0 million in aggregate principal amount of~~outstanding borrowings under our ~~7.625% senior notes in September 2013.~~credit facility during the three months ended March 31, 2015 as compared to the three months ended March 31, 2014.

Derivatives. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our combined consolidated statements of operations under the line item captioned “Gain (loss) on derivative instruments, net.” For the three months ended ~~September 30, 2014~~March 31, 2015 and ~~2013~~2014, we had a cash gain on settlement of derivative instruments of $43.6 million and a cash loss on settlement of derivative instruments of $~~1,531,000~~ ~~and~~ ~~$3,215,000~~1.1 million, respectively. For the three months ended ~~September 30, 2014~~March 31, 2015 and ~~2013~~2014, we had a ~~non-cash gain on~~negative change in the fair value of open derivative instruments of ~~$16,440,000~~$25.2 million and ~~a non-cash loss on open derivative instruments of $1,695,000,~~$3.3 million, respectively.

Income Tax Expense. We recorded income tax expense of $~~23,978,000~~3.4 million for the three months ended ~~September 30, 2014~~March 31, 2015 as compared to ~~$9,099,000~~$13.6 million for the three months ended ~~September 30, 2013~~.March 31, 2014. Our effective tax rate was ~~34.9%~~34.4% for the three months ended ~~September 30, 2014~~March 31, 2015 as compared to ~~38.4%~~36.6% for the three months ended ~~September 30, 2013~~.March 31, 2014.

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~~Comparison of the Nine Months Ended September 30, 2014 and 2013~~

~~Oil, Natural Gas Liquids and Natural Gas Revenues.~~ Our oil, natural gas liquids and natural gas revenues increased by approximately $232,041,000, or 176%, to $364,135,000 for the nine months ended September 30, 2014 from $132,094,000 for the nine months ended September 30, 2013. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 11,092 BOE/d to 17,367 BOE/d during the nine months ended September 30, 2014 from 6,275 BOE/d during the nine months ended September 30, 2013. The total increase in revenue of approximately $232,041,000 is largely attributable to higher oil, natural gas liquids and natural gas production volumes for the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013. The increases in production volumes were due to a combination of increased drilling activity and growth through acquisitions. Our production increased by 2,333,886 Bbls of oil, 412,142 Bbls of natural gas liquids and 1,693,334 Mcf of natural gas for the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013. The net dollar effect of the decreases in prices of approximately $8,486,000 (calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas liquids and natural gas) and the net dollar effect of the increase in production of approximately $240,527,000 (calculated as the increase in period-to-period volumes for oil, natural gas liquids and natural gas multiplied by the period average prices) are shown below.

Change in prices
Production volumes⁽¹⁾
Total net dollar effect of change
(in thousands)
Effect of changes in price:
Oil $ (2.36 ) 3,596,983
$ (8,498 )
Natural gas liquids $ (2.77 ) 661,160
$ (1,828 )
Natural gas $ 0.64
2,899,097
$ 1,840
Total revenues due to change in price $ (8,486 )

Change in production volumes⁽¹⁾
Prior period average prices Total net dollar effect of change
(in thousands)
Effect of changes in production volumes:
Oil 2,333,886
$ 94.51
$ 220,571
Natural gas liquids 412,142
$ 33.49
$ 13,802
Natural gas 1,693,334
$ 3.63
$ 6,154
Total revenues due to change in production volumes $ 240,527
Total change in revenues $ 232,041




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

~~Lease Operating Expense.~~ Lease operating expense, or LOE, was $32,216,000 ($6.79 per BOE) for the nine months ended September 30, 2014, an increase of $16,849,000, or 110%, from $15,367,000 ($8.97 per BOE) for the nine months ended September 30, 2013. The increase is due to increased drilling activity and acquisitions, which resulted in additional producing wells for the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013. On a per BOE basis, LOE declined as new volumes came on line and expenses were held in line or were reduced. By the end of 2013, we were moving approximately 70% of our produced water by pipeline directly into commercial salt water disposal wells, rather than by truck, thereby further reducing one of our largest components of LOE.

~~Table of Contents~~

~~Production and Ad Valorem Tax Expense.~~ Production and ad valorem taxes increased to $23,350,000 for the nine months ended September 30, 2014 from $8,295,000 for the nine months ended September 30, 2013. In general, production taxes and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices. During the nine months ended September 30, 2014, our production taxes per BOE decreased by $0.03 as compared to the nine months ended September 30, 2013. Our ad valorem taxes have increased primarily as a result of increased valuations on our properties.

~~Depreciation, Depletion and Amortization.~~ Depreciation, depletion and amortization, or DD&A, expense increased $73,388,000, or 171%, from $42,976,000 for the nine months ended September 30, 2013 to $116,364,000 for the nine months ended September 30, 2014.

~~The following table provides components of our DD&A expense for the periods presented:~~

Nine Months Ended September 30,
2014 2013

(in thousands, except BOE amounts)
Depletion of proved oil and natural gas properties $ 115,437
$ 42,411
Depreciation of other property and equipment 927
565
DD&A $ 116,364
$ 42,976

Oil and natural gas properties DD&A per BOE $ 24.39
$ 24.76
Total DD&A per BOE $ 24.54
$ 25.09

The increases in depletion of proved oil and natural gas properties of $73,026,000 for the nine months ended September 30, 2014 as compared to the nine months ended September 30, 2013 resulted primarily from higher total production levels, increased net book value on new reserves added and an increase in capitalized interest to the full cost pool. On a per BOE basis, DD&A decreased primarily due to the increased net book value on new reserves and acquisitions.

~~General and Administrative Expense.~~ General and administrative expense increased $7,773,000 from $7,213,000 for the nine months ended September 30, 2013 to $14,986,000 for the nine months ended September 30, 2014. The increase was due to increases in stock based compensation, salary, legal, common stock offering, professional service and advisory service expenses. These increases were partially offset by increases in general and administrative costs related to exploration and development activity capitalized to the full cost pool and increases in COPAS overhead reimbursements due to increased drilling activity.

~~Net Interest Expense.~~ Net interest expense for the nine months ended September 30, 2014 was $24,090,000 as compared to $2,108,000 for the nine months ended September 30, 2013, an increase of $21,982,000. This increase was due primarily to the issuance of $450.0 million in aggregate principal amount of our 7.625% senior notes in September 2013.

~~Derivatives.~~ We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our consolidated statements of operations under the line item captioned “Loss on derivative instruments, net.” For the nine months ended September 30, 2014 and 2013, we had a cash loss on settlement of derivative instruments of $6,207,000 and $5,614,000, respectively. For the nine months ended September 30, 2014 and 2013, we had a non-cash gain on open derivative instruments of $5,630,000 and $3,733,000, respectively.

~~Income Tax Expense.~~ We recorded income tax expense of $52,742,000 for the nine months ended September 30, 2014 as compared to $20,063,000 for the nine months ended September 30, 2013. Our effective tax rate was 35.4% for the nine months ended September 30, 2014 as compared to 36.8% for the nine months ended September 30, 2013.

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Liquidity and Capital Resources

Our primary sources of liquidity have been proceeds from our public equity offerings, borrowings under our revolving credit facility, proceeds from the issuance of the senior notes and cash flows from operations. Our primary use of capital has been for the acquisition, development and exploration of oil and natural gas properties. As we pursue reserves and production growth, we regularly consider which capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us.

Liquidity and Cash Flow

Our cash flows for the ~~nine~~three months ended ~~September 30, 2014~~March 31, 2015 and ~~2013~~2014 are presented below:


	Nine Months Ended September 30,						Three Months Ended March 31,
	2014			2013			2015			2014

	(in thousands)						(in thousands)
Net cash provided by operating activities	$	251,995		$	91,647		$	99,143		$	71,466
Net cash used in investing activities	(1,289,081		)	(830,172		)	(153,555		)	(399,184		)
Net cash provided by financing activities	$	1,062,175		$	765,267		$	55,872		$	337,477
Net change in cash	$	25,089		$	26,742		$	1,460		$	9,759

Operating Activities

Net cash provided by operating activities was $~~252.0~~99.1 million for the ~~nine~~three months ended ~~September 30, 2014~~March 31, 2015 as compared to $~~91.6~~71.5 million for the ~~nine~~three months ended ~~September 30, 2013~~March 31, 2014. The increase in operating cash flows is aprimarily the result of ~~increases~~the increase in our oil and natural gas revenues due to a 126.1% increase in our net BOE production, ~~growth and lower expenses~~partially offset by a 54.2% decrease in ~~2014.~~our net realized sales prices.

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

See “—Sources of our revenue” above.

Investing Activities

The purchase and development of oil and natural gas properties accounted for the majority of our cash outlays for investing activities. We used cash for investing activities of $~~1,289.1~~153.6 million and $~~830.2~~399.2 million during the ~~nine~~three months ended ~~September 30, 2014~~March 31, 2015 and ~~2013~~2014, respectively.

During the ~~nine~~three months ended ~~September 30, 2014~~March 31, 2015, we spent $~~313.9~~151.4 million on capital expenditures in conjunction with our infrastructure projects and drilling program, in which we drilled 6115 gross ~~(49~~(13 net) horizontal wells 31and two gross ~~(25~~(one net) vertical wells. We spent an additional $2.0 million on leasehold costs, $0.2 million for the purchase of other property and equipment.

During the three months ended March 31, 2014, we spent $86.4 million on capital expenditures in conjunction with our drilling program in which we drilled 29 gross (24 net) wells and participated in the drilling of an additional ~~three~~one gross ~~(one net)~~ non-operated wells. We spent an additional $~~840.5~~312.2 million on leasehold costs and $~~43.2~~0.6 million for the purchase of other property and equipment. OnIn February ~~27 and 28,~~ 2014, we completed acquisitions of additional oil and natural gas leasehold interests in Martin County, Texas, in the Permian Basin, from unrelated third party sellers for an aggregate purchase price of approximately $292.2 million, subject to certain adjustments. ~~On August 25,~~

Our investing activities for the three months ended March 31, 2015 and 2014 ~~we completed an acquisition of surface rights~~ are summarized in the Permian Basin from unrelated third party sellers for a purchase price of approximately $41.9 million. On September 9, 2014, we completed the acquisition of oil and natural gas interests from unrelated third party sellers of additional leasehold interests in Midland, Glasscock, Reagan and Upton Counties, Texas in the Permian Basin, for an aggregate purchase price of approximately $523.3 million, subject to certain adjustments. We spent approximately $57.7 million on acquisitions of mineral interests underlying approximately 10,565 gross (3,461) net acres in the Midland and Delaware basins and approximately $33.9 million for a minor equity interest in an entity that owns mineral, overriding royalty, net profits, leasehold and other similar interests.following table:

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~~During the~~ ~~nine months ended September 30, 2013, we spent~~ ~~$190.1 million~~ on capital expenditures in conjunction with our drilling program in which we drilled 59 gross (51 net) wells and participated in the drilling of an additional four gross (two net) non-operated wells. We spent an additional $440.0 million on the acquisition of mineral interests, ~~$176.3 million~~ ~~on leasehold costs,~~ ~~$5.0 million~~ ~~for the purchase of other property and equipment,~~ ~~$0.3 million~~, net, on the settlement of non-hedge derivative instruments and $18.6 million for the post-closing adjustment associated with our acquisition of Gulfport Energy Corporation’s oil and natural gas assets in the Permian Basin in connection with our initial public offering in October 2012.

~~Our investing activities for the~~ ~~nine months ended September 30, 2014~~ ~~and~~ ~~2013~~ ~~are summarized in the following table:~~


	Nine Months Ended September 30,						Three Months Ended March 31,
	2014			2013			2015			2014

	(in thousands)						(in thousands)
Drilling, completion and infrastructure	$	(313,856	)	$	(190,084	)	$	(151,397	)	$	(86,393	)
Acquisition of leasehold interests	(840,482		)	(176,346		)	(2,000		)	(312,207		)
Acquisition of Gulfport properties	—			(18,550		)	—			—
Acquisition of mineral interests	(57,688		)	(440,000		)	—			—
Purchase of other property and equipment	(43,215		)	(4,965		)	(158		)	(595		)
Proceeds from sale of property and equipment	11			62			—			11
Cost method investment	(33,851		)	—			—			—
Settlement of non-hedge derivative instruments	—			(289		)	—			—
Receipt on derivative margins							—			—
Net cash used in investing activities	$	(1,289,081	)	$	(830,172	)	$	(153,555	)	$	(399,184	)

Financing Activities

Net cash provided by financing activities for the ~~nine~~three months ended ~~September 30,~~ March 31, 2015 and 2014 was $~~1,062.2~~55.9 million ~~as compared~~and $337.5 million, respectively. During the three months ended March 31, 2015, the amount provided by financing activities was primarily attributable to ~~$765.3~~the net proceeds from our January 2015 equity offering of $119.4 million ~~during~~ partially offset by the ~~same period in~~ ~~2013~~.repayment, net of borrowings of $61.9 million under our credit facility. The 2014 amount provided by financing activities was primarily attributable to the net proceeds of $208.4 million from our February 2014 equity offering ~~net proceeds of $137.2 million from the Viper Offering, net proceeds of $485.0 million from our July 2014 equity offering, net proceeds of $95.1 million from the Viper September 2014 equity offering~~ and borrowings ~~net~~ of ~~repayment, of $130.0~~$127.0 million under our credit facility. ~~During the~~ ~~nine months ended September 30, 2013~~, the amount provided by financing activities was primarily attributable to the net proceeds of $144.4 million from our May 2013 equity offering, $177.5 million from our August 2013 equity offering, $450.0 million from our September 2013 senior note offering and borrowings of $49.0 million under our revolving credit facility, which were repaid with proceeds from the May 2013 offering. In both periods, these proceeds were used primarily to acquire property and fund our drilling costs.

~~Senior Notes~~

~~On September 18, 2013, we completed an offering of~~ ~~$450.0 million~~ ~~in aggregate principal amount of~~ ~~7.625%~~ ~~senior unsecured notes due 2021, which we refer to as 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, we 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 of September 30, 2014, the Senior Notes are fully and unconditionally guaranteed by Diamondback O&G LLC, Diamondback E&P LLC and White Fang Energy 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 to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act.

The senior notes were issued under, and are governed by, an indenture among us, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as the trustee, as amended and supplemented, or the Indenture. We may issue additional senior notes under the Indenture, and all senior notes issued under the Indenture will constitute part of a single class of securities for all purposes of the Indenture. The Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of our restricted

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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 indebtedness, sell assets including capital stock of subsidiaries, agree to payment restrictions affecting our restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and gas business and designate certain of our subsidiaries as unrestricted subsidiaries. If we experience certain kinds of changes of control or if we sell certain of our assets, holders of the senior notes may have the right to require us to repurchase their senior notes.

~~We 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, we 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, we 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, we and the subsidiary guarantors entered into a registration rights agreement with the initial purchasers on September 18, 2013, pursuant to which we 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 declared effective by the SEC on September 15, 2014. The exchange offer was completed on October 23, 2014.

Second Amended and Restated Credit Facility

Our second amended and restated credit agreement, dated November 1, 2013, as amended on June 9, 2014 and November 13, 2014, 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~~2.0 billion, subject to scheduled semi-annual and other elective collateral borrowing base redeterminations based on our 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~~May 1st and ~~October~~November 1st. In addition, we may request up to three additional redeterminations of the borrowing base during any 12-month period. As of ~~September 30, 2014~~March 31, 2015, the borrowing base was set at $~~350.0~~750.0 million ~~and~~, although we elected a commitment amount of $500.0 million. In connection with our Spring 2015 redetermination, the agent lender under the credit agreement has recommended that our borrowing base be set at $725.0 million. This adjustment is subject to the approval of our other lenders. Regardless of such adjustment, we currently intend to continue our election of a commitment amount of $500.0 million. As of March 31, 2015, we had outstanding borrowings of ~~$140.0~~$161.6 million, which bore a weighted-average interest rate of 1.92%, and ~~$210.0~~$338.4 million available for future borrowings under this facility. ~~Our weighted-average interest rate on borrowings under~~As of March 31, 2015, the credit agreement is guaranteed by us, Diamondback E&P LLC and White Fang Energy LLC and will also be guaranteed by any future restricted subsidiaries of Diamondback. The credit agreement is also secured by substantially all of our ~~credit facility was 1.64% during~~assets and the ~~nine months ended September 30, 2014. Our lead lender recently approved an increase in our borrowing base to $750.0 million, however we have elected to limit~~assets of Diamondback O&G LLC and the ~~lenders’ aggregate commitment to $500.0 million.~~guarantors.

The outstanding borrowings under the credit agreement bear interest at a rate elected by us 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%~~0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from ~~0.5%~~0.50% 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. We are obligated to pay a quarterly commitment fee ranging from 0.375% to 0.50% 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 repaid (a) to the extent the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2018.

On June 9, 2014, we entered into a first amendment to the second amended and restated credit agreement, dated November 1, 2013. This amendment modified certain provisions of the credit agreement to, among other things, allow us to designate one or more of our subsidiaries as “Unrestricted Subsidiaries” that are not subject to certain restrictions contained in the credit agreement. In connection with the Viper Offering, we designated the

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Partnership, the General Partner and Viper Energy LLC as unrestricted subsidiaries under the credit agreement. As of September 30, 2014, the loan is guaranteed by us, Diamondback E&P LLC and White Fang Energy LLC and will also be guaranteed by any future restricted subsidiaries of Diamondback. The credit agreement is also secured by substantially all of our assets and the assets of Diamondback O&G LLC and the guarantors.

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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 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 ~~September 30, 2014,~~March 31, 2015, we had $450 million of senior notes outstanding.

As of ~~September 30, 2014,~~March 31, 2015, we were in compliance with all financial covenants under our revolving credit facility. The lenders may accelerate all of the indebtedness under our revolving credit facility upon the occurrence 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. With certain specified exceptions, the terms and provisions of our revolving credit facility generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.

Partnership Credit Facility-Wells Fargo Bank

On July 8, 2014, ~~the Partnership~~Viper entered into a secured revolving credit agreement with Wells Fargo Bank, National Association, or Wells Fargo, as the administrative agent, sole book runner and lead arranger. The credit agreement, which was amended August 15, 2014 to add additional lenders to the lending group, 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~~Viper’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~~Viper may request up to three additional redeterminations of the borrowing base during any 12-month period. As of ~~September 30, 2014,~~March 31, 2015, the borrowing base was set at $110.0 ~~million. The Partnership~~million and Viper had no outstanding ~~borrowings as~~borrowings. In connection with Viper’s Spring 2015 redetermination, the agent lender under the credit agreement has recommended that Viper’s borrowing base be increased to $175.0 million. This increase is subject to the approval of ~~September 30, 2014.~~the other lenders.

The outstanding borrowings under ~~the~~Viper's credit agreement bear interest at a rate elected by ~~the Partnership~~Viper 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%~~0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from ~~0.5%~~0.50% 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~~Viper 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.

The Viper 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.

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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 ended September 30, 2014 and ending with the quarter ending March 31, 2015

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $250 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the

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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~~Viper’s revolving credit facility upon the occurrence and during the continuance of any event of default. The Viper 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.

Capital Requirements and Sources of Liquidity

Our board of directors approved a ~~2014~~2015 capital budget for drilling and infrastructure of ~~$425.0~~$400.0 million to ~~$475.0 million, representing an increase of 48% over 2013.~~$450.0 million. We estimate that, of these expenditures, approximately:

~~85%~~$285.0 million to $315.0 million will be spent on 65drilling and completing 50 to 7560 gross ~~(52~~(43 to 6052 net) operated horizontal wells focused in Midland, Andrews, Upton, Martin and Dawson Counties;

8%$20.0 million to $30.0 million will be spent on 20infrastructure;

$20.0 million to ~~25 gross (16 to 20 net) operated vertical wells focused in Midland County;~~

~~5% will be spent on infrastructure; and~~

2%$30.0 million will be spent on non-operated ~~drilling.~~activity and other expenditures; and

an estimated $75.0 million for expenditures related to 2014 activity (net of expenditures from 2015 expected to be carried into 2016).

During the ~~nine~~three months ended ~~September 30, 2014~~March 31, 2015, our aggregate capital expenditures for drilling and infrastructure were $~~313.9~~151.4 million. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted. During the ~~nine~~three months ended ~~September 30, 2014~~March 31, 2015, we spent approximately $~~840.5~~2.0 million on acquisitions of leasehold interests. For information regarding our recently completed and pending acquisitions, see “—Recent Developments—Recent and pending acquisitions.”

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

Based upon current oil and natural gas price and production expectations for ~~2014,~~2015, we believe that our cash flow from operations and borrowings under our revolving credit facility will be sufficient to fund our operations through year-end ~~2014.~~2015. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. Further, our ~~2014~~2015 capital expenditure budget does not allocate any funds for leasehold interest and property acquisitions.

We monitor and adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control. If we require additional capital, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financing, asset sales, offerings of debt and or equity securities or other means. We cannot assure you that the needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our drilling programs, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves.

Contractual Obligations

Except as discussed in Note 14 of the Notes to the Consolidated Financial Statements of this Form 10-Q there were no material changes to our contractual obligations and other commitments, as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2014.

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Critical Accounting Policies

There have been no changes in our critical accounting policies from those disclosed in our Annual Report on Form 10-K for the year ended December 31, ~~2013.~~

~~Recent Accounting Pronouncements~~

~~In May~~ 2014 ~~the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers~~”. ASU 2014-09 supersedes most of the existing revenue recognition requirements in accounting principles generally accepted in the United States and requires (i) an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) requires expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers. The standard will be effective for annual and interim reporting periods beginning after December 15, 2016, with early application not permitted. The standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. We are currently evaluating the impact this standard will have on our financial position, results of operations or cash flows.

Off-balance Sheet Arrangements

We ~~had~~currently have no off-balance sheet arrangements as of ~~September 30, 2014~~March 31, 2015.

~~Contractual Obligations~~

~~There were no material changes~~ Please read Note 15 included in Notes to the Combined Consolidated Financial Statements set forth in Part I, Item 1 of this Form 10–Q, for a discussion of our ~~contractual obligations~~commitments and ~~other commitments, as disclosed~~contingencies, some of which are not recognized in ~~our Annual Report on Form 10-K for~~ the ~~year ended December 31, 2013.~~balance sheets under GAAP.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

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

We use price swap derivatives to reduce price volatility associated with certain of our oil sales. With respect to these fixed price swap contracts, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap price, and we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. Our derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on Argus Louisiana light sweet pricing.

At ~~September 30, 2014,~~March 31, 2015, we had a net asset derivative position of ~~$6,061,000,~~$92.3 million, related to our ~~Argus Louisiana Light Sweet fixed~~ price ~~swaps,~~swap derivatives, as compared to a net asset derivative position of ~~$431,000~~$0.4 million as of December 31, ~~2013~~2014 related to our price swap derivatives. Utilizing actual derivative contractual volumes under our fixed price swaps as of ~~September 30, 2014,~~March 31, 2015, a 10% increase in forward curves associated with the underlying commodity would have ~~decrease~~decreased the net asset position ~~into a net liability derivative position of $2,986,000~~to $76.5 million, a decrease of ~~$9,047,000,~~$15.8 million, while a 10% decrease in forward curves associated with the underlying commodity would have increased the net asset derivative position to ~~$15,108,000~~$108.2 million, an increase of ~~$9,047,000.~~$15.8 million. However, any cash derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.

~~Subsequent to September 30, 2014, we entered into additional~~ ~~commodity contracts. The contracts are fixed price oil swaps that will settle against the weighted average price per barrel of~~ ~~Argus Louisiana light sweet or NYMEX West Texas Intermediate during the calculation period. The following table presents the terms of the contracts:~~

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Fixed Swap
Volumes (Bbls) Price Production Period
Crude Oil—Argus Louisiana Light Sweet Fixed Price Swap 183,000
$ 82.95
November 2014 December 2014
Crude Oil—Argus Louisiana Light Sweet Fixed Price Swap 1,095,000
$ 90.99
January 2015 - December 2015
Crude Oil—NYMEX West Texas Intermediate Fixed Price Swap 1,825,000
$ 84.10
January 2015 - December 2015
Crude Oil—ICE Brent Fixed Price Swap

640,000
$ 88.78
February 2015 - January 2016
Crude Oil—ICE Brent Fixed Price Swap
91,000
$ 88.72
January 2016 - February 2016

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from joint interest receivables (approximately ~~$37.7~~$44.6 million at ~~September 30, 2014~~March 31, 2015) and receivables from the sale of our oil and natural gas production (approximately ~~$$50.6~~$38.6 million at ~~September 30, 2014~~March 31, 2015).

We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. For the ~~nine~~three months ended ~~September 30, 2014~~March 31, 2015, two purchasers accounted for more than 10% of our revenue: Shell Trading (US) Company ~~(66%~~(68%); and Enterprise Crude Oil LLC ~~(17%~~(11%). For the year ended December 31, ~~2013,~~2014, two purchasers accounted for more than 10% of our revenue: ~~Plains Marketing, L.P. (37%); and~~ Shell Trading (US) Company ~~(37%~~(64%) and Enterprise Crude Oil LLC (16%). No other customer accounted for more than 10% of our revenue during these periods.

Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells. At ~~September 30, 2014~~March 31, 2015, we had ~~two customers~~one customer that represented approximately ~~56%~~44% of our total joint operations receivables. At December 31, ~~2013,~~2014, we had one customer that represented approximately ~~86%~~61% of our total joint operations receivables.

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Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facility. The terms of our revolving credit facility provide for interest on borrowings at a floating rate 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. Our weighted-average interest rate on borrowings ~~from~~under our credit facility was ~~1.64% during the nine months ended September 30, 2014.~~1.92% at March 31, 2015. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our interest expense of approximately ~~$140,000~~$1.6 million based on the ~~$140.0~~$161.6 million outstanding in the aggregate under our revolving credit facility on ~~September 30, 2014.~~March 31, 2015.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Control and Procedures

Under the direction of our Chief Executive Officer and Chief Financial Officer, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, or the Exchange Act, that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and

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procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

As of ~~September 30, 2014,~~March 31, 2015, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that as of ~~September 30, 2014,~~March 31, 2015, our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There have not been any changes in our internal control over financial reporting that occurred during the quarter ended ~~September 30, 2014~~March 31, 2015 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

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PART II

~~PART II. OTHER INFORMATION~~

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A.RISK ~~FACTORS.~~

FACTORS

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

In addition to the information set forth in this Form ~~10–Q,~~10-Q, you should carefully consider the risk factors discussed in Part I, Item 1A. Risk Factors in our Annual Report on Form ~~10–K~~10-K for the year ended December 31, ~~2013.~~2014. There have been no material changes in our risk factors from those described in our Annual Report on Form ~~10–K~~10-K for the year ended December 31, ~~2013.~~2014.

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ITEM 6. EXHIBITS

EXHIBIT INDEX



Exhibit Number		Description
2.1#		Purchase and Sale Agreement dated February 14, 2014, between Henry Resources LLC, Henry Production LLC, Henry Taw Production LP, Davlin LP, Good Providence LP, William R. Fair, UTH Investments LTD, Paloma Oil & Ranch LP, Chinati Oil & Ranch LP, J. Craig Corbett, Bambana Resources LP, and FC Permian Properties, Inc., as Sellers, and Diamondback E&P LLC, as Buyer (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on February 18, 2014).
2.2#		Purchase and Sale Agreement, dated February 14, 2014, between Henry Resources LLC, Henry Production LLC, Henry Taw Production LP, Davlin LP, Good Providence LP, William R. Fair, UTH Investments LTD, Paloma Oil & Ranch LP, Chinati Oil & Ranch LP, J. Craig Corbett, Bambana Resources LP, FC Permian Properties, Inc., Blake Braun, Richard D. Campbell, and Thomas J. Woodside, as Sellers, and Diamondback E&P LLC, as Buyer (incorporated by reference to Exhibit 2.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on February 18, 2014).
2.3#		Purchase and Sale Agreement by and among Rio Oil and Gas, LLC, Rio Oil and Gas (Permian) LLC, Rio Oil and Gas (OPCO), LLC, Bluestem Energy, LP, Bluestem Energy Partners, LP, Bluestem Energy Holdings, LLC, Bluestem Energy Assets, LLC, Bluestem Acquisitions, LLC, BC Operating, Inc., Crown Oil Partners V, LP and Crump Energy Partners II, LLC, as sellers, and Diamondback E&P LLC, as buyer, dated July 18, 2014 (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on July 21, 2014).
3.1		Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
3.2		Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
4.1		Specimen certificate for shares of common stock, par value $0.01 per share, of the Company (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).

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~~Exhibit Number~~		~~Description~~
4.2		Registration Rights Agreement, dated as of October 11, 2012, by and between the Company and DB Energy Holdings LLC (incorporated by reference to Exhibit 4.2 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
4.3		Investor Rights Agreement, dated as of October 11, 2012, by and between the Company and Gulfport Energy Corporation (incorporated by reference to Exhibit 4.3 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
4.4		Indenture, dated as of September 18, 2013, among Diamondback Energy, Inc., the subsidiary guarantors party thereto and Wells Fargo, N.A., as trustee (including the form of Diamondback Energy, Inc.’s 7.625% Senior Note due October 2021 (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on September 18, 2013).
4.5		First Supplemental Indenture, dated as of November 5, 2013, by and ~~between~~among Diamondback Energy, Inc., the subsidiary guarantors party thereto and Wells Fargo, ~~N.A,~~National Association, as trustee (incorporated by reference to Exhibit 4.5 to the Form 10-K, File No. 001-35700, filed by the Company with the SEC on February 19, 2014).
4.6		~~Registration Rights Agreement,~~Second Supplemental Indenture, dated as of ~~September 18, 2013,~~October 8, 2014, by and among Diamondback Energy, Inc., ~~the~~White Fang Energy LLC, as subsidiary guarantor, other subsidiary guarantors party ~~thereto~~thereo and Credit Suisse Securities (USA) LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on September 18, 2013).
~~10.1~~		~~Senior Secured Revolving Credit Agreement, dated as of July 8, 2014, among Viper Energy Partners LP, as borrower,~~ Wells Fargo, ~~Bank,~~ National Association, as the administrative agent, sole book runner and lead arranger, and certain lenders from time to time party thereto. (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-36505, filed by Viper Energy Partners LP on July 14, 2014).trustee.
31.1*		Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
31.2*		Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
~~32.1++~~32.1**		Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.

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~~32.2++~~

Exhibit Number		Description
32.2**		Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
101.INS*		XBRL Instance Document.
101.SCH*		XBRL Taxonomy Extension Schema Document.
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*		XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.

_______________



*	Filed herewith.
**	The certifications attached as Exhibit 32.1 and Exhibit 32.2 accompany this Annual Report on Form 10-K pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.
#	The schedules (or similar attachments) referenced in this agreement have been omitted in accordance with Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule (or similar attachment) will be furnished supplementally to the Securities and Exchange Commission upon request.
*	~~Filed herewith.~~
++	The certifications attached as Exhibit 32.1 and Exhibit 32.2 accompany this Quarterly Report on Form 10-Q pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

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Table of Contents

SIGNATURES

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



			DIAMONDBACK ENERGY, INC.

Date:	~~November~~May 6, ~~2014~~	2015
			/s/ Travis D. Stice
			Travis D. Stice
			Chief Executive Officer
			(Principal Executive Officer)

			/s/ Teresa L. Dick
			Teresa L. Dick
			Chief Financial Officer
			(Principal Financial and Accounting Officer)



	(in thousands)
Joint interest receivables	$	42
Proved oil and natural gas properties	128,589
Unevaluated oil and natural gas properties	400,527
Total assets acquired	529,158
Accrued production and ad valorem taxes	358
Revenues payable	3,174
Asset retirement obligations	2,366
Total liabilities assumed	5,898
Total fair value of net assets	$	523,260



	(in thousands)
Proved oil and natural gas properties	$	170,174
Unevaluated oil and natural gas properties	123,243
Total assets acquired	293,417
Asset retirement obligations	1,258
Total liabilities assumed	1,258
Total fair value of net assets	$	292,159



		Fixed Swap
	Volumes (Bbls)	Price		Production Period
Crude Oil—Argus Louisiana Light Sweet Fixed Price Swap	183,000	$	82.95	November 2014	-	December 2014
Crude Oil—Argus Louisiana Light Sweet Fixed Price Swap	1,095,000	$	90.99	January 2015	-	December 2015
Crude Oil—NYMEX West Texas Intermediate Fixed Price Swap	1,825,000	$	84.10	January 2015	-	December 2015
Crude Oil—ICE Brent Fixed Price Swap	640,000	$	88.78	February 2015	-	January 2016
Crude Oil—ICE Brent Fixed Price Swap	91,000	$	88.72	January 2016	-	February 2016



Condensed Consolidated Statement of Operations
Nine Months Ended September 30, 2013
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues:
Oil sales	$	—		$	118,032		$	—		$	1,341		$	119,373
Natural gas sales	—			4,346			—			36			4,382
Natural gas liquid sales	—			8,277			—			62			8,339
Royalty income	—			—			1,439			(1,439		)	—
Total revenues	—			130,655			1,439			—			132,094
Costs and expenses:
Lease operating expenses	—			15,367			—			—			15,367
Production and ad valorem taxes	—			8,202			93			—			8,295
Gathering and transportation	—			640			1			—			641
Depreciation, depletion and amortization	—			42,497			445			34			42,976
General and administrative expenses	2,399			4,814			9			(9		)	7,213
Asset retirement obligation accretion expense	—			134			—			—			134
Total costs and expenses	2,399			71,654			548			25			74,626
Income (loss) from operations	(2,399		)	59,001			891			(25		)	57,468
Other income (expense)
Interest income	1			—			—			—			1
Interest expense	(68		)	(1,419		)	(622		)	—			(2,109		)
Other income	—			1,047			—			—			1,047
Gain on derivative instruments, net	—			(1,881		)	—			—			(1,881		)
Total other income (expense), net	(67		)	(2,253		)	(622		)	—			(2,942		)
Income (loss) before income taxes	(2,466		)	56,748			269			(25		)	54,526
Provision for income taxes	20,063			—			—			—			20,063
Net income (loss)	$	(22,529	)	$	56,748		$	269		$	(25	)	$	34,463

Large Accelerated Filer

Accelerated Filer

Non-Accelerated Filer

Smaller Reporting Company