10-Q

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, 2018

OR

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. YesýNo¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files). YesýNo¨

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

Large Accelerated Filer	ý	Accelerated Filer	o
Non-Accelerated Filer	o	Smaller Reporting Company	o
		Emerging Growth Company	o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.   o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   Yes¨ Noý

As of November 2, 2018, 101,257,911 shares of the registrant’s common stock were outstanding.

DIAMONDBACK ENERGY, INC.

FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2018

TABLE OF CONTENTS

	Page
Glossary of Oil and Natural Gas Terms	ii
Glossary of Certain Other Terms	iv
Cautionary Statement Regarding Forward-Looking Statements	v
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)
Consolidated Balance Sheets	1
Consolidated Statements of Operations	2
Consolidated Statements of Stockholders’ Equity	3
Consolidated Statements of Cash Flows	4
Condensed Notes to Consolidated Financial Statements	6
Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operations	39
Item 3. Quantitative and Qualitative Disclosures about Market Risk	57
Item 4. Controls and Procedures	58
PART II. OTHER INFORMATION
Item 1. Legal Proceedings	59
Item 1A. Risk Factors	59
Item 6. Exhibits	60
Signatures	62

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a glossary of certain oil and gas terms that are used in this Quarterly Report on Form 10-Q (this “report”):

Basin	A large depression on the earth’s surface in which sediments accumulate.
Bbl	Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
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.
British Thermal Unit or Btu	The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
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.
Crude oil	Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
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.
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.
Horizontal wells	Wells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.
Mb/d	Thousand barrels per day.
Mcf	Thousand cubic feet of natural gas.
Mineral interests	The interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
MMBtu	Million British Thermal Units.
Net acres or net wells	The sum of the fractional working interest owned in gross acres.
Oil and natural gas properties	Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.
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.
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 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.
Reserves	The estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves are not assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
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.
Royalty interest	An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development.
Spacing	The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.

ii

Working interest An 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.

iii

GLOSSARY OF CERTAIN OTHER TERMS

The following is a glossary of certain other terms that are used in this report.

Company	Diamondback Energy, Inc., a Delaware corporation.
Equity Plan	The Company’s Equity Incentive Plan.
Exchange Act	The Securities Exchange Act of 1934, as amended.
GAAP	Accounting principles generally accepted in the United States.
General Partner	Viper Energy Partners GP LLC, a Delaware limited liability company and the General Partner of the Partnership.
NYMEX	New York Mercantile Exchange.
Partnership	Viper Energy Partners LP, a Delaware limited partnership.
Partnership Agreement	The first amended and restated agreement of limited partnership, dated June 23, 2014, entered into by the General Partner and Diamondback in connection with the closing of the Viper Offering.
Operating Company	Viper Energy Partners LLC, a Delaware limited liability company and a subsidiary of the Partnership.
SEC	United States Securities and Exchange Commission.
Securities Act	The Securities Act of 1933, as amended.
2024 Senior Notes	The Company’s 4.750% senior unsecured notes due 2024 in the aggregate principal amount of $500 million.
2025 Senior Notes	The Company’s 5.375% senior unsecured notes due 2025 in the aggregate principal amount of $500 million.
Senior Notes	The 2024 Senior Notes and the 2025 Senior Notes.
Viper LTIP	Viper Energy Partners LP Long Term Incentive Plan.
Viper Offering	The Partnerships’ initial public offering.
Wells Fargo	Wells Fargo Bank, National Association.

iv

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, and Section 21E of 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 report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed in this report and detailed under Part II, Item 1A. Risk Factors in this report and our Annual Report on Form 10–K for the year ended December 31, 2017 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;

• acquisitions, including our recent acquisition of certain leasehold acres and other assets from Ajax Resources, LLC and our pending acquisition of Energen Corporation discussed elsewhere in this report;

• 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 report or, if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities laws. 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 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.

v

Diamondback Energy, Inc. and Subsidiaries

Consolidated Balance Sheets

(Unaudited)

	September 30,			December 31,
	2018			2017
	(In thousands, except par values and share data)
Assets
Current assets:
Cash and cash equivalents	$	508,446		$	112,446
Accounts receivable:
Joint interest and other	81,955			73,038
Oil and natural gas sales	182,362			158,575
Inventories	14,815			9,108
Derivative instruments	—			531
Prepaid expenses and other	8,111			4,903
Total current assets	795,689			358,601
Property and equipment:
Oil and natural gas properties, full cost method of accounting ($4,283,629 and $4,105,865 excluded from amortization at September 30, 2018 and December 31, 2017, respectively)	10,818,378			9,232,694
Midstream assets	355,758			191,519
Other property, equipment and land	85,882			80,776
Accumulated depletion, depreciation, amortization and impairment	(2,545,412		)	(2,161,372		)
Net property and equipment	8,714,606			7,343,617
Funds held in escrow	62,034			6,304
Deferred tax asset	95,551			—
Investment in real estate, net	106,834			—
Other assets	31,859			62,463
Total assets	$	9,806,573		$	7,770,985
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	85,869		$	94,590
Accrued capital expenditures	292,700			221,256
Other accrued liabilities	143,792			92,512
Revenues and royalties payable	75,600			68,703
Derivative instruments	123,826			100,367
Total current liabilities	721,787			577,428
Long-term debt	2,332,359			1,477,347
Derivative instruments	5,931			6,303
Asset retirement obligations	23,897			20,122
Deferred income taxes	292,795			108,048
Other long-term liabilities	7			—
Total liabilities	3,376,776			2,189,248
Commitments and contingencies (Note 16)
Stockholders’ equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 98,673,563 issued and outstanding at September 30, 2018; 98,167,289 issued and outstanding at December 31, 2017	987			982
Additional paid-in capital	5,464,542			5,291,011
Retained earnings (accumulated deficit)	467,830			(37,133		)
Total Diamondback Energy, Inc. stockholders’ equity	5,933,359			5,254,860
Non-controlling interest	496,438			326,877
Total equity	6,429,797			5,581,737
Total liabilities and equity	$	9,806,573		$	7,770,985

See accompanying notes to consolidated financial statements.

1

Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(In thousands, except per share amounts)
Revenues:
Oil sales	$	454,644		$	259,049		$	1,334,349		$	704,007
Natural gas sales	14,814			14,922			40,557			37,537
Natural gas liquid sales	57,610			25,266			133,858			57,625
Lease bonus	1,322			322			2,250			2,507
Midstream services	7,280			1,694			26,658			4,241
Other operating income	2,359			—			6,825			—
Total revenues	538,029			301,253			1,544,497			805,917
Costs and expenses:
Lease operating expenses	49,111			32,498			129,103			88,113
Production and ad valorem taxes	33,536			18,371			93,042			49,975
Gathering and transportation	6,976			3,476			18,074			9,110
Midstream services	19,725			4,445			48,515			7,127
Depreciation, depletion and amortization	146,318			87,579			391,401			221,681
General and administrative expenses (including non-cash equity-based compensation, net of capitalized amounts, of $5,350 and $6,187 for the three months ended September 30, 2018 and 2017, respectively, and $18,451 and $19,418 for the nine months ended September 30, 2018 and 2017, respectively)	14,185			11,888			45,039			37,524
Asset retirement obligation accretion	387			357			1,107			1,030
Other operating expense	940			—			2,416			—
Total costs and expenses	271,178			158,614			728,697			414,560
Income from operations	266,851			142,639			815,800			391,357
Other income (expense):
Interest expense, net	(18,548		)	(9,192		)	(49,345		)	(29,662		)
Other income, net	1,962			3			89,170			9,472
Gain (loss) on derivative instruments, net	(48,373		)	(50,645		)	(139,305		)	20,376
Gain (loss) on revaluation of investment	(199		)	—			5,165			—
Total other income (expense), net	(65,158		)	(59,834		)	(94,315		)	186
Income before income taxes	201,693			82,805			721,485			391,543
Provision for income taxes	42,276			857			82,750			4,393
Net income	159,417			81,948			638,735			387,150
Net income attributable to non-controlling interest	2,363			8,924			99,723			19,448
Net income attributable to Diamondback Energy, Inc.	$	157,054		$	73,024		$	539,012		$	367,702
Earnings per common share:
Basic	$	1.59		$	0.74		$	5.47		$	3.81
Diluted	$	1.59		$	0.74		$	5.45		$	3.80
Weighted average common shares outstanding:
Basic	98,638			98,144			98,603			96,491
Diluted	98,818			98,369			98,820			96,752
Dividends declared per share	$	0.125		$	—		$	0.375		$	—

See accompanying notes to consolidated financial statements.

2

Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Stockholders’ Equity

(Unaudited)

	Common Stock			Additional Paid-in Capital			Retained Earnings (Accumulated Deficit)			Non-Controlling Interest			Total
	Shares	Amount
	(In thousands)
Balance December 31, 2016	90,144	$	901	$	4,215,955		$	(519,394	)	$	320,830		$	4,018,292
Net proceeds from issuance of common units - Viper Energy Partners LP		—		—			—			369,896			369,896
Unit-based compensation		—		—			—			2,039			2,039
Common units issued for acquisition		—		—			—			3,050			3,050
Stock-based compensation		—		23,790			—			—			23,790
Distribution to non-controlling interest		—		—			—			(27,640		)	(27,640		)
Common shares issued in public offering, net of offering costs		—		14			—			—			14
Common shares issued for acquisition	7,686	77		809,096			—			—			809,173
Exercise of stock options and vesting of restricted stock units	337	4		355			—			—			359
Net income		—		—			367,702			19,448			387,150
Balance September 30, 2017	98,167	$	982	$	5,049,210		$	(151,692	)	$	687,623		$	5,586,123
Balance December 31, 2017	98,167	$	982	$	5,291,011		$	(37,133	)	$	326,877		$	5,581,737
Impact of adoption of ASU 2016-01, net of tax		—		—			(9,393		)	(6,671		)	(16,064		)
Net proceeds from issuance of common units - Viper Energy Partners LP		—		—			—			303,137			303,137
Unit-based compensation		—		—			—			2,166			2,166
Stock-based compensation		—		23,613			—			—			23,613
Distribution to non-controlling interest		—		—			—			(68,801		)	(68,801		)
Dividend paid		—		—			(24,656		)	—			(24,656		)
Exercise of stock options and vesting of restricted stock units	506	5		(5		)	—			140			140
Change in ownership of consolidated subsidiaries, net		—		149,923			—			(160,133		)	(10,210		)
Net income		—		—			539,012			99,723			638,735
Balance September 30, 2018	98,674	$	987	$	5,464,542		$	467,830		$	496,438		$	6,429,797

See accompanying notes to consolidated financial statements.

3

Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)

	Nine Months Ended September 30,
	2018			2017
	(In thousands)
Cash flows from operating activities:
Net income	$	638,735		$	387,150
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for deferred income taxes	81,573			3,313
Asset retirement obligation accretion	1,107			1,030
Depreciation, depletion and amortization	391,401			221,681
Amortization of debt issuance costs	2,291			2,828
Change in fair value of derivative instruments	23,618			(9,365		)
Income from equity investment	—			(309		)
Gain on revaluation of investment	(5,165		)	—
Equity-based compensation expense	18,451			19,418
Loss (gain) on sale of assets, net	3,071			(386		)
Changes in operating assets and liabilities:
Accounts receivable	(21,611		)	(23,422		)
Accounts receivable-related party	—			283
Restricted cash	—			500
Inventories	(14,196		)	(2,700		)
Prepaid expenses and other	(5,813		)	(9,242		)
Accounts payable and accrued liabilities	18,383			18,305
Accounts payable and accrued liabilities-related party	—			(2		)
Accrued interest	12,663			(1,738		)
Income tax payable	311			1,017
Revenues and royalties payable	6,897			29,657
Net cash provided by operating activities	1,151,716			638,018
Cash flows from investing activities:
Additions to oil and natural gas properties	(1,010,325		)	(531,489		)
Additions to midstream assets	(129,820		)	(22,491		)
Purchase of other property, equipment and land	(2,049		)	(21,534		)
Acquisition of leasehold interests	(185,658		)	(1,892,864		)
Acquisition of mineral interests	(335,574		)	(370,855		)
Acquisition of midstream assets	—			(50,279		)
Proceeds from sale of assets	6,771			3,584
Investment in real estate	(110,654		)	—
Funds held in escrow	(51,045		)	121,391
Equity investments	(604		)	(188		)
Net cash used in investing activities	(1,818,958		)	(2,764,725		)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	1,027,500			533,000
Repayment under credit facility	(1,221,500		)	(383,500		)
Proceeds from senior notes	1,062,000			—
Debt issuance costs	(14,578		)	(1,714		)
Public offering costs	(2,636		)	(510		)
Proceeds from public offerings	305,773			370,344
Proceeds from exercise of unit options	140			—
Proceeds from exercise of stock options	—			358
Dividends to stockholders	(24,656		)	—

4

Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows - Continued

(Unaudited)

	Nine Months Ended September 30,
	2018			2017
Distributions to non-controlling interest	(68,801		)	(27,640		)
Net cash provided by financing activities	1,063,242			490,338
Net increase (decrease) in cash and cash equivalents	396,000			(1,636,369		)
Cash and cash equivalents at beginning of period	112,446			1,666,574
Cash and cash equivalents at end of period	$	508,446		$	30,205
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest	$	51,658		$	28,702
Supplemental disclosure of non-cash transactions:
Change in accrued capital expenditures	$	71,444		$	129,105
Capitalized stock-based compensation	$	7,328		$	6,411
Common stock issued for oil and natural gas properties	$	—		$	809,173
Asset retirement obligations acquired	$	270		$	2,411

See accompanying notes to consolidated financial statements.

5

Diamondback Energy, Inc. and Subsidiaries

Condensed 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.

The wholly-owned subsidiaries of Diamondback, as of September 30, 2018, 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, Rattler Midstream LLC (formerly known as White Fang Energy LLC), a Delaware limited liability company, and Tall City Towers LLC, a Delaware limited liability company. The consolidated subsidiaries include these wholly-owned subsidiaries as well as Viper Energy Partners LP, a Delaware limited partnership (the “Partnership”), and the Partnership’s wholly-owned subsidiary Viper Energy Partners LLC, a Delaware limited liability company (the “Operating 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, 2018, the Company owned approximately 59% of the Partnership’s total units outstanding. 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 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 GAAP have been omitted pursuant to such rules and regulations, although the Company believes the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10–Q should be read in conjunction with the Company’s most recent Annual Report on Form 10–K for the fiscal year ended December 31, 2017, 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.

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

6

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Investments

The Partnership has an equity interest in a limited partnership that is so minor that the Partnership has no influence over the limited partnership’s operating and financial policies. This interest was acquired during the year ended December 31, 2014 and is accounted for under the cost method. Effective January 1, 2018, the Partnership adopted Accounting Standards Update 2016-01 which requires the Partnership to measure this investment at fair value which resulted in a downward adjustment of $18.7 million to record the impact of this adoption. For the three months and nine months endedSeptember 30, 2018, the Partnership recorded a gain (loss) of $(0.2) million and $5.2 million, respectively. The Partnership’s investment balance as of September 30, 2018 was $20.2 million, which is included in other assets in the accompanying consolidated balance sheets.

Funds Held in Escrow

The funds held in escrow represent amounts in deposit to fund acquisitions. During the nine months ended September 30, 2018, there was $62.0 million in deposit to be applied to the purchase price for the acquisition of leasehold interests and related assets from Ajax Resources, LLC that closed on October 31, 2018. See Note 4— Acquisitions for information relating to this acquisition. During the nine months ended September 30, 2017, there was $6.3 million in deposit to fund other acquisitions which closed in the first quarter of 2018.

New Accounting Pronouncements

Recently Adopted Pronouncements

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”. This standard included a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. Among other things, the standard also eliminated industry-specific revenue guidance, required enhanced disclosures about revenue, provided guidance for transactions that were not previously addressed comprehensively and improved guidance for multiple-element arrangements. The Company adopted this Accounting Standards Update effective January 1, 2018 using the modified retrospective approach. The Company utilized a bottom-up approach to analyze the impact of the new standard by reviewing its current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard to its revenue contracts and the impact of adopting this standards update on its total revenues, operating income and its consolidated balance sheet. The adoption of this standard did not result in a cumulative-effect adjustment.

In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. This update applies to any entity that holds financial assets or owes financial liabilities. This update requires equity investments (except for those accounted for under the equity method or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. The Partnership adopted this standard effective January 1, 2018 by means of a negative cumulative-effect adjustment totaling $18.7 million.

In August 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-15, “Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments”. This update apples to all entities that are required to present a statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; including bank-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The Company adopted this update effective January 1, 2018 using the retrospective transition method. Adoption of this standard did not have an effect on the presentation on the Statement of Cash Flows.

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

In November 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-18, “Statement of Cash Flows - Restricted Cash”. This update affects entities that have restricted cash or restricted cash equivalents. The Company adopted this update effective January 1, 2018. The adoption of this update did not have an effect on the presentation on the Statement of Cash Flows.

In January 2017, the Financial Accounting Standards Board issued Accounting Standards Update 2017-01, “Business Combinations - Clarifying the Definition of a Business”. This update apples to all entities that must determine whether they acquired or sold a business. This update provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The Company adopted this update prospectively effective January 1, 2018. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.

Accounting Pronouncements Not Yet Adopted

In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Company believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases. The Company is still evaluating the impact of this standard.

In January 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-01, “Leases - Land Easement Practical Expedient for Transition to Topic 842”. This update applies to any entity that holds land easements. The update allows entities to adopt a practical expedient to not evaluate existing or expired land easements under Topic 842 that were not previously accounted for as leases under the current leases guidance. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. The Company believes the adoption of this update will not have an impact on its financial position, results of operations or liquidity.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-10, “Codification Improvements to Topic 842, Leases”. This update provides clarification and corrects unintended application of certain sections in the new lease guidance. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases. The Company is still evaluating the impact of this standard.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-11, “Lease (Topic 842): Targeted Improvements”. This update provides another transition method of allowing entities to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases. The Company is still evaluating the impact of this standard.

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company does not believe the adoption of this standard will have a material impact on the Company’s consolidated financial statements since the Company does not have a history of credit losses.

In June 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-07, “Stock Compensation - Improvements to Nonemployee Share-Based Payment Accounting”. This update applies the existing employee guidance to nonemployee share-based transactions, with the exception of specific guidance related to the attribution of compensation cost. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-09, “Codification Improvements”. This update provides clarification and corrects unintended application of the guidance in various sections. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

In August 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-13, “Fair Value Measurement (Topic 820) - Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement”. This update modifies the fair value measurement disclosure requirements specifically related to Level 3 fair value measurements and transfers between levels. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied prospectively. The Company is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

In August 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-15, “Intangibles - Goodwill and Other - Internal - Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract”. This update requires the capitalization of implementation costs incurred in a hosting arrangement that is a service contract for internal-use software. Training and certain data conversion costs cannot be capitalized. The entity is required to expense the capitalized implementation costs over the term of the hosting agreement. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update should be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. The Company believes the adoption of this update will not have an impact on its financial position, results of operations or liquidity.

3.    REVENUE FROM CONTRACTS WITH CUSTOMERS

Revenue from Contracts with Customers

Sales of oil, natural gas and natural gas liquids are recognized at the point control of the product is transferred to the customer. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, the quality of the oil or natural gas and the prevailing supply and demand conditions. As a result, the price of the oil, natural gas and natural gas liquids fluctuates to remain competitive with other available oil, natural gas and natural gas liquids supplies.

Oil sales

The Company’s oil sales contracts are generally structured where it delivers oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, the Company or a third party transports the product to the delivery point and receives a specified index price from the purchaser with no deduction. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Oil revenues are recorded net of any third-party transportation fees and other applicable differentials in the Company’s consolidated statements of operations.

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Natural gas and natural gas liquids sales

Under the Company’s natural gas processing contracts, it delivers natural gas to a midstream processing entity at the wellhead, battery facilities or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of natural gas liquids and residue gas. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For those contracts where the Company has concluded it is the principal and the ultimate third party is its customer, the Company recognizes revenue on a gross basis, with transportation, gathering, processing, treating and compression fees presented as an expense in its consolidated statements of operations.

In certain natural gas processing agreements, the Company may elect to take its residue gas and/or natural gas liquids in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing, treating and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing, treating and compression expense in its consolidated statements of operations.

Midstream Revenue

Substantially all revenues from gathering, compression, water handling, disposal and treatment operations are derived from intersegment transactions for services Rattler Midstream LLC (“Rattler”) provides to exploration and production operations. The portion of such fees shown in the Company’s consolidated financial statements represent amounts charged to interest owners in the Company’s operated wells, as well as fees charged to other third parties for water handling and treatment services provided by Rattler or usage of Rattler’s gathering and compression systems. For gathering and compression revenue, Rattler satisfies its performance obligations and recognizes revenue when low pressure volumes are delivered to a specified delivery point. Revenue is recognized based on the per MMbtu gathering fee or a per barrel gathering fee charged by Rattler in accordance with the gathering and compression agreement. For water handling and treatment revenue, Rattler satisfies its performance obligations and recognizes revenue when the fresh water volumes have been delivered to the fracwater meter for a specified well pad and the wastewater volumes have been metered downstream of the Company’s facilities. For services contracted through third party providers, Rattler’s performance obligation is satisfied when the service performed by the third party provider has been completed. Revenue is recognized based on the per barrel fresh water delivery or a wastewater gathering and disposal fee charged by Rattler in accordance with the water services agreement.

Transaction price allocated to remaining performance obligations

The Company’s upstream product sales contracts do not originate until production occurs and, therefore, are not considered to exist beyond each days’ production. Therefore, there are no remaining performance obligation under any of our product sales contracts.

The majority of the Company’s midstream revenue agreements have a term greater than one year, and as such Rattler LLC has utilized the practical expedient in ASC 606, which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under its revenue agreements, each delivery generally represents a separate performance obligation; therefore, future volumes delivered are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

The remainder of the Company’s midstream revenue agreements, which relate to agreements with third parties, are short-term in nature with a term of one year or less. Rattler LLC has utilized an additional practical expedient in ASC 606 which exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of an agreement that has an original expected duration of one year or less.

10

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Contract balances

Under the Company’s product sales contracts, it has the right to invoice its customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606.

Prior-period performance obligations

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the three months ended September 30, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Company believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the revenue related to expected sales volumes and prices for those properties are estimated and recorded.

4.    ACQUISITIONS

Tall City Towers LLC

On January 31, 2018, Tall City Towers LLC, a subsidiary of the Company, completed its acquisition of the Fasken Center office buildings in Midland, TX where the Company’s corporate offices are located for a net purchase price of $109.7 million.

Pending Merger with Energen Corporation

On August 14, 2018, the Company entered into a definitive merger agreement providing for the Company’s acquisition of Energen Corporation (“Energen”) in an all-stock transaction valued at approximately $9.2 billion including Energen’s net debt of $831.0 million as of June 30, 2018 (the “Pending Merger”). The addition of Energen’s assets will increase the Company’s assets to: (i) over 273,000 net Tier One acres in the Permian Basin, an increase of 57% from its current Tier One acreage of approximately 174,000 net acres, (ii) approximately 7,200 estimated total net horizontal Permian locations, an increase of over 120% from its current estimated net locations and (iii) approximately 394,000 net acres across the Midland and Delaware Basins, an increase of 82% from our approximately 216,000 net acres as September 30, 2018, in each case after giving effect to the Company’s recently completed Ajax Resources, LLC, ExL Management, LLC and EnergyQuest II LLC acquisitions described below.

The completion of the Pending Merger is subject to the satisfaction or waiver of certain customary mutual closing conditions. The Company’s registration statement on Form S-4 relating to the Pending Merger was declared effective by the SEC on October 24, 2018, and the Pending Merger is expected to be completed at the end of November of 2018.

11

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Under the terms of the merger agreement relating to the Pending Merger, the Company has agreed to assume Energen’s outstanding debt, which as of June 30, 2018 was approximately $831.0 million. This amount consists of $301.0 million of borrowings under Energen’s existing credit facility, $400.0 million aggregate principal amount of 4.625% Notes, due September 1, 2021, $20.0 million aggregate principal amount of 7.32% Medium-term Notes, Series A, due July 28, 2022, $10.0 million aggregate principal amount of 7.35% Medium-term Notes, Series A, due July 28, 2027, and $100.0 million aggregate principal amount of 7.125% Medium-term Notes, Series B, due February 15, 2028 (collectively, the “Energen Notes”). The Company may choose to refinance the Energen credit facility and the Company’s credit facility into a combined credit facility in connection with the consummation of the Pending Merger or the Company may choose to repay the outstanding borrowings under the Energen credit facility using cash on hand or borrowings under the Company’s revolving credit facility. With respect to the outstanding Energen Notes, the Company may take no action, or the Company may seek to amend the terms of the indenture governing the Energen Notes or engage in liability management transactions with respect to, repay or refinance any or all of the Energen Notes, with any repayment coming from cash on hand or borrowings under the Company’s revolving credit facility.

Ajax Resources, LLC

On July 22, 2018, the Company entered into a definitive purchase agreement to acquire all leasehold interests and related assets of Ajax Resources, LLC, which include approximately 25,493 net leasehold acres in the Northern Midland Basin, for $900.0 million in cash, subject to certain adjustments, and approximately 2.6 million shares of the Company’s common stock (the “Ajax acquisition”). This transaction closed on October 31, 2018 and was effective as of July 1, 2018. The cash portion of this transaction was funded through a combination of cash on hand, proceeds from the sale of mineral interests to the Partnership (described below), borrowing under the Company’s revolving credit facility and a portion of the proceeds from the Company’s September 2018 senior note offering. See Note 9—Debt for information relating to this offering.

In connection with the closing of the Ajax acquisition on October 31, 2018, the Company entered into a registration rights agreement with Ajax Resources, LLC and certain other holders of the Company’s common stock. Pursuant to this agreement, the Company agreed to (i) file with the SEC a shelf registration statement to facilitate the resale of common stock issued in the Ajax acquisition and any shares of common stock that may be issued or distributed in respect of such shares upon certain events and (ii) use its reasonable best efforts to cause such registration statement to become effective by November 30, 2018. Pursuant to this registration rights agreement, the Company also agreed to provide certain demand and piggyback registration rights to such holders.

ExL Petroleum Management, LLC and EnergyQuest II LLC

On September 21, 2018, the Company entered into two definitive purchase agreements to acquire leasehold interests and related assets, one with ExL Petroleum Management, LLC and ExL Petroleum Operating, Inc. and one with EnergyQuest II LLC, for an aggregate of approximately 3,646 net leasehold acres in the Northern Midland Basin for a total of $312.5 million in cash, subject to certain adjustments. These transactions closed on October 31, 2018 and were effective as of August 1, 2018. These transactions were funded through a combination of cash on hand, proceeds from the sale of assets to the Partnership (described below) and borrowing under the Company’s revolving credit facility.

Drop-down Transaction

On August 15, 2018, the Company completed a transaction to sell to the Partnership mineral interests underlying 32,424 gross (1,696 net royalty) acres primarily in Pecos County, Texas, in the Permian Basin, approximately 80% of which are operated by the Company, for $175.0 million (the “Drop-down Transaction”).

12

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Oil and Natural Gas Properties

On February 28, 2017, the Company completed its acquisition of certain oil and natural gas properties, midstream assets and other related assets in the Delaware Basin for an aggregate purchase price consisting of $1.74 billion in cash and 7.69 million shares of the Company’s common stock, of which approximately 1.15 million shares were placed in an indemnity escrow. This transaction included the acquisition of (i) approximately 100,306 gross (80,339 net) acres primarily in Pecos and Reeves counties for approximately $2.5 billion and (ii) midstream assets for approximately $47.6 million. The Company used the net proceeds from its December 2016 equity offering, net proceeds from its December 2016 debt offering, cash on hand and other financing sources to fund the cash portion of the purchase price for this acquisition.

The following represents the fair value of the assets and liabilities assumed on the acquisition date. The aggregate consideration transferred was $2.5 billion, resulting in no goodwill or bargain purchase gain.

	(in thousands)
Proved oil and natural gas properties	$	386,308
Unevaluated oil and natural gas properties	2,122,597
Midstream assets	47,432
Prepaid capital costs	3,460
Oil inventory	839
Equipment	163
Revenues and royalties payable	(9,650		)
Asset retirement obligations	(1,550		)
Total fair value of net assets	$	2,549,599

The Company included in its consolidated statements of operations revenues of $84.3 million and direct operating expenses of $16.0 million for the period from February 28, 2017 to September 30, 2017 due to the acquisition.

Pro Forma Financial Information

The following unaudited summary pro forma consolidated statement of operations data of Diamondback for the three months and nine months endedSeptember 30, 2017 have been prepared to give effect to the February 28, 2017 acquisition as if it had occurred on January 1, 2016. The pro forma data are not necessarily indicative of financial results that would have been attained had the acquisitions occurred on January 1, 2016. The pro forma data also necessarily exclude various operation expenses related to the properties and the financial statements should not be viewed as indicative of operations in future periods.

	Three Months Ended September 30, 2017		Nine Months Ended September 30, 2017
	(in thousands, except per share amounts)
Revenues	$	301,253	$	828,846
Income from operations	142,639		405,699
Net income	81,948		382,044
Basic earnings per common share	0.74		3.96
Diluted earnings per common share	0.74		3.95

5.    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 and the Eagle Ford Shale. Viper Energy Partners GP LLC, a fully-consolidated subsidiary of Diamondback, serves as the general partner of the Partnership. As of September 30, 2018, the Company owned approximately 59% of the Partnership’s total units outstanding.

Recapitalization,Tax Status Election and Related Transactions by Viper

In March 2018, the Partnership announced that the Board of Directors of the General Partner had unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election. In connection with making this election, on May 9, 2018 the Partnership (i) amended and restated its First Amended and Restated Partnership Agreement, (ii) amended and restated the First Amended and Restated Limited Liability Company Agreement of the Operating Company, (iii) amended and restated its existing registration rights agreement with the Company and (iv) entered into an exchange agreement with the Company, the General Partner and the Operating Company. Simultaneously with the effectiveness of these agreements, the Company delivered and assigned to the Partnership the 73,150,000 common units the Company owned in exchange

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

for (i) 73,150,000 of the Partnership’s newly-issued Class B units and (ii) 73,150,000 newly-issued units of the Operating Company pursuant to the terms of a Recapitalization Agreement dated March 28, 2018, as amended as of May 9, 2018 (the “Recapitalization Agreement”). Immediately following that exchange, the Partnership continued to be the managing member of the Operating Company, with sole control of its operations, and owned approximately 36% of the outstanding units issued by the Operating Company, and the Company owned the remaining approximately 64% of the outstanding units issued by the Operating Company. Upon completion of the Partnership’s July 2018 offering of units, it owned approximately 41% of the outstanding units issued by the Operating Company and the Company owned the remaining approximately 59%. The Operating Company units and the Partnership’s Class B units owned by the Company are exchangeable from time to time for the Partnership’s common units (that is, one Operating Company unit and one Partnership Class B unit, together, will be exchangeable for one Partnership common unit).

On May 10, 2018, the change in the Partnership’s income tax status became effective. On that date, pursuant to the terms of the Recapitalization Agreement, (i) the General Partner made a cash capital contribution of $1.0 million to the Partnership in respect of its general partner interest and (ii) the Company made a cash capital contribution of $1.0 million to the Partnership in respect of the Class B units. The Company, as the holder of the Class B units, and the General Partner, as the holder of the general partner interest, are entitled to receive an 8% annual distribution on the outstanding amount of these capital contributions, payable quarterly, as a return on this invested capital. On May 10, 2018, the Company also exchanged 731,500 Class B units and 731,500 units in the Operating Company for 731,500 common units of the Partnership and a cash amount of $10,000 representing a proportionate return of the $1.0 million invested capital in respect of the Class B units. The General Partner continues to serve as the Partnership’s general partner and the Company continues to control the Partnership. After the effectiveness of the tax status election and the completion of related transactions, the Partnership’s minerals business continues to be conducted through the Operating Company, which continues to be taxed as a partnership for federal and state income tax purposes. This structure is anticipated to provide significant benefits to the Partnership’s business, including operational effectiveness, acquisition and disposition transactional planning flexibility and income tax efficiency. For additional information regarding the tax status election and related transactions, please refer to the Partnership’s Definitive Information Statement on Schedule 14C filed with the SEC on April 17, 2018 and the Partnership’s Current Report on Form 8-K filed with the SEC on May 15, 2018.

Partnership Agreement

The second amended and restated agreement of limited partnership, dated as of May 9, 2018, as amended as of May 10, 2018 (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. For the three months ended September 30, 2018 and 2017, the General Partner allocated $0.6 million to the Partnership. For the nine months ended September 30, 2018 and 2017, the General Partner allocated $1.8 million to the Partnership.

Tax Sharing

In connection with the closing of the Viper Offering, the Partnership entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to which the Partnership agreed to 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 agreed to 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. For the three months and nine months endedSeptember 30, 2018, the Partnership accrued state income tax expense (benefit) of $(0.1) million and $0.1 million, respectively, for its share of Texas margin tax for which the Partnership’s results are included in a combined tax return filed by Diamondback.

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Other Agreements

See Note 12—Related Party Transactions for information regarding the advisory services agreement the Partnership and the General Partner entered into with Wexford Capital LP (“Wexford”).

The Partnership has entered into a secured revolving credit facility with Wells Fargo, as administrative agent sole book runner and lead arranger. See Note 9—Debt for a description of this credit facility.

6.    PROPERTY AND EQUIPMENT

Property and equipment includes the following:

	September 30,			December 31,
	2018			2017
	(in thousands)
Oil and natural gas properties:
Subject to depletion	$	6,534,749		$	5,126,829
Not subject to depletion	4,283,629			4,105,865
Gross oil and natural gas properties	10,818,378			9,232,694
Accumulated depletion	(1,375,163		)	(1,009,893		)
Accumulated impairment	(1,143,498		)	(1,143,498		)
Oil and natural gas properties, net	8,299,717			7,079,303
Midstream assets	355,758			191,519
Other property, equipment and land	85,882			80,776
Accumulated depreciation	(26,751		)	(7,981		)
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment	$	8,714,606		$	7,343,617
Balance of costs not subject to depletion:
Incurred in 2018	$	589,352
Incurred in 2017	2,563,902
Incurred in 2016	714,467
Incurred in 2015	234,948
Incurred in 2014	180,960
Total not subject to depletion	$	4,283,629

15

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. 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. Costs, including related employee costs, associated with production and operation of the properties are charged to expense as incurred. All other internal costs not directly associated with exploration and development activities are charged to expense as they are incurred. Capitalized internal costs were approximately $6.7 million and $5.7 million for the three months ended September 30, 2018 and 2017, respectively, and $20.4 million and $15.9 million for the nine months ended September 30, 2018 and 2017, 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. Acquisition costs not currently being amortized are primarily related to unproved acreage that the Company plans to prove up through drilling. The Company has no plans to let any acreage expire. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas.

Under this method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions or financial derivatives, if any, that hedge the Company’s oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required.

At September 30, 2018, there was $50.1 million in exploration costs and development costs and $42.0 million in capitalized interest that was not subject to depletion. At December 31, 2017, there were $26.0 million in exploration costs and development costs and $22.1 million in capitalized interest that was not subject to depletion.

7.    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,
	2018			2017
	(in thousands)
Asset retirement obligations, beginning of period	$	21,285		$	17,422
Additional liabilities incurred	2,229			1,196
Liabilities acquired	270			2,411
Liabilities settled	(1,474		)	(689		)
Accretion expense	1,107			1,030
Revisions in estimated liabilities	568			4
Asset retirement obligations, end of period	23,985			21,374
Less current portion	88			1,392
Asset retirement obligations - long-term	$	23,897		$	19,982

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. The current portion of the asset retirement obligation liability is included in other accrued liabilities in the Company’s consolidated balance sheets.

16

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

8.    EQUITY METHOD INVESTMENTS

In October 2014, the Company obtained a 25% interest in HMW Fluid Management LLC (“HMW LLC”), which 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. On June 30, 2018, HMW LLC’s operating agreement was amended effective January 1, 2018. As a result of the amendment, the Company will no longer recognize an equity investment in HMW LLC but will instead consolidate its interests in the net assets of HMW LLC. In exchange for the Company’s 25% investment, the Company received a 50% undivided ownership interest in two of the four salt water disposal wells and associated assets previously owned by HMW LLC. The Company’s basis in the assets is equivalent to its basis in the equity investment in HMW LLC. During the nine months ended September 30, 2017, the Company invested $0.2 million in this entity and recorded $0.3 million, which is the Company’s share of HMW LLC’s net income, bringing its total investment to $6.8 million at September 30, 2017.

9.    DEBT

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

	September 30,			December 31,
	2018			2017
	(in thousands)
4.750 % Senior Notes due 2024	$	1,250,000		$	500,000
5.375 % Senior Notes due 2025	800,000			500,000
Unamortized debt issuance costs	(25,038		)	(13,153		)
Unamortized premium costs	10,897			—
Revolving credit facility	—			397,000
Partnership revolving credit facility	296,500			93,500
Total long-term debt	$	2,332,359		$	1,477,347

2024 Senior Notes

On October 28, 2016, the Company issued $500.0 million in aggregate principal amount of 4.750% Senior Notes due 2024 (the “2024 Senior Notes”). The 2024 Senior Notes bear interest at a rate of 4.750% per annum, payable semi-annually, in arrears on May 1 and November 1 of each year, commencing on May 1, 2017 and will mature on November 1, 2024. All of the Company’s existing and future restricted subsidiaries that guarantee its revolving credit facility or certain other debt guarantee the 2024 Senior Notes; provided, however, that the 2024 Senior Notes are not guaranteed by the Partnership, the General Partner, Viper Energy Partners LLC or Rattler Midstream LLC, and will not be guaranteed by any of the Company’s future unrestricted subsidiaries.

On September 25, 2018, the Company issued $750.0 million aggregate principal amount of new 4.750% Senior Notes due 2024 (the “New 2024 Notes”) as additional notes under, and subject to the terms of, the 2024 Indenture. The New 2024 Notes were issued in a transaction exempt from the registration requirements under the Securities Act. The Company received approximately $740.7 million in net proceeds, after deducting the initial purchasers’ discount and its estimated offering expenses, but disregarding accrued interest, from the issuance of the New 2024 Notes. The Company used a portion of the net proceeds from the issuance of the New 2024 Notes to repay the outstanding borrowings under its revolving credit facility and intends to use the balance for general corporate purposes, including funding a portion of the cash consideration for the acquisition of assets from Ajax Resources, LLC.

17

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

The 2024 Senior Notes were issued under, and are governed by, an indenture among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented (the “2024 Indenture”). The 2024 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 capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted 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 natural gas business and designate certain of the Company’s subsidiaries as unrestricted subsidiaries.

The Company may on any one or more occasions redeem some or all of the 2024 Senior Notes at any time on or after November 1, 2019 at the redemption prices (expressed as percentages of principal amount) of 103.563% for the 12-month period beginning on November 1, 2019, 102.375% for the 12-month period beginning on November 1, 2020, 101.188% for the 12-month period beginning on November 1, 2021 and 100.000% beginning on November 1, 2022 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to November 1, 2019, the Company may on any one or more occasions redeem all or a portion of the 2024 Senior Notes (including the New 2024 Notes) at a price equal to 100% of the principal amount of the 2024 Senior Notes (including the New 2024 Notes) plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to November 1, 2019, the Company may on any one or more occasions redeem the 2024 Senior Notes (including the New 2024 Notes) in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2024 Senior Notes (including the New 2024 Notes) issued prior to such date at a redemption price of 104.750%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings.

2025 Senior Notes

On December 20, 2016, the Company issued $500.0 million in aggregate principal amount of 5.375% Senior Notes due 2025 (the “2025 Senior Notes”). The 2025 Senior Notes bear interest at a rate of 5.375% per annum, payable semi-annually, in arrears on May 31 and November 30 of each year, commencing on May 31, 2017 and will mature on May 31, 2025. All of the Company’s existing and future restricted subsidiaries that guarantee its revolving credit facility or certain other debt guarantee the 2025 Senior Notes, provided, however, that the 2025 Senior Notes are not guaranteed by the Partnership, the General Partner, Viper Energy Partners LLC or Rattler Midstream LLC, and will not be guaranteed by any of the Company’s future unrestricted subsidiaries.

On January 29, 2018, the Company issued $300.0 million aggregate principal amount of new 5.375% Senior Notes due 2025 (the “New 2025 Notes”) as additional notes under, and subject to the terms of, the 2025 Indenture. The New 2025 Notes were issued in a transaction exempt from the registration requirements under the Securities Act. The Company received approximately $308.4 million in net proceeds, after deducting the initial purchaser’s discount and its estimated offering expenses, but disregarding accrued interest, from the issuance of the New 2025 Notes. The Company used the net proceeds from the issuance of the New 2025 Notes to repay a portion of the outstanding borrowings under its revolving credit facility.

The 2025 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 capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting the Company’s restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of the Company’s assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and natural gas business and designate certain of the Company’s subsidiaries as unrestricted subsidiaries.

18

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

The Company may on any one or more occasions redeem some or all of the 2025 Senior Notes (including the New 2025 Notes) at any time on or after May 31, 2020 at the redemption prices (expressed as percentages of principal amount) of 104.031% for the 12-month period beginning on May 31, 2020, 102.688% for the 12-month period beginning on May 31, 2021, 101.344% for the 12-month period beginning on May 31, 2022 and 100.000% beginning on May 31, 2023 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to May 31, 2020, the Company may on any one or more occasions redeem all or a portion of the 2025 Senior Notes (including the New 2025 Notes) at a price equal to 100% of the principal amount of the 2025 Senior Notes (including the New 2025 Notes) plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to May 31, 2020, the Company may on any one or more occasions redeem the 2025 Senior Notes (including the New 2025 Notes) in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2025 Senior Notes (including the New 2025 Notes) issued prior to such date at a redemption price of 105.375%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings.

The Company’s Credit Facility

The Company and Diamondback O&G LLC, as borrower, entered into the second amended and restated credit agreement, dated November 1, 2013, as amended, with a syndicate of banks, including Wells Fargo, as administrative agent, and its affiliate Wells Fargo Securities, LLC, as sole book runner and lead arranger. The credit agreement provides for a revolving credit facility in the maximum credit amount of $5.0 billion, subject to a borrowing base based on the Company’s oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be redetermined, under certain circumstances, annually with an effective date of May 1st, and, under certain circumstances, semi-annually with effective dates of May 1st and November 1st. In addition, the Company and Wells Fargo may each request up to two interim redeterminations of the borrowing base during any 12-month period. As of September 30, 2018, the borrowing base was set at $2.0 billion, the Company had elected a commitment amount of $1.0 billion and the Company had no outstanding borrowings under the revolving credit facility and $1.0 billion available for future borrowings under its revolving credit facility. On October 26, 2018, the credit agreement was amended to increase the borrowing base to $2.5 billion, which was increased further to $2.65 billion on November 6, 2018 following the closing of the Company’s acquisition of assets from Ajax Resources, LLC and satisfaction of certain other conditions. The Company also elected to increase the commitment amount from $1.0 billion to $2.0 billion effective October 26, 2018. In addition, this amendment increased the Company’s flexibility to make restricted payments and redeem senior unsecured notes.

Diamondback O&G LLC is the borrower under the credit agreement. As of December 31, 2017, the credit agreement is guaranteed by the Company, Diamondback E&P LLC and Rattler Midstream LLC (formerly known as White Fang Energy LLC) and will also be guaranteed by any of the Company’s future subsidiaries that are classified as restricted subsidiaries under the credit agreement. The credit agreement is also secured by substantially all of the assets of the Company, Diamondback O&G LLC and the guarantors.

The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by the Company that is equal to an alternate 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 0.25% to 1.25% in the case of the alternate base rate and from 1.25% to 2.25% in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the least of the maximum credit amount, the borrowing base and the elected commitment amount. 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 commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. 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 commitment or 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, 2022.

19

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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

Financial Covenant	Required Ratio
Ratio of total net debt to EBITDAX, as defined in the credit agreement	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, as amended in November 2017, allows for the issuance of unsecured debt in the form of senior or senior subordinated notes if no default would result from the incurrence of such debt after giving effect thereto and if, in connection with any such issuance, the borrowing base is reduced by 25% of the stated principal amount of each such issuance.

As of September 30, 2018 and December 31, 2017, 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.

The Partnership’s Credit Agreement

On July 8, 2014, the Partnership entered into a secured revolving credit agreement with Wells Fargo, as administrative agent, certain other lenders and the Operating Company, the Partnership’s consolidated subsidiary, as guarantor. On May 8, 2018, the Operating Company assumed all liabilities as borrower under the credit agreement and the Partnership became a guarantor of the credit agreement. On July 20, 2018, the Operating Company, the Partnership, Wells Fargo and the other lenders amended and restated the credit agreement to reflect the assumption by the Operating Company.

The credit agreement, as amended and restated, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base based on the Partnership’s oil and natural gas reserves and other factors (the “borrowing base”) of $475.0 million, subject to scheduled semi-annual and other borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and October 26th. In addition, the Operating Company and Wells Fargo each may request up to three interim redeterminations of the borrowing base during any 12-month period. As of September 30, 2018, the borrowing base was set at $475.0 million, and there was $296.5 million of outstanding borrowings and $178.5 million available for future borrowings under the revolving credit facility. In connection with the Partnership’s fall 2018 redetermination, the Partnership’s borrowing base was increased to $555.0 million effective October 26, 2018.

The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by the Operating Company that is equal to an alternate 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 0.75% to 1.75% per annum in the case of the alternate base rate and from 1.75% to 2.75% per annum in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the lesser of the maximum credit amount and the borrowing base. The Operating Company is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. 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 (i) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (ii) 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 (iii) at the maturity date of November 1, 2022. The loan is secured by substantially all of the assets of the Partnership and the Operating Company.

20

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, purchases of margin stock, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements, and require the maintenance of the financial ratios described below:

Financial Covenant	Required Ratio
Ratio of total net debt to EBITDAX, as defined in the credit agreement	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 $400.0 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.

The lenders may accelerate all of the indebtedness under the credit agreement 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.

Alliance with Obsidian Resources, L.L.C.

The Company entered into a participation and development agreement (the “DrillCo Agreement”), dated September 10, 2018, with Obsidian Resources, L.L.C. (“CEMOF”) to fund oil and natural gas development. Funds managed by CEMOF and its affiliates have agreed to commit to funding certain costs out of CEMOF’s net production revenue and, for a period of time, to the extent not funded by such revenue, up to an additional $300.0 million, to fund drilling programs on locations provided by the Company. Subject to adjustments depending on asset characteristics and return expectations of the selected drilling plan, CEMOF will fund up to 85% of the costs associated with new wells drilled under the DrillCo Agreement and is expected to receive an 80% working interest in these wells until it reaches certain payout thresholds equal to a cumulative 9% and then 13% internal rate of return. Upon reaching the final internal rate of return target, CEMOF’s interest will be reduced to 15%, while the Company’s interest will increase to 85%.

10.    CAPITAL STOCK AND EARNINGS PER SHARE

Diamondback did not complete any equity offerings during the nine months endedSeptember 30, 2018 and September 30, 2017.

Partnership Equity Offerings

In January 2017, the Partnership completed an underwritten public offering of 9,775,000 common units, which included 1,275,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. The Partnership received net proceeds from this offering of approximately $147.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which the Partnership used $120.5 million to repay the outstanding borrowings under its revolving credit agreement and the balance was used for general partnership purposes, which included additional acquisitions.

In July 2017, the Partnership completed an underwritten public offering of 16,100,000 common units, which included 2,100,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. In this offering, the Company purchased 700,000 common units, an affiliate of the General Partner purchased 3,000,000 common units and certain officers and directors of the Company and the General Partner purchased an aggregate of 114,000 common units, in each case directly from the underwriters. The Partnership received net proceeds from this offering of approximately $232.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which the Partnership used $152.8 million to repay all of the then-outstanding borrowings under the Partnership’s revolving credit facility and the balance was used to fund a portion of the purchase price for acquisitions and for general partnership purposes.

In July 2018, the Partnership completed an underwritten public offering of 10,080,000 common units, which included 1,080,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Following this offering, Diamondback owned approximate 59% of the total Partnership units then outstanding. The Partnership received net proceeds from this offering of approximately $303.1 million, after deducting underwriting discounts and commissions and estimated offering expenses. The Partnership used the net proceeds to purchase units of the Operating Company. The Operating Company in turn used the net proceeds to repay a portion of the $361.5 million then outstanding borrowings under its revolving credit facility.

Earnings Per Share

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

21

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands, except per share amounts)
Net income attributable to common stock	$	157,054	$	73,024	$	539,012	$	367,702
Weighted average common shares outstanding
Basic weighted average common units outstanding	98,638		98,144		98,603		96,491
Effect of dilutive securities:
Potential common shares issuable	180		225		217		261
Diluted weighted average common shares outstanding	98,818		98,369		98,820		96,752
Basic net income attributable to common stock	$	1.59	$	0.74	$	5.47	$	3.81
Diluted net income attributable to common stock	$	1.59	$	0.74	$	5.45	$	3.80

For the three months ended September 30, 2018 and 2017, there were 12,699 shares and 52,857 shares, respectively, and during the nine months ended September 30, 2018 and 2017, there were 2,300 and 1,248 shares, respectively, that were not included in the computation of diluted earnings per share because their inclusion would have been anti-dilutive for the periods presented. These shares could dilute basic earnings per share in future periods.

11.    EQUITY-BASED COMPENSATION

The following table presents the effects of the equity compensation plans and related costs:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands)
General and administrative expenses	$	5,350	$	6,187	$	18,451	$	19,418
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	2,338		2,167		7,328		6,411

Restricted Stock Units

The following table presents the Company’s restricted stock units activity under the Equity Plan during the nine months ended September 30, 2018:

	Restricted Stock Awards & Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2017	243,577		$	90.88
Granted	90,115		$	115.03
Vested	(170,014	)	$	89.08
Forfeited	(7,597	)	$	95.80
Unvested at September 30, 2018	156,081		$	106.54

The aggregate fair value of restricted stock units that vested during the nine months ended September 30, 2018 and 2017 was $15.1 million and $14.8 million, respectively. As of September 30, 2018, the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $13.0 million. Such cost is expected to be recognized over a weighted-average period of 1.4 years.

22

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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 two-year or three-year performance period.

In February 2018, eligible employees received performance restricted stock unit awards totaling 117,423 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, 2018 to December 31, 2020 and cliff vest at December 31, 2020.

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 for the February 2018 awards.

	2018
	Three-Year Performance Period
Grant-date fair value	$	170.45
Risk-free rate	1.99		%
Company volatility	35.90		%

The following table presents the Company’s performance restricted stock units activity under the Equity Plan for the nine months ended September 30, 2018:

	Performance Restricted Stock Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2017	202,326		$	139.83
Granted	285,737		$	130.96
Vested	(168,314	)	$	103.41
Unvested at September 30, 2018(1)	319,749		$	151.08

(1) A maximum of 639,498 units could be awarded based upon the Company’s final TSR ranking.

As of September 30, 2018, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $23.0 million. Such cost is expected to be recognized over a weighted-average period of 1.2 years.

Partnership Unit Options

The following table presents the unit option activity under the Viper LTIP for the nine months ended September 30, 2018:

			Weighted Average
	Unit Options		Exercise Price		Remaining Term	Intrinsic Value
					(in years)	(in thousands)
Outstanding at December 31, 2017	7,600		$	18.49
Exercised	(7,600	)	$	18.49
Outstanding at September 30, 2018	—		$	—	0.00	$	—

23

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

The aggregate intrinsic value of unit options that were exercised during the nine months ended September 30, 2018 were $0.2 million.

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 units entitle 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 nine months ended September 30, 2018.

	Phantom Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2017	105,439		$	17.10
Granted	119,818		$	24.46
Vested	(102,811	)	$	19.23
Unvested at September 30, 2018	122,446		$	22.52

The aggregate fair value of phantom units that vested during the nine months ended September 30, 2018 was $2.0 million. As of September 30, 2018, the unrecognized compensation cost related to unvested phantom units was $2.0 million. Such cost is expected to be recognized over a weighted-average period of 1.3 years.

12.    RELATED PARTY TRANSACTIONS

Advisory Services Agreement - The Partnership

In connection with the closing of the Viper Offering, the Partnership and the 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 the General Partner with general financial and strategic advisory services related to the business in return for an annual fee of $0.5 million, plus reasonable out-of-pocket expenses. The Viper Advisory Services Agreement had an initial term of two years commencing on June 23, 2014, and will continue for additional one-year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term. The Partnership did not pay any amounts during the three months and nine months endedSeptember 30, 2018 or September 30, 2017 under the Viper Advisory Services Agreement.

Lease Bonus - The Partnership

During the three months and nine months endedSeptember 30, 2018, the Company paid the Partnership $2.9 million in lease bonus payments to extend the term of 12 leases, reflecting an average bonus of $6,412 per acre. During the three months ended September 30, 2017, the Company did not pay the Partnership any lease bonus payments. During the nine months ended September 30, 2017, the Company paid the Partnership $0.1 million in lease bonus payments to extend the term of two leases, reflecting an average bonus of $7,459 per acre.

24

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

13.    INCOME TAXES

The Company’s effective income tax rates were 11.5% and 1.2% for the nine months endedSeptember 30, 2018 and 2017, respectively. Total income tax expense for the nine months endedSeptember 30, 2018 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income primarily due to (i) the impact of deferred taxes recognized by the Partnership as a result of its change in tax status, (ii) current and deferred state income taxes, (iii) net income attributable to the non-controlling interest, and (iv) the impact of permanent differences between book and taxable income. The Company recorded a discrete income tax benefit of approximately $0.8 million related to equity-based compensation for the nine months endedSeptember 30, 2018 and a discrete benefit of approximately $72.7 million related to deferred taxes on the Partnership’s investment in the Operating Company arising from the change in the Partnership’s tax status. Total income tax expense for the nine months endedSeptember 30, 2017differed from amounts computed by applying the federal statutory rate to pre-tax income primarily due to state income taxes and the change in the valuation allowance which offset the Company’s federal net deferred tax position in that period.

The Tax Cuts and Jobs Act, a historic reform of the U.S. federal income tax statutes, was enacted on December 22, 2017. As of the completion of the Company’s financial statements for the year ended December 31, 2017, the Company had substantially completed its accounting for the effects of the enactment of the Tax Cuts and Jobs Act and, with respect to those items for which the Company’s accounting was not complete, the Company made reasonable estimates of the effects on its deferred tax balances. At September 30, 2018, the Company had not made an adjustment to the provisional estimates recorded for the year ended December 31, 2017. The Company has considered in its estimated annual effective tax rate for 2018 the impact of the statutory changes enacted by the Tax Cuts and Jobs Act, including reasonable estimates of those provisions effective for the 2018 tax year.

As discussed further in Note 5, on March 29, 2018, the Partnership announced that the Board of Directors of its General Partner had unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity, which change became effective on May 10, 2018. The transactions undertaken in connection with the change in the Partnership’s tax status were not taxable to the Company. Subsequent to the Partnership’s change in tax status, the Partnership’s provision for income taxes for the period ended September 30, 2018 is based on its estimated annual effective tax rate plus discrete items. As such, the Partnership’s provision for income taxes is included in the Company’s consolidated financial statements and to the extent applicable, in net income attributable to the non-controlling interest.

14.    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 fixed price swap contracts, fixed price basis swap contracts and three-way costless collars with corresponding put, short put and call options to reduce price volatility associated with certain of its oil and natural gas sales. With respect to the Company’s fixed price swap contracts and fixed price basis 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 or basis 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 or basis price. The Company has fixed price basis swaps for the spread between the WTI Midland price and the WTI Cushing price.

Under the Company’s costless collar contracts, a three-way collar is a combination of three options: a ceiling call, a floor put, and a short put. The counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the ceiling price to a maximum of the difference between the floor price and the short put price.  The Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the ceiling price. If the settlement price is between the floor and the ceiling price, there is no payment required.

The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing (Cushing and Magellan East Houston) and Crude Oil Brent, and with natural gas derivative settlements based on the New York Mercantile Exchange Henry Hub pricing.

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

25

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

As of September 30, 2018, the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.

	2018				2019
	Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)			Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)
Oil Swaps - WTI Cushing	2,392,000	$	51.27		1,638,000	$	52.78
Oil Swaps - WTI Magellan East Houston	644,000	$	71.06		1,087,000	$	40.37
Oil Swaps - BRENT	920,000	$	62.51		725,000	$	72.63
Oil Basis Swaps	1,380,000	$	(0.88	)	270,000	$	(9.42	)
Natural Gas Swaps	1,840,000	$	3.07		—	$	—

	October 2018 - December 2018		January 2019 - December 2019
Oil Three-Way Collars	WTI Magellan East Houston		WTI Cushing		Brent		WTI Magellan East Houston
Volume (Bbls)	644,000		1,810,000		2,000,000		994,000
Short put price (per Bbl)	$	56.43	$	45.00	$	55.00	$	56.82
Floor price (per Bbl)	$	66.43	$	55.00	$	65.00	$	66.82
Ceiling price (per Bbl)	$	78.82	$	70.23	$	82.47	$	77.60

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, 2018 and December 31, 2017.

	September 30, 2018		December 31, 2017
	(in thousands)
Gross amounts of assets presented in the Consolidated Balance Sheet	$	—	$	531
Net amounts of assets presented in the Consolidated Balance Sheet	—		531
Gross amounts of liabilities presented in the Consolidated Balance Sheet	129,757		106,670
Net amounts of liabilities presented in the Consolidated Balance Sheet	$	129,757	$	106,670

26

Diamondback Energy, Inc. and Subsidiaries

Condensed 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, 2018		December 31, 2017
	(in thousands)
Current assets: derivative instruments	$	—	$	531
Noncurrent assets: derivative instruments	—		—
Total assets	$	—	$	531
Current liabilities: derivative instruments	$	123,826	$	100,367
Noncurrent liabilities: derivative instruments	5,931		6,303
Total liabilities	$	129,757	$	106,670

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(in thousands)
Change in fair value of open non-hedge derivative instruments	$	(9,913	)	$	(58,645	)	$	(23,618	)	$	9,365
Gain (loss) on settlement of non-hedge derivative instruments	(38,460		)	8,000			(115,687		)	11,011
Gain (loss) on derivative instruments	$	(48,373	)	$	(50,645	)	$	(139,305	)	$	20,376

15.    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.

27

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

The Company estimates the fair values of proved oil and natural gas properties assumed in business combinations using discounted cash flow techniques and based on market assumptions as to the future commodity prices, internal estimates of future quantities of oil and natural gas reserves, future estimated rates of production, expected recovery rates and risk-adjustment discounts. The estimated fair values of unevaluated oil and natural gas properties were based on the location, engineering and geological studies, historical well performance, and applicable mineral lease terms. Given the unobservable nature of the inputs, the estimated fair values of oil and natural gas properties assumed is deemed to use Level 3 inputs. The asset retirement obligations assumed as part of business combinations are estimated using the same assumptions and methodology as described below.

The Company estimates asset retirement obligations pursuant to the provisions of the Financial Accounting Standards Board issued Accounting Standards Codification Topic 410, “Asset Retirement and Environmental Obligations”. The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with the future plugging and abandonment of wells and related facilities. Given the unobservable nature of the inputs, including plugging costs and useful lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 7—Asset Retirement Obligations for further discussion of the Company’s asset retirement obligations.

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 and cost method investment. The fair values of the Company’s fixed price swaps, fixed price basis swaps and costless collars are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs.

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2018 and December 31, 2017.

	September 30, 2018
	Level 1		Level 2			Level 3
	(in thousands)
Assets:
Investment	$	20,240	$	—		$	—
Liabilities:
Fixed price swaps	$	—	$	(129,757	)	$	—

	December 31, 2017
	Level 1		Level 2			Level 3
	(in thousands)
Assets:
Investment	$	—	$	—		$	—
Liabilities:
Fixed price swaps	$	—	$	(106,139	)	$	—

28

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets:

	September 30, 2018				December 31, 2017
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
	(in thousands)
Debt:
Revolving credit facility	$	—	$	—	$	397,000	$	397,000
4.750% Senior Notes due 2024	$	1,250,000	$	1,252,613	$	500,000	$	501,855
5.375% Senior Notes due 2025	$	800,000	$	819,000	$	500,000	$	515,000
Partnership revolving credit facility	$	296,500	$	296,500	$	93,500	$	93,500

The fair value of the revolving credit facility and the Partnership’s revolving credit facility approximates their 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, 2018 quoted market price, a Level 1 classification in the fair value hierarchy.

16.    COMMITMENTS AND CONTINGENCIES

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

17.    SUBSEQUENT EVENTS

Recent Acquisitions and Divestitures

Ajax Resources, LLC

On July 22, 2018, the Company entered into a definitive purchase agreement to acquire all leasehold interests and related assets of Ajax Resources, LLC which includes approximately 25,493 net leasehold acres in the Northern Midland Basin for $900.0 million in cash, subject to certain adjustments, and approximately 2.6 million shares of the Company’s common stock. This transaction closed October 31, 2018, and was effective as of July 1, 2018. See Note 4—Acquisitions for additional information regarding the Ajax acquisition.

The cash portion of the purchase price for the Ajax acquisition was funded through a combination of cash on hand, proceeds from the sale of mineral interests to the Partnership, borrowing under the Company’s revolving credit facility and a portion of the proceeds from the Company’s September 2018 senior note offering. See Note 9—Debt for information relating to this offering.

ExL Petroleum Management, LLC and Energy Quest II LLC

On October 31, 2018, the Company completed the acquisition of approximately 3,646 net leasehold acres and related assets in the Northern Midland Basin from ExL Petroleum Management, LLC, ExL Petroleum Operating, Inc. and EnergyQuest II LLC for $312.5 million in cash, subject to certain adjustments. See Note 4—Acquisitions for additional information regarding this acquisition.

29

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Divestiture of Oil and Natural Gas Properties

On November 1, 2018, the Company completed its divestiture of certain oil and natural gas properties in the Delaware Basin for an aggregate sale price of $62.1 million. This transaction included the divestiture of approximately 2,485 gross (2,072 net) acres primarily in Pecos county, Texas.

Third Quarter Dividend Declaration

On November 5, 2018, the Board of Directors of the Company declared a cash dividend for the third quarter of 2018 of $0.125 per share of common stock, payable on November 26, 2018 to its stockholders of record at the close of business on November 19, 2018.

Commodity Contracts

Subsequent to September 30, 2018, the Company entered into new fixed price basis swaps. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing (Cushing and Magellan East Houston) and Crude Oil Brent.

The following tables present the derivative contracts entered into by the Company subsequent to September 30, 2018. When aggregating multiple contracts, the weighted average contract price is disclosed.

	Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)
April 2019 - December 2019
Oil Swaps - WTI Magellan East Houston	458,000	$	76.18
Oil Swaps - BRENT	275,000	$	77.58

The Company’s Credit Facility

On October 26, 2018, the Company’s borrowing base under its credit agreement was increased to $2.5 billion and was increased further to $2.65 billion on November 6, 2018 following the closing of the Company’s acquisition of assets from Ajax Resources, LLC and satisfaction of certain other conditions. The Company also elected to increase the commitment amount from $1.0 billion to $2.0 billion effective October 26, 2018.

The Partnership’s Credit Facility

In connection with the Partnership’s fall 2018 redetermination, the Partnership’s borrowing base was increased to $555.0 million effective October 26, 2018.

18.    GUARANTOR FINANCIAL STATEMENTS

As of September 30, 2018, Diamondback E&P LLC and Diamondback O&G LLC (the “Guarantor Subsidiaries”) are guarantors under the indentures relating to the 2024 Senior Notes and the 2025 Senior Notes, as supplemented. In connection with the issuance of the 2024 Senior Notes and the 2025 Senior Notes (including the New 2025 Senior Notes), the Partnership, the General Partner, Viper Energy Partners LLC and Rattler Midstream LLC were designated as Non-Guarantor Subsidiaries. The following presents condensed consolidated financial information for the Company (which for purposes of this Note 18 is referred to as the “Parent”), the Guarantor Subsidiaries and the Non–Guarantor Subsidiaries 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.

30

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Condensed Consolidated Balance Sheet
September 30, 2018
(In thousands)
						Non–
			Guarantor			Guarantor
	Parent		Subsidiaries			Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	471,148	$	20,469		$	16,829		$	—		$	508,446
Accounts receivable	—		226,299			38,018			—			264,317
Accounts receivable - related party	—		—			7,758			(7,758		)	—
Intercompany receivable	3,199,881		262,503			—			(3,462,384		)	—
Inventories	—		14,815			—			—			14,815
Other current assets	257		7,708			146			—			8,111
Total current assets	3,671,286		531,794			62,751			(3,470,142		)	795,689
Property and equipment:
Oil and natural gas properties, at cost, full cost method of accounting	—		9,209,250			1,612,425			(3,297		)	10,818,378
Midstream assets	—		355,758			—			—			355,758
Other property, equipment and land	—		80,194			5,688			—			85,882
Accumulated depletion, depreciation, amortization and impairment	—		(2,306,710		)	(230,784		)	(7,918		)	(2,545,412		)
Net property and equipment	—		7,338,492			1,387,329			(11,215		)	8,714,606
Funds held in escrow	—		62,034			—			—			62,034
Investment in subsidiaries	4,631,753		989			—			(4,632,742		)	—
Deferred tax asset	—		—			95,551			—			95,551
Investment in real estate, net	—		106,834			—			—			106,834
Other assets	—		8,513			23,346			—			31,859
Total assets	$	8,303,039	$	8,048,656		$	1,568,977		$	(8,114,099	)	$	9,806,573
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	—	$	85,865		$	4		$	—		$	85,869
Intercompany payable	—		3,470,142			—			(3,470,142		)	—
Other current liabilities	41,026		590,186			4,706			—			635,918
Total current liabilities	41,026		4,146,193			4,710			(3,470,142		)	721,787
Long-term debt	2,035,859		—			296,500			—			2,332,359
Derivative instruments	—		5,931			—			—			5,931
Asset retirement obligations	—		23,897			—			—			23,897
Deferred income taxes	292,795		—			—			—			292,795
Other long-term liabilities	—		7			—			—			7
Total liabilities	2,369,680		4,176,028			301,210			(3,470,142		)	3,376,776
Commitments and contingencies
Stockholders’ equity	5,933,359		3,872,628			572,217			(4,444,845		)	5,933,359
Non-controlling interest	—		—			695,550			(199,112		)	496,438
Total equity	5,933,359		3,872,628			1,267,767			(4,643,957		)	6,429,797
Total liabilities and equity	$	8,303,039	$	8,048,656		$	1,568,977		$	(8,114,099	)	$	9,806,573

31

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Condensed Consolidated Balance Sheet
December 31, 2017
(In thousands)
						Non–
			Guarantor			Guarantor
	Parent		Subsidiaries			Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	54,074	$	34,175		$	24,197		$	—		$	112,446
Accounts receivable	—		205,859			25,754			—			231,613
Accounts receivable - related party	—		—			5,142			(5,142		)	—
Intercompany receivable	2,624,810		2,267,308			—			(4,892,118		)	—
Inventories	—		9,108			—			—			9,108
Other current assets	618		4,461			355			—			5,434
Total current assets	2,679,502		2,520,911			55,448			(4,897,260		)	358,601
Property and equipment:
Oil and natural gas properties, at cost, full cost method of accounting	—		8,129,211			1,103,897			(414		)	9,232,694
Midstream assets	—		191,519			—			—			191,519
Other property, equipment and land	—		80,776			—			—			80,776
Accumulated depletion, depreciation, amortization and impairment	—		(1,976,248		)	(189,466		)	4,342			(2,161,372		)
Net property and equipment	—		6,425,258			914,431			3,928			7,343,617
Funds held in escrow	—		—			6,304			—			6,304
Investment in subsidiaries	3,809,557		—			—			(3,809,557		)	—
Other assets	—		25,609			36,854			—			62,463
Total assets	$	6,489,059	$	8,971,778		$	1,013,037		$	(8,702,889	)	$	7,770,985
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	1	$	91,629		$	2,960		$	—		$	94,590
Intercompany payable	132,067		4,765,193			—			(4,897,260		)	—
Other current liabilities	7,236		472,933			2,669			—			482,838
Total current liabilities	139,304		5,329,755			5,629			(4,897,260		)	577,428
Long-term debt	986,847		397,000			93,500			—			1,477,347
Derivative instruments	—		6,303			—			—			6,303
Asset retirement obligations	—		20,122			—			—			20,122
Deferred income taxes	108,048		—			—			—			108,048
Total liabilities	1,234,199		5,753,180			99,129			(4,897,260		)	2,189,248
Commitments and contingencies
Stockholders’ equity	5,254,860		3,218,598			913,908			(4,132,506		)	5,254,860
Non-controlling interest	—		—			—			326,877			326,877
Total equity	5,254,860		3,218,598			913,908			(3,805,629		)	5,581,737
Total liabilities and equity	$	6,489,059	$	8,971,778		$	1,013,037		$	(8,702,889	)	$	7,770,985

32

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Condensed Consolidated Statement of Operations
Three Months Ended September 30, 2018
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues:
Oil sales	$	—		$	391,051		$	—		$	63,593		$	454,644
Natural gas sales	—			10,891			—			3,923			14,814
Natural gas liquid sales	—			50,740			—			6,870			57,610
Royalty income	—			—			74,386			(74,386		)	—
Lease bonus	—			—			4,205			(2,883		)	1,322
Midstream services	—			7,280			—			—			7,280
Other operating income	—			2,347			12			—			2,359
Total revenues	—			462,309			78,603			(2,883		)	538,029
Costs and expenses:
Lease operating expenses	—			49,111			—			—			49,111
Production and ad valorem taxes	—			28,509			5,027			—			33,536
Gathering and transportation	—			6,087			889			—			6,976
Midstream services	—			19,725			—			—			19,725
Depreciation, depletion and amortization	—			125,627			16,532			4,159			146,318
General and administrative expenses	6,862			6,629			1,309			(615		)	14,185
Asset retirement obligation accretion	—			387			—			—			387
Other operating expense	—			940			—			—			940
Total costs and expenses	6,862			237,015			23,757			3,544			271,178
Income (loss) from operations	(6,862		)	225,294			54,846			(6,427		)	266,851
Other income (expense)
Interest expense, net	(10,868		)	(3,969		)	(3,711		)	—			(18,548		)
Other income (expense), net	416			1,521			640			(615		)	1,962
Loss on derivative instruments, net	—			(48,373		)	—			—			(48,373		)
Loss on revaluation of investment	—			—			(199		)	—			(199		)
Total other income (expense), net	(10,452		)	(50,821		)	(3,270		)	(615		)	(65,158		)
Income (loss) before income taxes	(17,314		)	174,473			51,576			(7,042		)	201,693
Provision for income taxes	41,512			—			764			—			42,276
Net income (loss)	(58,826		)	174,473			50,812			(7,042		)	159,417
Net income attributable to non-controlling interest	—			—			48,466			(46,103		)	2,363
Net income (loss) attributable to Diamondback Energy, Inc.	$	(58,826	)	$	174,473		$	2,346		$	39,061		$	157,054

33

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Condensed Consolidated Statement of Operations
Three Months Ended September 30, 2017
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues:
Oil sales	$	—		$	223,038		$	—		$	36,011		$	259,049
Natural gas sales	—			11,774			—			3,148			14,922
Natural gas liquid sales	—			22,214			—			3,052			25,266
Royalty income	—			—			42,211			(42,211		)	—
Lease bonus	—			—			322			—			322
Midstream services	—			1,694			—			—			1,694
Total revenues	—			258,720			42,533			—			301,253
Costs and expenses:
Lease operating expenses	—			32,498			—			—			32,498
Production and ad valorem taxes	—			15,546			2,825			—			18,371
Gathering and transportation	—			3,271			205			—			3,476
Midstream services	—			4,445			—			—			4,445
Depreciation, depletion and amortization	—			74,766			11,068			1,745			87,579
General and administrative expenses	6,506			4,629			1,368			(615		)	11,888
Asset retirement obligation accretion	—			357			—			—			357
Total costs and expenses	6,506			135,512			15,466			1,130			158,614
Income (loss) from operations	(6,506		)	123,208			27,067			(1,130		)	142,639
Other income (expense)
Interest expense, net	(6,393		)	(1,940		)	(859		)	—			(9,192		)
Other income (expense), net	9			210			399			(615		)	3
Loss on derivative instruments, net	—			(50,645		)	—			—			(50,645		)
Total other income (expense), net	(6,384		)	(52,375		)	(460		)	(615		)	(59,834		)
Income (loss) before income taxes	(12,890		)	70,833			26,607			(1,745		)	82,805
Provision for income taxes	857			—			—			—			857
Net income (loss)	(13,747		)	70,833			26,607			(1,745		)	81,948
Net income attributable to non-controlling interest	—			—			—			8,924			8,924
Net income (loss) attributable to Diamondback Energy, Inc.	$	(13,747	)	$	70,833		$	26,607		$	(10,669	)	$	73,024

34

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Condensed Consolidated Statement of Operations
Nine Months Ended September 30, 2018
(In thousands)
					Non–
			Guarantor		Guarantor
	Parent		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Revenues:
Oil sales	—		1,149,184		—		185,165		1,334,349
Natural gas sales	—		31,405		—		9,152		40,557
Natural gas liquid sales	—		116,976		—		16,882		133,858
Royalty income	—		—		211,199		(211,199	)	—
Lease bonus	—		—		5,133		(2,883	)	2,250
Midstream services	—		26,658		—		—		26,658
Other operating income	—		6,705		120		—		6,825
Total revenues	—		1,330,928		216,452		(2,883	)	1,544,497
Costs and expenses:
Lease operating expenses	—		129,103		—		—		129,103
Production and ad valorem taxes	—		78,909		14,133		—		93,042
Gathering and transportation	—		16,777		1,297		—		18,074
Midstream services	—		48,515		—		—		48,515
Depreciation, depletion and amortization	—		337,823		41,317		12,261		391,401
General and administrative expenses	20,891		19,763		6,230		(1,845	)	45,039
Asset retirement obligation accretion	—		1,107		—		—		1,107
Other operating expense	—		2,416		—		—		2,416
Total costs and expenses	20,891		634,413		62,977		10,416		728,697
Income (loss) from operations	(20,891	)	696,515		153,475		(13,299	)	815,800
Other income (expense)
Interest expense, net	(29,945	)	(10,339	)	(9,061	)	—		(49,345	)
Other income (expense), net	750		88,786		1,479		(1,845	)	89,170
Loss on derivative instruments, net	—		(139,305	)	—		—		(139,305	)
Gain on revaluation of investment	—		—		5,165		—		5,165
Total other income (expense), net	(29,195	)	(60,858	)	(2,417	)	(1,845	)	(94,315	)
Income (loss) before income taxes	(50,086	)	635,657		151,058		(15,144	)	721,485
Provision for (benefit from) income taxes	153,864		—		(71,114	)	—		82,750
Net income (loss)	(203,950	)	635,657		222,172		(15,144	)	638,735
Net income attributable to non-controlling interest	—		—		77,526		22,197		99,723
Net income (loss) attributable to Diamondback Energy, Inc.	(203,950	)	635,657		144,646		(37,341	)	539,012

35

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Condensed Consolidated Statement of Operations
Nine Months Ended September 30, 2017
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues:
Oil sales	$	—		$	607,381		$	—		$	96,626		$	704,007
Natural gas sales	—			31,088			—			6,449			37,537
Natural gas liquid sales	—			50,506			—			7,119			57,625
Royalty income	—			—			110,194			(110,194		)	—
Lease bonus	—			—			2,613			(106		)	2,507
Midstream services	—			4,241			—			—			4,241
Total revenues	—			693,216			112,807			(106		)	805,917
Costs and expenses:
Lease operating expenses	—			88,113			—			—			88,113
Production and ad valorem taxes	—			42,307			7,668			—			49,975
Gathering and transportation	—			8,618			492			—			9,110
Midstream services	—			7,127			—			—			7,127
Depreciation, depletion and amortization	—			190,748			28,587			2,346			221,681
General and administrative expenses	20,046			14,259			5,064			(1,845		)	37,524
Asset retirement obligation accretion	—			1,030			—			—			1,030
Total costs and expenses	20,046			352,202			41,811			501			414,560
Income (loss) from operations	(20,046		)	341,014			70,996			(607		)	391,357
Other income (expense)
Interest expense, net	(23,526		)	(4,022		)	(2,114		)	—			(29,662		)
Other income (expense), net	1,101			9,690			526			(1,845		)	9,472
Gain on derivative instruments, net	—			20,376			—			—			20,376
Total other income (expense), net	(22,425		)	26,044			(1,588		)	(1,845		)	186
Income (loss) before income taxes	(42,471		)	367,058			69,408			(2,452		)	391,543
Provision for income taxes	4,393			—			—			—			4,393
Net income (loss)	(46,864		)	367,058			69,408			(2,452		)	387,150
Net income attributable to non-controlling interest	—			—			—			19,448			19,448
Net income (loss) attributable to Diamondback Energy, Inc.	$	(46,864	)	$	367,058		$	69,408		$	(21,900	)	$	367,702

36

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Condensed Consolidated Statement of Cash Flows
Nine Months Ended September 30, 2018
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Net cash provided by operating activities	$	220		$	975,082		$	176,414		$	—		$	1,151,716
Cash flows from investing activities:
Additions to oil and natural gas properties	—			(1,010,325		)	—			—			(1,010,325		)
Additions to midstream assets	—			(129,820		)	—			—			(129,820		)
Purchase of other property, equipment and land	—			2,638			(4,687		)	—			(2,049		)
Acquisition of leasehold interests	—			(185,658		)	—			—			(185,658		)
Acquisition of mineral interests	—			170,268			(505,842		)	—			(335,574		)
Proceeds from sale of assets	—			6,206			565			—			6,771
Funds held in escrow	—			(51,045		)	—			—			(51,045		)
Equity investments	—			(604		)	—			—			(604		)
Intercompany transfers	(22,310		)	22,310			—			—			—
Investment in real estate	—			(110,654		)	—			—			(110,654		)
Net cash used in investing activities	(22,310		)	(1,286,684		)	(509,964		)	—			(1,818,958		)
Cash flows from financing activities:
Proceeds from borrowing under credit facility	—			470,500			557,000			—			1,027,500
Repayment under credit facility	—			(867,500		)	(354,000		)	—			(1,221,500		)
Proceeds from senior notes	1,062,000			—			—			—			1,062,000
Debt issuance costs	(13,723		)	(232		)	(623		)	—			(14,578		)
Public offering costs	—			—			(2,636		)	—			(2,636		)
Proceeds from public offerings	—			—			305,773			—			305,773
Contributions to subsidiaries	(1,000		)	—			(1,000		)	2,000			—
Contributions by members	—			—			2,000			(2,000		)	—
Distributions from subsidiary	112,671			—			—			(112,671		)	—
Unit options exercised	—			—			140			—			140
Dividends to stockholders	(24,656		)	—			—			—			(24,656		)
Distributions to non-controlling interest	—			—			(181,472		)	112,671			(68,801		)
Intercompany transfers	(696,128		)	695,128			1,000			—			—
Net cash provided by financing activities	439,164			297,896			326,182			—			1,063,242
Net increase (decrease) in cash and cash equivalents	417,074			(13,706		)	(7,368		)	—			396,000
Cash and cash equivalents at beginning of period	54,074			34,175			24,197			—			112,446
Cash and cash equivalents at end of period	$	471,148		$	20,469		$	16,829		$	—		$	508,446

37

Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Condensed Consolidated Statement of Cash Flows
Nine Months Ended September 30, 2017
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(25,369	)	$	569,330		$	94,057		$	—		$	638,018
Cash flows from investing activities:
Additions to oil and natural gas properties	—			(531,489		)	—			—			(531,489		)
Additions to midstream assets	—			(22,491		)	—			—			(22,491		)
Purchase of other property, equipment and land	—			(21,534		)	—			—			(21,534		)
Acquisition of leasehold interests	—			(1,892,864		)	—			—			(1,892,864		)
Acquisition of mineral interests	—			(69,722		)	(301,133		)	—			(370,855		)
Acquisition of midstream assets	—			(50,279		)	—			—			(50,279		)
Proceeds from sale of assets	—			3,584			—			—			3,584
Funds held in escrow	—			121,391			—			—			121,391
Equity investments	—			(188		)	—			—			(188		)
Intercompany transfers	(1,651,328		)	1,651,328			—			—			—
Net cash used in investing activities	(1,651,328		)	(812,264		)	(301,133		)	—			(2,764,725		)
Cash flows from financing activities:
Proceeds from borrowing under credit facility	—			312,500			220,500			—			533,000
Repayment under credit facility	—			(78,000		)	(305,500		)	—			(383,500		)
Purchase of subsidiary units by parent	(10,068		)	—			—			10,068			—
Debt issuance costs	(744		)	(790		)	(180		)	—			(1,714		)
Public offering costs	(77		)	—			(433		)	—			(510		)
Proceeds from public offerings	—			—			380,412			(10,068		)	370,344
Distributions from subsidiary	64,858			—			—			(64,858		)	—
Proceeds from exercise of stock options	358			—			—			—			358
Distributions to non-controlling interest	—			—			(92,498		)	64,858			(27,640		)
Net cash provided by financing activities	54,327			233,710			202,301			—			490,338
Net decrease in cash and cash equivalents	(1,622,370		)	(9,224		)	(4,775		)	—			(1,636,369		)
Cash and cash equivalents at beginning of period	1,643,226			14,135			9,213			—			1,666,574
Cash and cash equivalents at end of period	$	20,856		$	4,911		$	4,438		$	—		$	30,205

38

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 report as well as our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2017. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See “Part II. Item 1A. Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Overview

We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. Our activities are primarily directed at the horizontal development of the Wolfcamp and Spraberry formations in the Midland Basin and the Wolfcamp and Bone Spring formations in the Delaware Basin. We intend to continue to develop our reserves and increase production through development drilling and 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.

The following table sets forth our production data for the periods indicated:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Oil (MBbls)	72	%	73	%	73	%	74	%
Natural gas (MMcf)	11	%	13	%	12	%	12	%
Natural gas liquids (MBbls)	17	%	14	%	15	%	14	%
	100	%	100	%	100	%	100	%

As of September 30, 2018, we had approximately 208,317 net acres, which consisted of approximately 104,973 net acres in the Northern Midland Basin and approximately 103,344 net acres in the Southern Delaware Basin. As of December 31, 2017, we had an estimated 3,800 gross horizontal locations that we believe to be economic at $60 per Bbl West Texas Intermediate, or WTI.

In the third quarter of 2018, we again demonstrated our operational focus on achieving best-in-class execution, low-cost operations and a conservative balance sheet as we continued to execute on our growth plan while maintaining cash operating margins in excess of 80% on a per BOE basis. In doing so, we achieved another quarter of robust production growth within cash flow, which has allowed us to maintain a low leverage ratio, while generating what we believe to be a peer leading return on average capital employed. During the third quarter of 2018, we operated 13 drilling rigs and five dedicated frac spreads, and recently added our 14th operating rigs when we took over operations from Ajax Resources, LLC, or Ajax.

2018 Highlights

Transportation Contracts

In July 2018, we executed agreements to secure firm oil transportation out of the Midland Basin at fixed discounts to Gulf Coast pricing beginning with the third quarter of 2018 and have multiple term sales agreements in place to cover the remainder of our expected Midland production. We also executed an option agreement to acquire up to a 10% equity interest in the EPIC Crude Oil Pipeline project in connection with a 100,000 BOD/d volume commitment, with 50% of the volume covered via a take or pay contract and the remaining 50% covered via an acreage dedication.

39

In October 2018, we executed another agreement to secure firm oil transportation out of the Midland Basin at fixed discounts to Gulf Coast pricing beginning in November 2018 to transport product from the acreage we recently acquired from Ajax (described below) and production growth from our existing assets. This agreement, as well as the agreements executed in July, will provide transportation assurance for the majority of our existing Midland production, production from the Ajax acreage and our estimated production growth for the fourth quarter of 2018.

Ajax Resources, LLC

On July 22, 2018, we entered into a definitive purchase agreement to acquire leasehold interests and related assets of Ajax, which include approximately 25,493 net leasehold acres in the Northern Midland Basin, for $900.0 million in cash, subject to certain adjustments, and approximately 2.6 million shares of our common stock, which we refer to as the Ajax acquisition. The Ajax acquisition closed on October 31, 2018 and was effective as of July 1, 2018. The cash portion of this transaction was funded through a combination of cash on hand, proceeds from the sale of mineral interests to Viper Energy Partners LP, which we refer to as Viper or the Partnership, described below, borrowing under our revolving credit facility and proceeds from our September 2018 senior note offering. See “Our September 2018 Senior Note Offering” below.

In connection with the closing of the Ajax acquisition on October 31, 2018, we entered into a registration rights agreement with Ajax and certain other holders of our common stock pursuant to which we agreed to (i) file with the SEC a shelf registration statement to facilitate the resale of common stock issued in the Ajax acquisition and (ii) use our reasonable best efforts to cause such registration statement to become effective by November 30, 2018. Pursuant to this registration rights agreement, we also agreed to provide certain demand and piggyback registration rights to such holders.

ExL Petroleum Management, LLC and EnergyQuest II LLC Acquisition

On September 21, 2018, we entered into two definitive purchase agreements to acquire leasehold interests and related assets, one with ExL Petroleum Management, LLC and ExL Petroleum Operating, Inc. and one with EnergyQuest II LLC, for an aggregate of approximately 3,646 net leasehold acres in the Northern Midland Basin for a total of $312.5 million in cash, subject to certain adjustments. These transactions closed on October 31, 2018 and were effective as of August 1, 2018. These transactions, which we refer to collectively as the ExL acquisition, were funded through a combination of cash on hand, proceeds from the sale of assets to the Partnership (described below) and borrowing under our revolving credit facility.

Pending Merger with Energen Corporation

On August 14, 2018, we entered into a definitive merger agreement providing for our acquisition of Energen Corporation, or Energen, in an all-stock transaction valued at approximately $9.2 billion including Energen’s net debt of $831.0 million as of June 30, 2018, which we refer to as the Pending Merger. The addition of Energen’s assets will increase our assets to: (i) over 273,000 net Tier One acres in the Permian Basin, an increase of 57% from our current Tier One acreage of approximately 174,000 net acres, (ii) over 7,200 estimated total net horizontal Permian locations, an increase of over 120% from our current estimated net locations, and (iii) approximately 394,000 net acres across the Midland and Delaware Basins, an increase of 82% from our approximately 216,000 net acres as September 30, 2018, in each after giving effect to our recently completed Ajax acquisition and ExL acquisition.

The completion of the Pending Merger is subject to the satisfaction or waiver of certain customary mutual closing conditions. Our registration statement on Form S-4 relating to the Pending Merger was declared effective by the SEC on October 24, 2018, and the Pending Merger is expected to be completed at the end of November of 2018.

40

Under the terms of the merger agreement relating to the Pending Merger, we have agreed to assume Energen’s outstanding debt, which as of June 30, 2018 was approximately $831.0 million. This amount consists of $301.0 million of borrowings under Energen’s existing credit facility, $400.0 millionaggregate principal amount of 4.625% Notes, due September 1, 2021, $20.0 million aggregate principal amount of 7.32% Medium-term Notes, Series A, due July 28, 2022, $10.0 million aggregate principal amount of 7.35% Medium-term Notes, Series A, due July 28, 2027, and $100.0 million aggregate principal amount of 7.125% Medium-term Notes, Series B, due February 15, 2028, which we collectively refer to as the Energen Notes. We may choose to refinance the Energen credit facility and our credit facility into a combined credit facility in connection with the consummation of the Pending Merger or we may choose to repay the outstanding borrowings under the Energen credit facility using cash on hand or borrowings under our revolving credit facility. With respect to the outstanding Energen Notes, we may take no action, or we may seek to amend the terms of the indenture governing the Energen Notes or engage in liability management transactions with respect to, repay or refinance any or all of the Energen Notes, with any repayment coming from cash on hand or borrowings under our revolving credit facility.

Drop-down Transaction

On August 15, 2018, we sold to the Partnership mineral interests underlying 32,424 gross (1,696 net royalty) acres primarily in Pecos County, Texas, in the Permian Basin, approximately 80% of which are operated by us, for $175.0 million, which we refer to as the Drop-down Transaction.

Alliance with Obsidian Resources, L.L.C.

We entered into a participation and development agreement, which we refer to as the DrillCo agreement, dated September 10, 2018, with Obsidian Resources, L.L.C., which we refer to as CEMOF, to fund oil and natural gas development. Funds managed by CEMOF and its affiliates have agreed to commit to funding certain costs out of CEMOF’s net production revenue and, for a period of time, to the extent not funded by such revenue, up to an additional $300.0 million, to fund drilling programs on locations provided by us. Subject to adjustments depending on asset characteristics and return expectations of the selected drilling plan, CEMOF will fund up to 85% of the costs associated with new wells drilled under the DrillCo agreement and is expected to receive an 80% working interest in these wells until it reaches certain payout thresholds equal to a cumulative 9% and then 13% internal rate of return. Upon reaching the final internal rate of return target, CEMOF’s interest will be reduced to 15%, while our interest will increase to 85%.

Third Quarter Dividend Declaration

On November 5, 2018, our board of directors declared a cash dividend for the third quarter of 2018 of $0.125 per share of common stock, payable on November 26, 2018 to our stockholders of record at the close of business on November 19, 2018.

Our September 2018 Senior Note Offering

On September 25, 2018, we issued $750.0 million aggregate principal amount of new 4.750% senior notes due 2024, or the “new 2024 notes”. The new 2024 notes were issued in a transaction exempt from the registration requirements under the Securities Act. We received approximately $740.7 million in net proceeds, after deducting the initial purchasers’ discount and our estimated offering expenses, but disregarding accrued interest, from the issuance of the new 2024 notes. We used a portion of the net proceeds from the issuance of the new 2024 notes to repay a portion of the outstanding borrowings our revolving credit facility and we used the balance for general corporate purposes, including the funding of a portion of the cash consideration for the acquisition of assets from Ajax.

Viper’s July 2018 Equity Offering

In July 2018, Viper completed an underwritten public offering of 10,080,000 common units, which included 1,080,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Following this offering, we owned approximately 59% of Viper’s total units then outstanding. Viper received net proceeds from this offering of approximately $303.1 million, after deducting underwriting discounts and commissions and estimated offering expenses. Viper used the net proceeds to purchase units of the Operating Company. The Operating Company in turn used the net proceeds to repay a portion of the $361.5 million then outstanding borrowings under its revolving credit facility.

41

Operational Update

During the three months ended September 30, 2018, we drilled 40 gross (34 net) operated horizontal wells, of which 20 gross (18 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin, and turned 43 gross (38 net) operated horizontal wells into production, of which 30 gross (26 net) wells were in the Midland Basin and the remaining wells were in the Delaware Basin.

During the third quarter of 2018, we operated 13 drilling rigs and five dedicated frac spreads. Upon the closing of the Ajax acquisition on October 31, we took over operations of one operated rig and plan to run an average of 14 drilling rigs for the remainder of 2018. We expect to operate seven of these drilling rigs in the Midland Basin targeting horizontal development of the Wolfcamp and Spraberry formations, while the remainder of the drilling rigs are expected to operate in the Delaware Basin targeting the Wolfcamp and Bone Spring formations.

In the Midland Basin, we continue to see positive well results from our core development areas in Midland, Glasscock, Howard, Andrews and Martin counties. Assuming commodity prices at current levels, we anticipate operating between six and seven drilling rigs across our Northern Midland Basin acreage for the remainder of 2018.

In the Delaware Basin, we are currently operating seven drilling rigs, with plans to operate seven drilling rigs for the remainder of 2018. Our 2018 development plan is primarily focused on long-lateral Wolfcamp A wells in Pecos, Reeves and Ward counties. In the third quarter, we tested the Second Bone Spring in Pecos county by completing two wells with positive early time results.

We continue to focus on low cost operations and best in class execution. In doing so, we are focused on controlling oilfield service costs as our service providers seek additional pricing increases after a prolonged period of declining costs in 2015 and 2016. To combat rising service costs, we have taken proactive measures such as securing frac sand supply for future well completions, locking in costs where feasible and purchasing items such as casing in bulk and in advance. We will continue to seek opportunities to control and de-bundle additional costs where possible, such as diesel and frac sand costs for our completion operations. We believe that our 2018 drilling and completion budget covers potential increases in our service costs during the year.

The following table summarizes our average daily production for the periods presented:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
Oil (Bbls)/d	88,262	61,720	82,046	55,212
Natural Gas (Mcf)/d	84,826	64,506	79,549	53,321
Natural Gas Liquids (Bbls)/d	20,575	12,558	17,495	10,526
Total average production per day (BOE)	122,975	85,029	112,799	74,624

Our average daily production for the three months ended September 30, 2018 as compared to the three months ended September 30, 2017increased37,946 BOE/d, or 44.6%.

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Recapitalization, Tax Status Election and Related Transactions by Viper

In March 2018, Viper announced that the Board of Directors of its general partner had unanimously approved a change of Viper’s federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election. In connection with making this election, on May 9, 2018 Viper (i) amended and restated its First Amended and Restated Partnership Agreement, (ii) amended and restated the First Amended and Restated Limited Liability Company Agreement of Viper Energy Partners LLC, or the Operating Company, (iii) amended and restated its existing registration rights agreement with us and (iv) entered into an exchange agreement with us, Viper’s general partner, or the General Partner, and the Operating Company. Simultaneously with the effectiveness of these agreements, we delivered and assigned to Viper the 73,150,000 common units we owned in exchange for (i) 73,150,000 of Viper’s newly-issued Class B units and (ii) 73,150,000 newly-issued units of the Operating Company pursuant to the terms of a Recapitalization Agreement dated March 28, 2018, as amended as of May 9, 2018, or the Recapitalization Agreement. Immediately following that exchange, Viper continued to be the managing member of the Operating Company, with sole control of its operations, and owned approximately 36% of the outstanding units issued by the Operating Company, and we owned the remaining approximately 64% of the outstanding units issued by the Operating Company. Upon completion of Viper’s July 2018 offering of units, Viper owned approximately 41% of the outstanding units issued by the Operating Company and we owned the remaining approximately 59%. The Operating Company units and Viper’s Class B units owned by us are exchangeable from time to time for Viper’s common units (that is, one Operating Company unit and one Viper Class B unit, together, will be exchangeable for one Viper common unit).

On May 10, 2018, the change in Viper’s income tax status became effective. On that date, pursuant to the terms of the Recapitalization Agreement, (i) the General Partner made a cash capital contribution of $1.0 million to Viper in respect of its general partner interest and (ii) we made a cash capital contribution of $1.0 million to Viper in respect of the Class B units. We, as the holder of the Class B units, and the General Partner, as the holder of the general partner interest, are entitled to receive an 8% annual distribution on the outstanding amount of these capital contributions, payable quarterly, as a return on this invested capital. On May 10, 2018, we also exchanged 731,500 Class B units and 731,500 units in the Operating Company for 731,500 common units of Viper and a cash amount of $10,000 representing a proportionate return of the $1.0 million invested capital in respect of the Class B units. The General Partner continues to serve as Viper’s general partner and we continue to control Viper. After the effectiveness of the tax status election and the completion of related transactions, Viper’s minerals business continues to be conducted through the Operating Company, which continues to be taxed as a partnership for federal and state income tax purposes. This structure is anticipated to provide significant benefits to Viper’s business, including operational effectiveness, acquisition and disposition transactional planning flexibility and income tax efficiency. For additional information regarding the tax status election and related transactions, please refer to Viper’s Definitive Information Statement on Schedule 14C filed with the SEC on April 17, 2018 and Viper’s Current Report on Form 8-K filed with the SEC on May 15, 2018.

Sources of Our Revenues

Our main sources of revenues are 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. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold, production mix or commodity prices.

The following table presents the breakdown of our revenues for the following periods:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Revenues
Oil sales	86	%	87	%	88	%	88	%
Natural gas sales	3	%	5	%	3	%	5	%
Natural gas liquid sales	11	%	8	%	9	%	7	%
	100	%	100	%	100	%	100	%

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 or natural gas liquids prices. Oil, natural gas and natural gas liquids prices have historically been volatile. During 2017, WTI posted prices ranged from $42.48 to $60.46 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.44 to $3.71 per MMBtu. During the first nine months of 2018, WTI posted prices ranged from $59.20 to $77.41 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.49 to $6.24 per MMBtu. On September 28, 2018, the WTI posted price for crude oil was $73.16 per Bbl and the Henry Hub spot market price of natural gas was $3.01 per MMBtu. Lower commodity prices may not only decrease our revenues, but also potentially the amount of oil and natural gas that we can produce economically. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our credit agreement, which may be redetermined at the discretion of our lenders.

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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,
	2018			2017				2018			2017
	(in thousands, except Bbl, Mcf and BOE amounts)
Revenues:
Oil, natural gas and natural gas liquids	$	527,068		$	299,237			$	1,508,764		$	799,169
Lease bonus	1,322			322				2,250			2,507
Midstream services	7,280			1,694				26,658			4,241
Other operating income	2,359			—			—	6,825			—
Total revenues	538,029			301,253				1,544,497			805,917
Operating expenses:
Lease operating expenses	49,111			32,498				129,103			88,113
Production and ad valorem taxes	33,536			18,371				93,042			49,975
Gathering and transportation	6,976			3,476				18,074			9,110
Midstream services	19,725			4,445				48,515			7,127
Depreciation, depletion and amortization	146,318			87,579				391,401			221,681
General and administrative expenses	14,185			11,888				45,039			37,524
Asset retirement obligation accretion	387			357				1,107			1,030
Other operating expense	940			—				2,416			—
Total expenses	271,178			158,614				728,697			414,560
Income from operations	266,851			142,639				815,800			391,357
Interest expense, net	(18,548		)	(9,192		)		(49,345		)	(29,662		)
Other income, net	1,962			3				89,170			9,472
Gain (loss) on derivative instruments, net	(48,373		)	(50,645		)		(139,305		)	20,376
Gain (loss) on revaluation of investment	(199		)	—			—	5,165			—
Total other income (expense), net	(65,158		)	(59,834		)		(94,315		)	186
Income before income taxes	201,693			82,805				721,485			391,543
Provision for income taxes	42,276			857				82,750			4,393
Net income	159,417			81,948				638,735			387,150
Net income attributable to non-controlling interest	2,363			8,924				99,723			19,448
Net income attributable to Diamondback Energy, Inc.	$	157,054		$	73,024			$	539,012		$	367,702

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(in thousands)
Production Data:
Oil (MBbls)	8,120			5,678			22,399			15,073
Natural gas (MMcf)	7,804			5,935			21,717			14,557
Natural gas liquids (MBbls)	1,893			1,155			4,776			2,874
Combined volumes (MBOE)	11,314			7,823			30,794			20,372
Daily combined volumes (BOE/d)	122,975			85,029			112,799			74,624
Average Prices:
Oil (per Bbl)	$	55.99		$	45.62		$	59.57		$	46.71
Natural gas (per Mcf)	1.90			2.51			1.87			2.58
Natural gas liquids (per Bbl)	30.44			21.87			28.03			20.05
Combined (per BOE)	46.59			38.25			49.00			39.23
Oil, hedged ($ per Bbl)(1)	51.23			46.90			54.36			47.35
Natural gas, hedged ($ per MMbtu)(1)	1.93			2.64			1.92			2.67
Average price, hedged ($ per BOE)(1)	43.19			39.28			45.24			39.77
Average Costs per BOE:
Lease operating expense	$	4.34		$	4.15		$	4.19		$	4.33
Production and ad valorem taxes	2.96			2.35			3.02			2.45
Gathering and transportation expense	0.62			0.44			0.59			0.45
General and administrative - cash component	0.78			0.73			0.86			0.89
Total operating expense - cash	$	8.70		$	7.67		$	8.66		$	8.12
General and administrative - non-cash component	$	0.47		$	0.79		$	0.60		$	0.95
Depreciation, depletion and amortization	12.93			11.20			12.71			10.88
Interest expense, net	1.64			1.18			1.60			1.46
Total expenses	$	15.04		$	13.17		$	14.91		$	13.29
Average realized oil price ($/Bbl)	$	55.99		$	45.62		$	59.57		$	46.71
Average NYMEX ($/Bbl)	69.69			48.18			66.93			49.30
Differential to NYMEX	(13.70		)	(2.56		)	(7.36		)	(2.59		)
Average realized oil price to NYMEX	80		%	95		%	89		%	95		%
Average realized natural gas price ($/Mcf)	$	1.90		$	2.51		$	1.87		$	2.58
Average NYMEX ($/Mcf)	2.93			2.95			2.95			3.01
Differential to NYMEX	(1.03		)	(0.44		)	(1.08		)	(0.43		)
Average realized natural gas price to NYMEX	65		%	85		%	63		%	86		%
Average realized natural gas liquids price ($/Bbl)	$	30.44		$	21.87		$	28.03		$	20.05
Average NYMEX oil price ($/Bbl)	69.69			48.18			66.93			49.30
Average realized natural gas liquids price to NYMEX oil price	44		%	45		%	42		%	41		%

(1) Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects include gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting.

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Comparison of the Three Months Ended September 30, 2018 and 2017

Oil, Natural Gas and Natural Gas Liquids Revenues. Our oil, natural gas and natural gas liquids revenues increased by approximately $227.8 million, or 76%, to $527.1 million for the three months ended September 30, 2018 from $299.2 million for the three months ended September 30, 2017. Our revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 37,946 BOE/d to 122,975 BOE/d during the three months ended September 30, 2018 from 85,029 BOE/d during the three months ended September 30, 2017. The total increase in revenue of approximately $227.8 million is largely attributable to higher oil, natural gas and natural gas liquids production volumes and higher average sales prices for the three months ended September 30, 2018 as compared to the three months ended September 30, 2017. The increases in production volumes were due to a combination of increased drilling activity and growth through acquisitions. Our production increased by 2,441,927 Bbls of oil, 1,869,390 Mcf of natural gas and 737,526 Bbls of natural gas liquids for the three months ended September 30, 2018 as compared to the three months ended September 30, 2017.

The net dollar effect of the increases in prices of approximately $95.7 million (calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas and natural gas liquids) and the net dollar effect of the increase in production of approximately $132.2 million (calculated as the increase in period-to-period volumes for oil, natural gas and natural gas liquids 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	$	10.37		8,120		$	84,206
Natural gas	(0.61		)	7,804		(4,760		)
Natural gas liquids	8.57			1,893		16,222
Total revenues due to change in price						$	95,668
	Change in production volumes(1)			Prior period Average Prices		Total net dollar effect of change
						(in thousands)
Effect of changes in production volumes:
Oil	2,442			$	45.62	$	111,334
Natural gas	1,869			2.51		4,700
Natural gas liquids	738			21.87		16,129
Total revenues due to change in production volumes						132,163
Total change in revenues						$	227,831

(1) Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.

Lease Bonus Revenue. Lease bonus income increased by $1.0 million for the three months ended September 30, 2018 as compared to the three months ended September 30, 2017. Lease bonus revenue was $1.3 million for the three months ended September 30, 2018 attributable to lease bonus payments to extend the term of 13 leases, reflecting an average bonus of $7,369 per acre. Lease bonus revenue was $0.3 million for the three months ended September 30, 2017 attributable to lease bonus payments to extend the term of one lease, reflecting an average bonus of $10,000 per acre.

Midstream Services Revenue. Midstream services revenue was $7.3 million for the three months ended September 30, 2018, an increase of $5.6 million as compared to $1.7 million for the three months ended September 30, 2017. We began generating midstream services revenue during the first quarter of 2017 and, prior to that period, had no midstream services revenue. Our midstream services revenue represents fees charged to our joint interest owners and third parties for the transportation of oil and natural gas along with water gathering and related disposal facilities. These assets complement our operations in areas where we have significant production.

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Lease Operating Expense. Lease operating expense was $49.1 million ($4.34 per BOE) for the three months ended September 30, 2018 as compared to $32.5 million ($4.15 per BOE) for the three months ended September 30, 2017. The increase in lease operating expense was a result of nonrecurring charges due to work overs.

Production and Ad Valorem Tax Expense. Production and ad valorem taxes were $33.5 million for the three months ended September 30, 2018, an increase of $15.2 million, or 83%, from $18.4 million for the three months ended September 30, 2017. 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, among other factors, whereas production taxes are based upon current year commodity prices. During the three months ended September 30, 2018, our production and ad valorem taxes per BOE increased by $0.61 as compared to the three months ended September 30, 2017, primarily due to increased commodity prices and production volumes.

Midstream Services Expense. Midstream services expense was $19.7 million for the three months ended September 30, 2018, an increase of $15.3 million as compared to $4.4 million for the three months ended September 30, 2017. Prior to the first quarter of 2017, we had no midstream services expense. Midstream services expense represents costs incurred to operate and maintain our oil and natural gas gathering and transportation systems, natural gas lift, compression infrastructure and water transportation facilities.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased$58.7 million, or 67%, to $146.3 million for the three months ended September 30, 2018 from $87.6 million for the three months ended September 30, 2017.

The following table provides the components of our depreciation, depletion and amortization expense for the periods presented:

	Three Months Ended September 30,
	2018		2017
	(in thousands, except BOE amounts)
Depletion of proved oil and natural gas properties	$	138,402	$	86,388
Depreciation of midstream assets	5,451		830
Depreciation of other property and equipment	2,465		361
Depreciation, depletion and amortization expense	$	146,318	$	87,579
Oil and natural gas properties depreciation, depletion and amortization per BOE	$	12.23	$	11.04

The increase in depletion of proved oil and natural gas properties of $52.0 million for the three months ended September 30, 2018 as compared to the three months ended September 30, 2017 resulted primarily from higher production levels and an increase in net book value on new reserves added.

General and Administrative Expenses. General and administrative expenses increased$2.3 million from $11.9 million for the three months ended September 30, 2017 to $14.2 million for the three months ended September 30, 2018. The increase was primarily due to an increase in employee count.

Net Interest Expense. Net interest expense for the three months ended September 30, 2018 was $18.5 million as compared to $9.2 million for the three months ended September 30, 2017, an increase of $9.4 million. This increase was due to a higher interest rate and increased average borrowings during the three months ended September 30, 2018 as compared to the three months ended September 30, 2017.

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 “Gain (loss) on derivative instruments, net.” For the three months ended September 30, 2018, we had a cash loss on settlement of derivative instruments of $38.5 million as compared to a cash gain on settlement of derivative instruments of $8.0 million for the three months ended September 30, 2017. For the three months ended September 30, 2018 and 2017, we had a negative change in the fair value of open derivative instruments of $9.9 million and $58.6 million, respectively.

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Provision for Income Taxes. We recorded an income tax provision of $42.3 million for the three months ended September 30, 2018 as compared to an income tax provision of $0.9 million for the three months ended September 30, 2017. The change in our income tax provision was primarily due to the increase in pre-tax book income for the three months ended September 30, 2018, and the change in the valuation allowance for the three months ended September 30, 2017.

Comparison of the Nine Months Ended September 30, 2018 and 2017

Oil, Natural Gas and Natural Gas Liquids Revenues. Our oil, natural gas and natural gas liquids revenues increased by approximately $709.6 million, or 89%, to $1,508.8 million for the nine months ended September 30, 2018 from $799.2 million for the nine months ended September 30, 2017. Our revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 38,175 BOE/d to 112,799 BOE/d during the nine months ended September 30, 2018 from 74,624 BOE/d during the nine months ended September 30, 2017. The total increase in revenue of approximately $709.6 million is largely attributable to higher oil, natural gas and natural gas liquids production volumes and higher average sales prices for the nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017. The increases in production volumes were due to a combination of increased drilling activity and growth through acquisitions. Our production increased by 7,325,834 Bbls of oil, 7,160,383 Mcf of natural gas and 1,902,459 Bbls of natural gas liquids for the nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017.

The net dollar effect of the increases in prices of approximately $310.7 million (calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas and natural gas liquids) and the net dollar effect of the increase in production of approximately $398.9 million (calculated as the increase in period-to-period volumes for oil, natural gas and natural gas liquids 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	$	12.86		22,399		$	288,046
Natural gas	(0.71		)	21,716		(15,418		)
Natural gas liquids	7.98			4,776		38,113
Total revenues due to change in price						$	310,741
	Change in production volumes(1)			Prior period Average Prices		Total net dollar effect of change
						(in thousands)
Effect of changes in production volumes:
Oil	7,326			$	46.71	$	342,239
Natural gas	7,160			2.58		18,465
Natural gas liquids	1,902			20.05		38,150
Total revenues due to change in production volumes						398,854
Total change in revenues						$	709,595

(1) Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.

Lease Bonus Revenue. Lease bonus income decreased by $0.3 million for the nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017. Lease bonus revenue was $2.3 million for the nine months ended September 30, 2018 attributable to lease bonus payments to extend the term of 16 leases, reflecting an average bonus of $7,090 per acre. Lease bonus revenue was $2.5 million for the nine months ended September 30, 2017 attributable to lease bonus payments to extend the term of four leases, reflecting an average bonus of $3,257 per acre.

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Midstream Services Revenue. Midstream services revenue was $26.7 million for the nine months ended September 30, 2018, an increase of $22.4 million as compared to $4.2 million for the nine months ended September 30, 2017. We began generating midstream services revenue during the first quarter of 2017 and, prior to that period, had no midstream services revenue. Our midstream services revenue represents fees charged to our joint interest owners and third parties for the transportation of oil and natural gas along with water gathering and related disposal facilities. These assets complement our operations in areas where we have significant production.

Lease Operating Expense. Lease operating expense was $129.1 million ($4.19 per BOE) for the nine months ended September 30, 2018 as compared to $88.1 million ($4.33 per BOE) for the nine months ended September 30, 2017. The increase in lease operating expense was a result of nonrecurring charges due to work overs. The decrease in lease operating expense per BOE was a result of lease operating expenses increasing at a lower percentage than the increase in production volumes.

Production and Ad Valorem Tax Expense. Production and ad valorem taxes were $93.0 million for the nine months ended September 30, 2018, an increase of $43.1 million, or 86%, from $50.0 million for the nine months ended September 30, 2017. 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, among other factors, whereas production taxes are based upon current year commodity prices. During the nine months ended September 30, 2018, our production and ad valorem taxes per BOE increased by $0.57 as compared to the nine months ended September 30, 2017, primarily due to increased commodity prices and production volumes.

Midstream Services Expense. Midstream services expense was $48.5 million for the nine months ended September 30, 2018, an increase of $41.4 million as compared to $7.1 million for the nine months ended September 30, 2017. Prior to the first quarter of 2017, we had no midstream services expense. Midstream services expense represents costs incurred to operate and maintain our oil and natural gas gathering and transportation systems, natural gas lift, compression infrastructure and water transportation facilities.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased$169.7 million, or 77%, to $391.4 million for the nine months ended September 30, 2018 from $221.7 million for the nine months ended September 30, 2017.

The following table provides the components of our depreciation, depletion and amortization expense for the periods presented:

	Nine Months Ended September 30,
	2018		2017
	(in thousands, except BOE amounts)
Depletion of proved oil and natural gas properties	$	370,771	$	218,335
Depreciation of midstream assets	14,023		2,261
Depreciation of other property and equipment	6,607		1,085
Depreciation, depletion and amortization expense	$	391,401	$	221,681
Oil and natural gas properties depreciation, depletion and amortization per BOE	$	12.04	$	10.71

The increase in depletion of proved oil and natural gas properties of $152.4 million for the nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017 resulted primarily from higher production levels and an increase in net book value on new reserves added.

General and Administrative Expenses. General and administrative expenses increased$7.5 million from $37.5 million for the nine months ended September 30, 2017 to $45.0 million for the nine months ended September 30, 2018. The increase was primarily due to an increase in employee count.

Net Interest Expense. Net interest expense for the nine months ended September 30, 2018 was $49.3 million as compared to $29.7 million for the nine months ended September 30, 2017, an increase of $19.7 million. This increase was due to a higher interest rate and increased borrowings during the nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017.

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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 “Gain (loss) on derivative instruments, net.” For the nine months ended September 30, 2018, we had a cash loss on settlement of derivative instruments of $115.7 million as compared to a cash gain on settlement of derivative instruments of $11.0 million for the nine months ended September 30, 2017. For the nine months ended September 30, 2018, we had a negative change in the fair value of open derivative instruments of $23.6 million as compared to a positive change of $9.4 million for the nine months ended September 30, 2017.

Provision for Income Taxes. We recorded an income tax provision of $82.8 million and $4.4 million for the nine months ended September 30, 2018 and 2017, respectively. The change in our income tax provision was primarily due to the increase in pre-tax book income for the nine months ended September 30, 2018, and the change in the valuation allowance for the nine months ended September 30, 2017.

Liquidity and Capital Resources

Historically, our primary sources of liquidity have been proceeds from our public equity offerings, borrowings under our revolving credit facility, proceeds from the issuance of our senior notes and cash flows from operations. Our primary uses of capital have 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 months ended September 30, 2018 and 2017 are presented below:

	Nine Months Ended September 30,
	2018			2017
	(in thousands)
Net cash provided by operating activities	$	1,151,716		$	638,018
Net cash used in investing activities	(1,818,958		)	(2,764,725		)
Net cash provided by financing activities	1,063,242			490,338
Net increase (decrease) in cash	$	396,000		$	(1,636,369	)

Operating Activities

Net cash provided by operating activities was $1.2 billion for the nine months ended September 30, 2018 as compared to $638.0 million for the nine months ended September 30, 2017. The increase in operating cash flows is primarily the result of an increase in our oil and natural gas revenues due to an increase in average prices and production growth during the nine months ended September 30, 2018.

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. Net cash used in investing activities was $1.8 billion and $2.8 billion during the nine months ended September 30, 2018 and 2017, respectively.

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During the nine months ended September 30, 2018, we spent (a) $1.0 billion on capital expenditures in conjunction with our development program, in which we drilled 40 gross (34 net) operated horizontal wells, of which 20 gross (18 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin, and turned 43 gross (38 net) operated horizontal wells into production, of which 30 gross (26 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin, (b) $129.8 million on additions to midstream assets, (c) $185.7 million on leasehold acquisitions, (d) $335.6 million for the acquisition of mineral interests, (e) $110.7 million in real estate investments, (f) $51.0 million funds held in escrow and (g) $2.0 million for the purchase of other property and equipment.

During the nine months ended September 30, 2017, we spent (a) $531.5 million on capital expenditures in conjunction with our drilling program and related infrastructure projects, in which we drilled 106 gross (94 net) horizontal wells, completed 85 gross (71 net) horizontal wells and participated in the drilling of 12 gross (one net) non-operated wells in the Permian Basin, (b) $22.5 million on additions to midstream assets, (c) $1,892.9 million on leasehold acquisitions, (d) $50.3 million for midstream assets, (e) $21.5 million for the purchase of other property and equipment and (f) $370.9 million for mineral interests acquisitions.

Our investing activities for the nine months ended September 30, 2018 and 2017 are summarized in the following table:

	Nine Months Ended September 30,
	2018			2017
	(in thousands)
Drilling, completion and infrastructure	$	(1,010,325	)	$	(531,489	)
Additions to midstream assets	(129,820		)	(22,491		)
Acquisition of leasehold interests	(185,658		)	(1,892,864		)
Acquisition of mineral interests	(335,574		)	(370,855		)
Acquisition of midstream assets	—			(50,279		)
Purchase of other property, equipment and land	(2,049		)	(21,534		)
Investment in real estate	(110,654		)	—
Proceeds from sale of assets	6,771			3,584
Funds held in escrow	(51,045		)	121,391
Equity investments	(604		)	(188		)
Net cash used in investing activities	$	(1,818,958	)	$	(2,764,725	)

Financing Activities

Net cash provided by financing activities for the nine months ended September 30, 2018 and 2017 was $1.1 billion and $490.3 million, respectively. During the nine months ended September 30, 2018, the amount provided by financing activities was primarily attributable to the issuance of $1.1 billion of new senior notes, partially offset by $194.0 million of repayments, net of aggregate borrowings under our credit facility in January and September 2018, an aggregate of $305.8 million of net proceeds from Viper’s public offerings, $68.8 million of distributions to non-controlling interest and $24.7 million of dividends to stockholders. The 2017 amount provided by financing activities was primarily attributable to $370.3 million of proceeds from Viper’s January and July 2017 equity offerings as well as $149.5 million of borrowings, net of repayments, under Viper’s credit facility and $27.6 million in distributions.

2024 Senior Notes

On October 28, 2016, we issued $500.0 million in aggregate principal amount of 4.750% senior notes due 2024, which we refer to as the existing 2024 senior notes. The existing 2024 senior notes bear interest at a rate of 4.750% per annum, payable semi-annually, in arrears on May 1 and November 1 of each year, commencing on May 1, 2017 and will mature on November 1, 2024. All of our existing and future restricted subsidiaries that guarantee our revolving credit facility or certain other debt guarantee the existing 2024 senior notes; provided, however, that the existing 2024 senior notes are not guaranteed by Viper, Viper Energy Partners GP LLC, Viper Energy Partners LLC or Rattler Midstream LLC, and will not be guaranteed by any of our future unrestricted subsidiaries.

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On September 25, 2018, we issued $750.0 million aggregate principal amount of new 4.750% senior notes due 2024, which we refer to as the new 2024 notes and, together with the existing 2024 senior notes, as the 2024 senior notes, as additional notes under, and subject to the terms of, the 2024 Indenture (as defined below). The new 2024 notes were issued in a transaction exempt from the registration requirements under the Securities Act. We received approximately $740.7 million in net proceeds, after deducting the initial purchasers’ discount and our estimated offering expenses, but disregarding accrued interest, from the issuance of the new 2024 notes. We used a portion of the net proceeds from the issuance of the new 2024 notes to repay a portion of the outstanding borrowings our revolving credit facility and the balance for general corporate purposes, including funding a portion of the cash consideration for the acquisition of assets from Ajax.

The 2024 senior notes were issued under, and are governed by, an indenture among us, the subsidiary guarantors party thereto and Wells Fargo, as the trustee (which, as may be amended or supplemented from time to time, is referred to as the 2024 Indenture). The 2024 Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit our 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 capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted 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 natural gas business and designate certain of our subsidiaries as unrestricted subsidiaries.

We may on any one or more occasions redeem some or all of the 2024 senior notes at any time on or after November 1, 2019 at the redemption prices (expressed as percentages of principal amount) of 103.563% for the 12-month period beginning on November 1, 2019, 102.375% for the 12-month period beginning on November 1, 2020, 101.188% for the 12-month period beginning on November 1, 2021 and 100.000% beginning on November 1, 2022 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to November 1, 2019, we may on any one or more occasions redeem all or a portion of the 2024 senior notes at a price equal to 100% of the principal amount of the 2024 senior notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to November 1, 2019, we may on any one or more occasions redeem the 2024 senior notes in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2024 senior notes issued prior to such date at a redemption price of 104.750%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings.

Under a registration rights agreement executed in connection with the issuance of the new 2024 notes, we and our subsidiary guarantors agreed to file, subject to certain conditions, a registration statement relating to the new 2024 notes with the SEC pursuant to which we will either offer to exchange the new 2024 notes for registered notes with substantially identical terms or, in certain circumstances, register the resale of the new 2024 notes. Additional interest on the new 2024 notes may become payable if we do not comply with our obligations under the registration rights agreement relating to the new 2024 notes.

2025 Senior Notes

On December 20, 2016, we issued $500.0 million in aggregate principal amount of 5.375% senior notes due 2025, which we refer to as the exiting 2025 notes, under an indenture (which, as may be amended or supplemented from time to time, is referred to as the 2025 Indenture) among us, the subsidiary guarantors party thereto and Wells Fargo, as the trustee. On July 27, 2017, we exchanged all of the existing 2025 notes for substantially identical notes in the same aggregate principal amount that were registered under the Securities Act.

On January 29, 2018, we issued $300.0 million aggregate principal amount of new 5.375% senior notes due 2025, which we refer to as the new 2025 notes, as additional notes under the 2025 Indenture. The new 2025 notes were issued in a transaction exempt from the registration requirements under the Securities Act. We refer to the new 2025 notes, together with the existing 2025 notes, as the 2025 senior notes. We received approximately $308.4 million in net proceeds, after deducting the initial purchaser’s discount and our estimated offering expenses, but disregarding accrued interest, from the issuance of the new 2025 notes. We used the net proceeds from the issuance of the new 2025 notes to repay a portion of the outstanding borrowings under our revolving credit facility.

The 2025 senior notes bear interest at a rate of 5.375% per annum, payable semi-annually, in arrears on May 31 and November 30 of each year and will mature on May 31, 2025. All of our existing and future restricted subsidiaries that guarantee our revolving credit facility or certain other debt guarantee the 2025 senior notes; provided, however, that the 2025 senior notes are not guaranteed by Viper, Viper Energy Partners GP LLC, Viper Energy Partners LLC or Rattler Midstream LLC, and will not be guaranteed by any of our future unrestricted subsidiaries.

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The 2025 Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit our 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 capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted 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 natural gas business and designate certain of our subsidiaries as unrestricted subsidiaries.

We may on any one or more occasions redeem some or all of the 2025 senior notes at any time on or after May 31, 2020 at the redemption prices (expressed as percentages of principal amount) of 104.031% for the 12-month period beginning on May 31, 2020, 102.688% for the 12-month period beginning on May 31, 2021, 101.344% for the 12-month period beginning on May 31, 2022 and 100.000% beginning on May 31, 2023 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to May 31, 2020, we may on any one or more occasions redeem all or a portion of the 2025 senior notes at a price equal to 100% of the principal amount of the 2025 senior notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to May 31, 2020, we may on any one or more occasions redeem the 2025 senior notes in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2025 senior notes issued prior to such date at a redemption price of 105.375%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings.

As required under the terms of the registration rights agreements relating to the new 2025 senior notes, we filed with the SEC our Registration Statement on Form S-4 relating to the exchange offers of the new 2025 senior notes for substantially identical notes registered under the Securities Act. The Registration Statement was declared effective by the SEC on July 18, 2018 and we closed the exchange offer on August 24, 2018.

Second Amended and Restated Credit Facility

Our credit agreement dated November 1, 2013, as amended and restated, with a syndicate of banks, including Wells Fargo, as administrative agent, and its affiliate Wells Fargo Securities, LLC, as sole book runner and lead arranger, provides for a revolving credit facility in the maximum credit amount of $5.0 billion, subject to a borrowing base based on our oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be redetermined, under certain circumstances, annually with an effective date of May 1st, and, under certain circumstances, semi-annually with effective dates of May 1st and November 1st. In addition, we and Wells Fargo may each request up to two interim redeterminations of the borrowing base during any 12-month period. As of September 30, 2018, the borrowing base was set at $2.0 billion, we had elected a commitment amount of $1.0 billion and we had no outstanding borrowings under the revolving credit facility and $1.0 billion available for future borrowings under our revolving credit facility. On October 26, 2018, our credit agreement was further amended to increase the borrowing base to $2.5 billion, which was increased further to $2.65 billion on November 6, 2018 following our closing of the Ajax acquisition and satisfaction of certain other conditions. We also elected to increase the commitment amount from $1.0 billion to $2.0 billion effective October 26, 2018. In addition, this amendment increased our flexibility to make restricted payments and redeem senior unsecured notes.

Diamondback O&G LLC is the borrower under our credit agreement. As of September 30, 2018, the credit agreement is guaranteed by us, Diamondback E&P LLC and Rattler Midstream LLC (formerly known as White Fang Energy LLC) and will also be guaranteed by any of our future subsidiaries that are classified as restricted subsidiaries under the credit agreement. The credit agreement is also secured by substantially all of our assets and the assets of Diamondback O&G LLC and the guarantors.

The outstanding borrowings under the credit agreement bear interest at a per annum 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 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.25% to 1.25% in the case of the alternative base rate and from 1.25% to 2.25% in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the least of the maximum credit amount, the borrowing base and the elected commitment amount. We are 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 loans and letters of credit outstanding in relation to the commitment. 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 commitment or 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, 2022.

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

Financial Covenant	Required Ratio
Ratio of total net debt to EBITDAX, as defined in the credit agreement	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, as amended in November 2017, allows for the issuance of unsecured debt in the form of senior or senior subordinated notes if no default would result from the incurrence of such debt after giving effect thereto and if, in connection with any such issuance, the borrowing base is reduced by 25% of the stated principal amount of each such issuance.

As of September 30, 2018, 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.

Viper’s Facility-Wells Fargo Bank

On July 8, 2014, Viper entered into a secured revolving credit agreement, or revolving credit facility, with Wells Fargo, as administrative agent, certain other lenders, and the Operating Company, as guarantor. On May 8, 2018, the Operating Company assumed all liabilities as borrower under the credit agreement and Viper became a guarantor of the credit agreement. On July 20, 2018, the Operating Company, Viper, Wells Fargo and the other lenders amended and restated the credit agreement to reflect the assumption by the Operating Company. The credit agreement, as amended and restated, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base based on Viper’s oil and natural gas reserves and other factors (the “borrowing base”) of $475.0 million, subject to scheduled semi-annual and other borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and October 26th. In addition, the Operating Company and Wells Fargo each may request up to three interim redeterminations of the borrowing base during any 12-month period. As of September 30, 2018, the borrowing base was set at $475.0 million, and Viper had $296.5 million of outstanding borrowings and $178.5 million available for future borrowings under its revolving credit facility. In connection with Viper’s fall 2018 redetermination, Viper’s borrowing base was increased to $555.0 million effective October 26, 2018.

The outstanding borrowings under Viper’s credit agreement bear interest at a per annum rate elected by the Operating Company that is equal to an alternate 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 0.75% to 1.75% per annum in the case of the alternate base rate and from 1.75% to 2.75% per annum in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the lesser of the maximum credit amount and the borrowing base. The Operating Company is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. 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 commitment or 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, 2022. The loan is secured by substantially all of the assets of Viper and the Operating Company.

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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:

Financial Covenant	Required Ratio
Ratio of total net debt to EBITDAX, as defined in the credit agreement	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 $400.0 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.

The lenders may accelerate all of the indebtedness under the 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.

Capital Requirements and Sources of Liquidity

Our board of directors approved a 2018 capital budget for drilling and infrastructure of approximately $1.5 billion to $1.6 billion, representing an increase of 74% over our 2017 capital budget. We estimate that, of these expenditures, approximately:

• $1.25 billion to $1.3 billion will be spent on drilling and completing 170 to 175 gross (146 to 163 net) horizontal wells across our operated leasehold acreage in the Northern Midland and Southern Delaware Basins, with an average lateral length of approximately 9.300 feet; and

• $225.0 million to $275.0 million will be spent on infrastructure and other expenditures, excluding the cost of any leasehold and mineral interest acquisitions.

During the nine months ended September 30, 2018, our aggregate capital expenditures for our development program were $1.0 billion. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted. During the nine months ended September 30, 2018, we spent approximately $521.2 million in cash on acquisitions of leasehold interests and mineral acres. Subsequently, on October 31, 2018, we purchased certain oil and natural gas assets for an aggregate of $1,212.5 million in cash and approximately 2.6 million shares of our common stock, subject to certain adjustments. We funded the cash portion of the consideration for these acquisitions through a combination of cash on hand, proceeds from the Drop-down Transaction, borrowings under our revolving credit facility and a portion of the proceeds from our issuance of the new 2024 notes. For a discussion of these acquisitions and the Pending Merger to acquire Energen in an all-stock transaction valued at approximately $9.2 billion, including Energen’s net debt of $831.0 million as of June 30, 2018, see “—2018 Highlights” above.

The amount and timing of these capital expenditures are 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. We are currently operating 11 drilling rigs and five completion crews. We will continue monitoring commodity prices and overall market conditions and can adjust our rig cadence up or down in response to changes in commodity prices and overall market conditions.

Based upon current oil and natural gas prices and production expectations for 2018, we believe that our cash flow from operations, cash on hand and borrowings under our revolving credit facility will be sufficient to fund our operations through year-end 2018. 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 2018 capital expenditure budget does not allocate any funds for leasehold interest and property acquisitions.

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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. If there is a decline in commodity prices, our revenues, cash flows, results of operations, liquidity and reserves may be materially and adversely affected.

Contractual Obligations

Except as discussed in Note 16 of the Notes to the Consolidated Financial Statements of this report, 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, 2017.

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, 2017.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of September 30, 2018. Please read Note 16 included in Notes to the Consolidated Financial Statements set forth in Part I, Item 1 of this report, for a discussion of our commitments and contingencies, some of which are not recognized in the 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, including basis swaps and costless collars, to reduce price volatility associated with certain of our oil and natural gas 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 NYMEX West Texas Intermediate pricing (Cushing and Magellan East Houston) and Crude Oil - Brent and with natural gas derivative settlements based on NYMEX Henry Hub pricing.

At September 30, 2018 and December 31, 2017, we had a net liability derivative position of $129.8 million and $106.7 million, respectively, related to our price swap derivatives. Utilizing actual derivative contractual volumes under our fixed price swaps as of September 30, 2018, a 10% increase in forward curves associated with the underlying commodity would have increased the net liability position to $137.7 million, an increase of $7.9 million, while a 10% decrease in forward curves associated with the underlying commodity would have decreased the net liability derivative position to $121.9 million, a decrease of $7.9 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.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from joint interest receivables (approximately $82.0 million at September 30, 2018) and receivables from the sale of our oil and natural gas production (approximately $182.4 million at September 30, 2018).

We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. For the nine months ended September 30, 2018, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (26%), Koch Supply & Trading LP (18%), and Rio Oil & Gas LLC (11%). For the nine months ended September 30, 2017, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (33%); Koch Supply & Trading LP (20%); and Enterprise Crude Oil LLC (11%). 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, 2018, we had seven customers that represented approximately 76% of our total joint operations receivables. At December 31, 2017, we had three customers that represented approximately 74% 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 0.25% to 1.25% in the case of the alternative base rate and from 1.25% to 2.25% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base.

As of September 30, 2018, we had no outstanding borrowings under our revolving credit facility. As of October 31, 2018, upon the closing of the Ajax acquisition and the ExL acquisition, we had $748.0 million in outstanding borrowings under our revolving credit facility. Our weighted average interest rate on borrowings under our revolving credit facility was 3.8% as of October 31, 2018. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our interest expense of approximately $7.5 million based on an aggregate of $748.0 million outstanding under our revolving credit facility as of October 31, 2018 upon the closing of the Ajax acquisition and ExL acquisition.

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 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, 2018, 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, 2018, 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, 2018 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

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PART II

ITEM 1. LEGAL PROCEEDINGS

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment related disputes.

In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.

ITEM 1A. RISK FACTORS

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

In addition to the information set forth in this report, you should carefully consider the risk factors discussed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2017. Except as disclosed in our 424(b)(3) prospectus, which we refer to as the merger prospectus, filled by us with the SEC on October 25, 2018 in connection with our pending merger with Energen, which contains, among other things, additional risk factors relating to such merger, there have been no material changes in our risk factors from those described in our Annual Report on Form 10-K for the year ended December 31, 2017.

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ITEM 6.    EXHIBITS

EXHIBIT INDEX

Exhibit Number	Description
2.1#	Agreement and Plan of Merger, dated as of August 14, 2018, by and among Diamondback Energy, Inc., Sidewinder Merger Sub Inc. and Energen Corporation (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on August 15, 2018).
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).
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 October 28, 2016, among Diamondback Energy, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (including the form of Diamondback Energy, Inc.’s 4.750 % Senior Notes due 2024) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on November 2, 2016).
4.5	First Supplemental Indenture, dated as of September 25, 2018, among Diamondback Energy, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on October 1, 2018).
4.6	Registration Rights Agreement, dated September 25, 2018, among Diamondback Energy, Inc., the guarantors party thereto and Merrill Lynch, Pierce, Fenner & Smith Incorporated and Goldman Sachs & Co. LLC (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on October 1, 2018).
4.7	Indenture, dated as of December 20, 2016, among Diamondback Energy, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (including the form of Diamondback Energy, Inc.’s 5.375% Senior Notes due 2025) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 21, 2016).
4.8	First Supplemental Indenture, dated as of January 29, 2018, among Diamondback Energy, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on January 30, 2018).
4.9	Registration Rights Agreement, dated as of February 28, 2017, by and among Diamondback Energy, Inc., Brigham Resources, LLC, Brigham Resources Operating, LLC and Brigham Resources Upstream Holdings, LP (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on March 6, 2017).

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Exhibit Number	Description
4.10*	Registration Rights Agreement, dated October 31, 2018, by and between Diamondback Energy, Inc. and Ajax Resources, LLC.
10.1	Eighth Amendment to the Second Amended and Restated Credit Agreement, dated as of October 26, 2018, by and among Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries of Diamondback Energy, Inc., as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on November 1, 2018).
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**	Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
32.2**	Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Taxonomy Extension Schema Document.
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase.
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*	XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document.

______________

*	Filed herewith.
**	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.
#	Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant hereby undertakes to furnish supplementally copies of any of the omitted schedules upon request by the SEC.

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SIGNATURES

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

		DIAMONDBACK ENERGY, INC.
Date:	November 7, 2018	/s/ Travis D. Stice
		Travis D. Stice
		Chief Executive Officer
		(Principal Executive Officer)
Date:	November 7, 2018	/s/ Teresa L. Dick
		Teresa L. Dick
		Chief Financial Officer
		(Principal Financial and Accounting Officer)

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EX-4.10

Exhibit 4.10

REGISTRATION RIGHTS AGREEMENT

This REGISTRATION RIGHTS AGREEMENT, dated as of October 31, 2018 (this “Agreement”), is by and among Diamondback Energy, Inc., a Delaware corporation (the “Company”), and the holders of Common Stock listed on the signature page hereof.

RECITALS

WHEREAS, as of July 22, 2018, the Company entered into a Purchase and Sale Agreement by and among Ajax Resources, LLC, Diamondback E&P LLC and the Company (the “Purchase Agreement”);

WHEREAS, under the Purchase Agreement, the Holders will receive shares of common stock, par value $0.01 per share, of the Company (the “Common Stock”); and

WHEREAS, resales by the Holders of the Common Stock may be required to be registered under the Securities Act and applicable state securities laws, depending upon the status of a Holder or the intended method of distribution of the Common Stock.

NOW, THEREFORE, in consideration of the premises, mutual covenants and agreements hereinafter contained and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

ARTICLE I - DEFINITIONS

1.1Definitions.

(a)For purposes of this Agreement, the following terms shall have the meanings specified in this Section 1.1; provided, however, that capitalized terms used but not defined herein shall have the meaning ascribed to such terms in the Purchase Agreement.

“Affiliate” means, with respect to any Person, any Person who, directly or indirectly through one or more intermediaries, controls, is controlled by or is under common control with any Person.

“Approved Block Trade” means a block sale or non-marketed offering of Registrable Securities for aggregate proceeds reasonably expected to exceed $100 million that does not require the Company to (i) enter into an underwriting or similar agreement, (ii) enter into any “lock up” agreement in which its ability to issue shares is restricted, (iii) participate in a “road show” or other marketing efforts or (iv) otherwise impose further material restrictions or burdens on the Company.

“Automatic Shelf Registration Statement” means an “Automatic Shelf Registration Statement,” as defined in Rule 405 under the Securities Act.

“Beneficial Ownership” and terms of similar import shall be as defined under and determined pursuant to Rule 13d-3 promulgated under the Exchange Act.

“Business Day” means any day on which Nasdaq is open for trading.

“Exchange Act” means the Securities Exchange Act of 1934, as amended, or any similar federal statute, and the rules and regulations promulgated by the SEC thereunder.

“Excluded Registration” means a registration under the Securities Act of (i) securities pursuant to one or more Demand Requests pursuant to Section 2.1 hereof, (ii) securities registered on Form S-8 or any similar successor form and (iii) securities registered to effect the acquisition of or combination with another Person.

“Existing Holders” means any securityholder who has registration rights pursuant to the Existing Registration Rights Agreement.

“Existing Registration Rights Agreement” means that certain Registration Rights Agreement dated as of February 28, 2018 by and among the Company and the holders of Common Stock listed on the signature pages thereto, as may be amended from time to time.

“Holder” means (i) a securityholder listed on the signature page hereof and (ii) any direct or indirect transferee of any such securityholder, including any securityholder that receives shares of Common Stock upon a distribution or liquidation of a Holder, who has been assigned the rights of the transferor Holder under this Agreement in accordance with Section 2.8.

“Nasdaq” means the Nasdaq Global Select Market.

“Person” or “person” means any individual, corporation, partnership, limited liability company, joint venture, association, joint-stock company, trust, unincorporated organization or government or other agency or political subdivision thereof.

“Prospectus” means the prospectus (including any preliminary, final or summary prospectus) included in any Registration Statement, all amendments and supplements to such prospectus and all other material incorporated by reference in such prospectus.

“Overnight Underwritten Offering” means an underwritten offering that is launched after the close of trading on one trading day and priced before the open of trading on the next succeeding trading day.

“register,” “registered” and “registration” refer to a registration effected by preparing and filing a Registration Statement in compliance with the Securities Act, and the declaration or ordering of the effectiveness of such Registration Statement.

“Registrable Securities” means, at any time, the Common Stock issued to the Holders pursuant to the Purchase Agreement, including any shares of Common Stock which may be issued or distributed in respect of such shares of Common Stock by way of conversion, concession, stock dividend or stock split or other distribution, recapitalization or reclassification or similar transaction; provided, however, that Registrable Securities shall cease to be Registrable Securities when (i) they have been distributed to the public pursuant to an offering registered under the Securities Act, (ii) they have been distributed, or may legally be distributed in one transaction, to the public pursuant to Rule 144 (or any successor provision) under the Securities Act, (iii) they have been transferred or sold to any Person to whom the rights under this Agreement are not assigned in accordance with this Agreement.

“Registration Expenses” means all expenses (other than Selling Expenses) arising from or incident to the Company’s performance of or compliance with this Agreement, including, without limitation:

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(i) SEC, stock exchange, Financial Industry Regulatory Authority, Inc. and other registration and filing fees; (ii) all fees and expenses incurred in connection with complying with any securities or blue sky laws (including, without limitation, fees, charges and disbursements of counsel in connection with blue sky qualifications of the Registrable Securities); (iii) all printing, messenger and delivery expenses; (iv) the fees, charges and disbursements of counsel to the Company and of its independent public accountants, reserve engineers, and any other accounting and legal fees, charges and expenses incurred by the Company (including, without limitation, any expenses arising from any special audits or “comfort” letters required in connection with or incident to any registration); (v) the fees and expenses incurred in connection with the listing of the Registrable Securities on Nasdaq (or the New York Stock Exchange or any other national securities exchange on which the Common Stock may then be listed) or the quotation of Registrable Securities on any inter-dealer quotation system; (vi) the fees and expenses incurred by the Company in connection with the road show, if any, for the Marketed Underwritten Shelf Takedown; and (vii) reasonable fees and expenses of counsel to the Holders in connection with the filing or amendment of any Registration Statement or Prospectus hereunder; provided that, with respect to any offering, Registration Expenses shall only include such fees and expenses (not exceed $50,000 in the aggregate) of one counsel to the Holders and one local counsel per jurisdiction with respect to any offering (which, in each case, shall be chosen by the Holders of a majority of Registrable Securities to be included in such offering).

“Registration Statement” means any registration statement of the Company that covers the resale of any Registrable Securities pursuant to the provisions of this Agreement filed with, or to be filed with, the SEC under the rules and regulations promulgated under the Securities Act, including the related Prospectus, amendments and supplements to such registration statement, including pre- and post-effective amendments, and all exhibits, financial information and all other material incorporated by reference in such registration statement or Prospectus.

“Required Holders” means Holders who then own beneficially more than 50% of the Registrable Securities.

“Rule 144” means Rule 144 promulgated by the SEC pursuant to the Securities Act, as such rule may be amended from time to time, or any similar rule or regulation hereafter adopted by the SEC as a replacement thereto having substantially the same effect as such rule.

“Same-Day Offering” means an underwritten offering that is launched before the open of trading on one trading day and priced before the open of trading or after the close of trading on such same trading day.

“SEC” means the Securities and Exchange Commission or any other Federal agency at the time administering the Securities Act.

“Securities Act” means the Securities Act of 1933, as amended, or any similar Federal statute, and the rules and regulations promulgated by the SEC thereunder.

“Selling Expenses” means the underwriting fees, discounts and commissions, placement fees of underwriters, broker commissions and any transfer taxes, in each case, applicable to all Registrable Securities registered by the Holders and the fees and expenses of counsel engaged by any Holder (other than expenses for counsel that are the Company’s expense under the definition of Registration Expenses).

“Shelf Registration Statement” means a “shelf” registration statement of the Company that covers all the Registrable Securities (and may cover other securities of the Company) on Form S-3 and under Rule 415 under the Securities Act or, if the Company is not then eligible to file on Form S-3, on Form S-1

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or any other appropriate form under the Securities Act, or any successor rule that may be adopted by the SEC, including without limitation any such registration statement filed pursuant to Section 2.1, and all amendments and supplements to such “shelf” registration statement, including post-effective amendments, in each case, including the Prospectus contained therein, all exhibits thereto and any document incorporated by reference therein.

(b)For purposes of this Agreement, the following terms have the meanings set forth in the sections indicated:

Term	Section
Advice	2.5
Agreement	Introductory Paragraph
Blackout Period	2.4(s)
Common Stock	Recitals
Company	Introductory Paragraph
Company Notice	2.1(c)
Company Underwritten Offering	2.3
Demand Request	2.1(c)
Effective Date	2.1(a)
Marketed Underwritten Shelf Takedown	2.1(b)
Material Adverse Effect	2.2(b)
Participating Majority	2.1(d)
Purchase Agreement	Recitals
Records	2.4(l)
Requesting Holder	2.1(c)
Seller Affiliates	2.7
Suspension Period	2.1(f)
Suspension Notice	2.5
Underwritten Shelf Takedown	2.1(b)

1.2Other Definitional and Interpretive Matters.Unless otherwise expressly provided or the context otherwise requires, for purposes of this Agreement the following rules of interpretation apply.

(a)When calculating the period of time before which, within which or following which any act is to be done or step taken pursuant to this Agreement, the date that is the reference date in calculating such period is excluded. If the last day of such period is a non‑Business Day, the period in question ends on the next succeeding Business Day.

(b)Any reference in this Agreement to $ means U.S. dollars.

(c)Any reference in this Agreement to gender includes all genders, and words imparting the singular number also include the plural and vice versa.

(d)The provision of a Table of Contents, the division of this Agreement into Articles, Sections and other subdivisions and the insertion of headings are for convenience of reference only and do not affect, and should not be utilized in, the construction or interpretation of this Agreement.

(e)All references in this Agreement to any “Article” or “Section” are to the corresponding Article or Section of this Agreement.

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(f)The words “herein,” “hereinafter,” “hereof,” and “hereunder” refer to this Agreement as a whole and not merely to a subdivision in which such words appear unless the context otherwise requires.

(g)The word “including” or any variation thereof means “including, but not limited to,” and does not limit any general statement that it follows to the specific or similar items or matters immediately following it.

ARTICLE II- REGISTRATION RIGHTS

2.1Shelf Registration.

(a)The Company will prepare, file (to the extent not previously filed) and use its reasonable best efforts to cause to become effective no later than the 30th day following the date of this Agreement (the “Effective Date”), a Shelf Registration Statement (which Shelf Registration Statement shall be an Automatic Shelf Registration Statement if the Company is then eligible to file an Automatic Shelf Registration Statement), registering for resale the Registrable Securities under the Securities Act. The plan of distribution indicated in the Shelf Registration Statement will include all such methods of sale as any Holder may reasonably request in writing at least five Business Days prior to the filing of the Shelf Registration Statement and that can be included in the Shelf Registration Statement under the rules and regulations of the SEC. Until the earlier of (a) three years after the Effective Date or (b) such time as all Registrable Securities cease to be Registrable Securities or the Company is no longer eligible to maintain a Shelf Registration Statement, the Company shall use its reasonable best efforts to keep current and effective such Shelf Registration Statement and file such supplements or amendments to such Shelf Registration Statement (or file a new Shelf Registration Statement (which Shelf Registration Statement shall be an Automatic Shelf Registration Statement if the Company is then eligible to file an Automatic Shelf Registration Statement) when such preceding Shelf Registration Statement expires pursuant to the rules of the SEC) as may be necessary or appropriate to keep such Shelf Registration Statement continuously effective and useable for the resale of all Registrable Securities under the Securities Act. Any Shelf Registration Statement when declared effective (including the documents incorporated therein by reference) will comply in all material respects as to form with all applicable requirements of the Securities Act and the Exchange Act and will not contain an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein not misleading.

(b)Any one or more Holders of Registrable Securities may request to sell all or any portion of their Registrable Securities in an underwritten offering that is registered pursuant to the Shelf Registration Statement (each, an “Underwritten Shelf Takedown”); provided, however, that the Holders, in the aggregate, will be entitled to make a demand for only one Underwritten Shelf Takedown and only if the proceeds from the sale of Registrable Securities in the Underwritten Shelf Takedown (before the deduction of underwriting discounts) is reasonably expected to exceed, in the aggregate, $75 million. At the request of such Holders, the plan of distribution for the one Underwritten Shelf Takedown shall include a customary “road show” (including an “electronic road show”) or other substantial marketing effort by the Company and the underwriters over a period not to exceed 24 hours (a “Marketed Underwritten Shelf Takedown”). If the Underwritten Shelf Takedown is not a Marketed Underwritten Shelf Takedown, the Company and its management will not be required to participate in a roadshow or other marketing effort.

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(c)The request (a “Demand Request”) for the Underwritten Shelf Takedown shall be made by the Holder or Holders making such request (the “Requesting Holder”) by giving written notice to the Company. The Demand Request shall specify the approximate number of Registrable Securities to be sold in the Underwritten Shelf Takedown and the expected price range of securities to be sold in such Underwritten Shelf Takedown. Within five Business Days after receipt of any Demand Request, the Company shall send written notice of such requested Underwritten Shelf Takedown to all other Holders of Registrable Securities (the “Company Notice”) and shall include in such Underwritten Shelf Takedown all Registrable Securities with respect to which the Company has received written requests for inclusion therein within five Business Days after sending the Company Notice.

(d)The Company shall select one or more nationally prominent firms of investment bankers reasonably acceptable to the Participating Majority to act as the managing underwriter or underwriters in connection with such Underwritten Shelf Takedown. The “Participating Majority” shall mean, with respect to the Underwritten Shelf Takedown, the Holder(s) of a majority of the Registrable Securities requested to be included in such Underwritten Shelf Takedown. All Holders proposing to distribute their securities through such underwriting shall enter into an underwriting agreement with such underwriter or underwriters in accordance with Section 2.1(g). The Company will use its reasonable best efforts to cause members of senior management to cooperate with the underwriter(s) in connection with the Underwritten Shelf Takedown and make themselves available to participate in the marketing process in connection with the Underwritten Shelf Takedown as requested by the managing underwriter(s) and providing such additional information reasonably requested by the managing underwriter(s) (in addition to the minimum information required by law, rule or regulation) in any prospectus relating to the Underwritten Shelf Takedown.

(e)If the managing underwriter(s) for such Underwritten Shelf Takedown advise the Company and the participating Holders in writing that, in their opinion, marketing factors require a limitation of the amount of securities to be underwritten (including Registrable Securities) because the amount of securities to be underwritten is likely to have an adverse effect on the marketability of the offering, then the Company shall so advise all Holders of Registrable Securities and the Existing Holders which would otherwise be underwritten pursuant hereto, and the amount of Registrable Securities that may be included in the underwriting shall be allocated among the participating Holders and participating Existing Holders, (i) first among the participating Holders as nearly as possible on a pro rata basis based on the total amount of Registrable Securities held by such Holders requested to be included in such underwriting and (ii) second to the extent all Registrable Securities requested to be included in such underwriting by the participating Holders have been included, to any participating Existing Holders and other Persons pursuant to contractual registration rights as nearly as possible on a pro rata basis based on the total amount of Registrable Securities (as defined in the Existing Registration Rights Agreement and other contractual registration rights) held by such Existing Holders and other Persons requested to be included in such underwriting. The Company shall prepare preliminary and final prospectus supplements for use in connection with the Underwritten Shelf Takedown, containing such additional information as may be reasonably requested by the underwriter(s).

(f)Upon written notice to the Holders of Registrable Securities, the Company shall be entitled to suspend, for a period of time not to exceed the periods specified in Section 2.4(s) (each, a “Suspension Period”), the use of any Registration Statement or Prospectus and shall not be required to amend or supplement the Registration Statement, any related Prospectus or any document incorporated therein by reference if (i) the Company receives any request by the SEC or any other federal or state governmental authority for amendments or supplements to such Registration Statement or Prospectus or for additional information that pertains to such Holders as sellers of Registrable Securities; (ii) the SEC issues any stop order suspending the effectiveness of the Registration Statement covering any or all of the Registrable Securities or the initiation of any proceedings for that purpose; (iii) the Company receives any notification

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with respect to the suspension of the qualification or exemption from qualification of any of the Registrable Securities for sale in any jurisdiction, or the initiation or threatening of any proceeding for such purpose; and (iv) the board of directors, chief executive officer or chief financial officer of the Company determines in its or his or her reasonable good faith judgment that the Registration Statement or any Prospectus may contain an untrue statement of a material fact or may omit any fact necessary to make the statements in the Registration Statement or Prospectus not misleading; provided, that the Company shall use its good faith efforts to amend the Registration Statement or Prospectus to correct such untrue statement or omission as promptly as reasonably practicable, unless the Company determines in good faith that such amendment would reasonably be expected to have a materially detrimental effect on the Company. The Holders acknowledge and agree that written notice of any Suspension Period may constitute material non-public information regarding the Company and shall keep the existence and contents of any such written notice confidential.

(g)If requested by the managing underwriter(s) for the Underwritten Shelf Takedown, the Company shall enter into an underwriting agreement with the underwriters for such offering, such agreement to be in form and substance (including with respect to representations and warranties by the Company) as is customarily given by the Company to underwriters in an underwritten public offering, and to contain indemnities generally to the effect and to the extent provided in Section 2.7. The Holders of Registrable Securities participating in the Underwritten Shelf Takedown shall be parties to such underwriting agreement and shall be required to make customary representations and warranties, in each case subject to the requirements of the managing underwriter(s), in connection with any such registration or transfer, including that, at such time, (A) such Holder owns his, her or its Registrable Securities to be sold or transferred free and clear of all liens, claims and encumbrances, (B) such Holder has power and authority to effect such transfer or sale, (C) such transfer or sale by such Holder contemplated by such underwriting agreement, and such Holder’s entry into such underwriting agreement, will not constitute a breach of any agreements to which such Holder is a party or by which such Holder is bound, (D) such transfer or sale contemplated by such underwriting agreement, and such Holder’s entry into such underwriting agreement, shall not constitute a breach or violation of such Holder’s organizational documents, if the Holder is an entity, or any law applicable to such Holder and (E) such matters pertaining to compliance with securities laws as may be reasonably requested. No Holder may participate in the Underwritten Shelf Takedown unless such Holder agrees to sell its Registrable Securities on the basis provided in such underwriting agreement and completes and executes all questionnaires, beneficial ownership information, powers of attorney, customary indemnities and other documents reasonably required by the managing underwriter(s) under the terms of such underwriting agreement. Each participating Holder may, at its option, require that any or all of the conditions precedent to the obligations of such underwriters under such underwriting agreement also be conditions precedent to its obligations.

(h)Each of the Holders hereby agrees (a) to cooperate with the Company and to furnish to the Company all such information regarding such Holder, its ownership of Registrable Securities and the disposition of such securities in connection with the preparation of the Registration Statement and any filings with any state securities commission as the Company may reasonably request, (b) to the extent required by the Securities Act, to deliver or cause delivery of the Prospectus contained in the Registration Statement, any amendment or supplement thereto, to any purchaser of Registrable Securities covered by the Registration Statement from the Holder and (c) if requested by the Company, to notify the Company of any sale of Registrable Securities by such Holder.

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(i)Notwithstanding anything to the contrary contained herein, after receiving a written request for an Underwritten Shelf Takedown, the Company may elect to effect an underwritten primary registration or offering, as the case may be, for its own benefit in lieu of the Underwritten Shelf Takedown if the Company’s board of directors believes that such primary registration or offering, as the case may be, would be in the best interests of the Company (each such election, a “Company Preemption”). If the Company so elects to effect a primary registration or offering, the Company shall give prompt written notice (which shall be given not later than 20 days after the date of the Demand Request) to all Holders of its intention to effect such a registration or offering and shall afford the Holders the rights contained in Section 2.2 with respect to a Piggyback Registration. In the event that the Company so elects to effect a primary registration or offering after receiving a request for the Underwritten Shelf Takedown, the Company shall use its reasonable best efforts to have the Registration Statement declared effective by the SEC or undertake the Underwritten Shelf Takedown, as the case may be, as soon as reasonably practicable. Any Underwritten Shelf Takedown that is subject to a Company Preemption shall not be deemed to be a Demand Request for purposes of Section 2.1(b).

2.2Piggyback Registrations.

(a)If the Company elects a Company Preemption and the form of registration statement to be used permits the registration of Registrable Securities, the Company shall give prompt written notice to each Holder of Registrable Securities (which notice shall be given not less than (i) 15 days prior to the anticipated filing date or (ii) two Business Days in the case of an Overnight Underwritten Offering, Same-Day Offering or similar “bought deal”), which notice shall offer each such Holder the opportunity to include any or all of its or his Registrable Securities in such registration statement, subject to the limitations contained in Section 2.2(b) hereof. Each Holder who desires to have its or his Registrable Securities included in such registration statement shall so advise the Company in writing (stating the number of shares desired to be registered) within ten days (or one Business Day in the case of an Overnight Underwritten Offering, Same-Day Offering or similar “bought deal”) after the date of such notice from the Company. Any Holder shall have the right to withdraw such Holder’s request for inclusion of such Holder’s Registrable Securities in any registration statement pursuant to this Section 2.2(a) by giving written notice to the Company of such withdrawal. Subject to Section 2.2(b) below, the Company shall include in such registration statement all such Registrable Securities so requested to be included therein; provided, however, that the Company may at any time withdraw or cease proceeding with any such registration if it shall at the same time withdraw or cease proceeding with the registration of all other equity securities originally proposed to be registered. For the avoidance of doubt, any registration or offering pursuant to this Section 2.2 shall not be considered an Underwritten Shelf Takedown for purposes of Section 2.1 of this Agreement.

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(b)With respect to any registration pursuant to Section 2.2(a), if the managing underwriter(s) advise the Company that the inclusion of Registrable Securities requested to be included in the Registration Statement will materially and adversely affect the marketability of the offering (a “Material Adverse Effect”), the Company will be obligated to include in the Registration Statement (after all such shares for its own account or for the account of any Existing Holder), as to each Requesting Holder, only a portion of the shares such Holder has requested be registered equal to the product of: (i) the ratio which such Holder’s requested shares bears to the total number of shares requested to be included in such Registration Statement by all Persons (including Holders) who have requested (pursuant to this Agreement or other contractual registration rights) that their shares be included in such Registration Statement; and (ii) the maximum number of Registrable Securities that the managing underwriter advises may be sold in an offering covered by the Registration Statement without a Material Adverse Effect. If, as a result of the provisions of this Section 2.2(b), any Holder shall not be entitled to include all Registrable Securities in a registration that such Holder has requested to be so included, such Holder may withdraw such Holder’s request to include Registrable Securities in such Registration Statement. No Person may participate in any Registration Statement pursuant to Section 2.2(a) unless such Person (i) agrees to sell such person’s Registrable Securities on the basis provided in any underwriting arrangements approved by the Company and (ii) completes and executes all questionnaires, powers of attorney, indemnities, underwriting agreements and other documents, each in customary form, reasonably required under the terms of such underwriting arrangements; provided, however, that no such Person shall be required to (A) make any representations or warranties in connection with any such registration other than representations and warranties as to (1) such Person’s ownership of his or its Registrable Securities to be sold or transferred free and clear of all liens, claims and encumbrances, (2) such Person’s power and authority to effect such transfer and (3) such matters pertaining to compliance with securities laws as may be reasonably requested or (B) undertake any indemnification obligations to the Company or the underwriters with respect thereto except as otherwise provided in Section 2.7.

2.3Holdback Agreement.By electing to include Registrable Shares in a Company registration statement pursuant to Section 2.2, the Holder shall be deemed to have agreed not to effect any sale or distribution of securities of the Company of the same or similar class or classes of the securities included in the Company registration statement or any securities convertible into or exchangeable or exercisable for such securities, including a sale pursuant to Rule 144, during such periods as reasonably requested (but in no event for a period longer than 60 days following (i) the effective date of such Company registration statement or (ii) the date of the applicable Prospectus; provided each of the executive officers and directors of the Company that hold shares of Common Stock of the Company or securities convertible into or exchangeable or exercisable for shares of Common Stock of the Company are subject to the same restriction for the entire time period required of the Holders hereunder) by the representatives of the underwriters, if an underwritten offering by the Company (a “Company Underwritten Offering”); provided further, for the avoidance of doubt, that such restrictions shall only apply if the Holders are able to sell Registrable Securities in such a Company Underwritten Offering. The provisions of this Section 2.3 will no longer apply to a Holder once such Holder ceases to hold at least 1% of the Registrable Securities acquired as a result of the transactions contemplated in the Purchase Agreement. The provisions of thisSection 2.3 shall not apply to (i) any transfer of Registrable Securities by a Holder to (a) any stockholder, member, managing member, general or limited partner of any Holder, or (b) any investment fund managed by any of such persons or (c) any other Affiliate of any Holder, or to any other Affiliate of a Holder, so long as such transfer is not for value and any such person agrees to and remains to be bound hereby, (ii) the entry by any Holder of a bona fide pledge of any Registrable Securities (and any foreclosure on any such pledge) and (iii) any hedging transaction with respect to an index or basket of securities where the equity securities of the Company constitute a de minimis amount.

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2.4Registration Procedures.In connection with the registration and sale of Registrable Securities pursuant to this Agreement, the Company will use its reasonable best efforts to effect the registration and the sale of such Registrable Securities in accordance with the intended method of disposition thereof, and pursuant thereto the Company will:

(a)if the Registration Statement is not automatically effective upon filing, use reasonable best efforts to cause such Registration Statement to become effective as promptly as reasonably practicable;

(b)promptly notify each selling Holder, promptly after the Company receives notice thereof, of the time when such Registration Statement has been declared effective or a supplement to any prospectus forming a part of such Registration Statement has been filed;

(c)after the Registration Statement becomes effective, promptly notify each selling Holder of any request by the SEC that the Company amend or supplement such Registration Statement or Prospectus;

(d)prepare and file with the SEC such amendments and supplements to the Registration Statement and the Prospectus used in connection therewith as may be reasonably necessary to keep the Registration Statement effective during the period set forth in, and subject to the terms and conditions of, this Agreement, and to comply with the provisions of the Securities Act with respect to the disposition of all Registrable Securities covered by the Registration Statement for the period required to effect the distribution of the Registrable Securities as set forth in Section 2 hereof;

(e)furnish to the selling Holders such numbers of copies of such Registration Statement, each amendment and supplement thereto, each Prospectus (including each preliminary Prospectus and Prospectus supplement) and such other documents as the Holder and any underwriter(s) may reasonably request in order to facilitate the disposition of the Registrable Securities;

(f)use its reasonable best efforts to register and qualify the Registrable Securities under such other securities or blue-sky laws of such jurisdictions as shall be reasonably requested by the Holders and any underwriter(s) and do any and all other acts and things that may be reasonably necessary or advisable to enable the Holders and any underwriter(s) to consummate the disposition of the Registrable Securities in such jurisdictions; provided, however, that the Company shall not be required in connection therewith or as a condition thereto to qualify to do business in or to file a general consent to service of process in any jurisdiction, unless the Company is already subject to service in such jurisdiction and except as may be required by the Securities Act, or subject itself to taxation in any such jurisdiction, unless the Company is already subject to taxation in such jurisdiction;

(g)use its reasonable best efforts to cause all such Registrable Securities to be listed on a national securities exchange or trading system and each securities exchange and trading system (if any) on which similar equity securities issued by the Company are then listed;

(h)provide a transfer agent and registrar for the Registrable Securities and provide a CUSIP number for all such Registrable Securities, in each case not later than the effective date of the Registration Statement;

(i)use its reasonable best efforts to furnish, on the date that shares of Registrable Securities are delivered to the underwriters for sale, if such securities are being sold through underwriters, (i) an opinion, dated as of such date, of the counsel representing the Company for the purposes of such registration, in form

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and substance as is customarily given to underwriters by the Company in an underwritten public offering, addressed to the underwriters, (ii) a letter dated as of such date, from the independent public accountants of the Company, in form and substance as is customarily given by independent public accountants to underwriters in an underwritten public offering, addressed to the underwriters and (iii) an engineers’ reserve report letter as of such date, from the independent petroleum engineers of the Company, in form and substance as is customarily given by independent petroleum engineers to underwriters in an underwritten public offering, addressed to the underwriters;

(j)if requested by the Holders, cooperate with the Holders and the managing underwriter(s) (if any) to facilitate the timely preparation and delivery of certificates (which shall not bear any restrictive legends unless required under applicable law) representing securities sold under the Registration Statement, and enable such securities to be in such denominations and registered in such names as such Holders or the managing underwriter (if any) may request and keep available and make available to the Company’s transfer agent prior to the effectiveness of such Registration Statement a supply of such certificates;

(k)in the event of any underwritten public offering, enter into and perform its obligations under an underwriting agreement, in form and substance as is customarily given by the Company to underwriters in an underwritten public offering, with the underwriter(s) of such offering;

(l)upon execution of confidentiality agreements in form and substance reasonably satisfactory to the Company, promptly make available for inspection by the selling Holders, any underwriter(s) participating in any disposition pursuant to such Registration Statement, and any attorney or accountant or other agent retained by any such underwriter or selected by the selling Holders, all financial and other records, pertinent corporate documents, and properties of the Company reasonably requested (collectively, “Records”), and use reasonable best efforts to cause the Company’s officers, directors, employees, and independent accountants to supply all information reasonably requested by any such seller, underwriter, attorney, accountant, or agent, in each case, as necessary or advisable to verify the accuracy of the information in such Registration Statement and to conduct appropriate due diligence in connection therewith; provided, that Records that the Company determines, in good faith, to be confidential and that it notifies the selling Holders are confidential shall not be disclosed by the selling Holders unless the release of such Records is ordered pursuant to a subpoena or other order from a court of competent jurisdiction or is otherwise required by applicable law. Each Holder agrees that information obtained by it as a result of such inspections shall be deemed confidential and shall not be used by it or its affiliates (other than with respect to such Holders’ due diligence) unless and until such information is made generally available to the public, and further agrees that, upon learning that disclosure of such Records is sought in a court of competent jurisdiction, to the extent permitted and to the extent practicable it shall give notice to the Company and allow the Company to undertake appropriate action to prevent disclosure of the Records deemed confidential;

(m)promptly notify the selling Holders and any underwriter(s) of the notification to the Company by the SEC of its initiation of any proceeding with respect to the issuance by the SEC of any stop order suspending the effectiveness of the Registration Statement, and in the event of the issuance of any stop order suspending the effectiveness of such Registration Statement, or of any order suspending or preventing the use of any related Prospectus or suspending the qualification of any Registrable Securities included in such Registration Statement for sale in any jurisdiction, use its reasonable best efforts to obtain promptly the withdrawal of such order;

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(n)promptly notify the selling Holders and any underwriter(s) at any time when a Prospectus relating thereto is required to be delivered under the Securities Act of the occurrence of any event as a result of which the Prospectus included in the Registration Statement, as then in effect, includes an untrue statement of a material fact or omits to state any material fact required to be stated therein or necessary to make the statements therein not misleading in light of the circumstances under which they were made, and at the request of any Holder promptly prepare and furnish to such Holder a reasonable number of copies of a supplement to or an amendment of such Prospectus, or a revised Prospectus, as may be necessary so that, as thereafter delivered to the purchasers of such securities, such Prospectus shall not include an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein not misleading in light of the circumstances under which they were made (following receipt of any supplement or amendment to any Prospectus, the selling Holders shall deliver such amended, supplemental or revised Prospectus in connection with any offers or sales of Registrable Securities, and shall not deliver or use any Prospectus not so supplemented, amended or revised);

(o)promptly notify the selling Holders and any underwriter(s) of the receipt by the Company of any notification with respect to the suspension of the qualification of any Registrable Securities for sale under the applicable securities or blue sky laws of any jurisdiction;

(p)make available to each Holder (i) promptly after the same is prepared and publicly distributed, filed with the SEC, or received by the Company, one copy of each Registration Statement and any amendment thereto, each preliminary Prospectus and Prospectus and each amendment or supplement thereto, each letter written by or on behalf of the Company to the SEC or the staff of the SEC (or other governmental agency or self-regulatory body or other body having jurisdiction, including any domestic or foreign securities exchange), and each item of correspondence from the SEC or the staff of the SEC (or other governmental agency or self‑regulatory body or other body having jurisdiction, including any domestic or foreign securities exchange), in each case relating to such Registration Statement, and (ii) such number of copies of each Prospectus, including a preliminary Prospectus, and all amendments and supplements thereto and such other documents as any Holder or any underwriter may reasonably request in order to facilitate the disposition of the Registrable Securities. The Company will promptly notify the Holders of the effectiveness of each Registration Statement or any post-effective amendment or the filing of any supplement or amendment to such Registration Statement or of any Prospectus supplement. The Company will promptly respond to any and all comments received from the SEC, with a view towards causing each Registration Statement or any amendment thereto to be declared effective by the SEC as soon as practicable and shall file an acceleration request, if necessary, as soon as practicable following the resolution or clearance of all SEC comments or, if applicable, following notification by the SEC that any such Registration Statement or any amendment thereto will not be subject to review;

(q)take no direct or indirect action prohibited by Regulation M under the Exchange Act; provided, that, to the extent that any prohibition is applicable to the Company, the Company will take all reasonable action to make any such prohibition inapplicable;

(r)take such other actions as are reasonably necessary in order to facilitate the disposition of such Registrable Securities; and

(s)notwithstanding any other provision of this Agreement, the Company shall not be required to file a Registration Statement (or any amendment thereto) or effect the requested Underwritten Shelf Takedown (or, if the Company has filed a Shelf Registration Statement and has included Registrable Securities therein, the Company shall be entitled to suspend the offer and sale of Registrable Securities pursuant to such Registration Statement) for a period of up to 60 days if (i) the board of directors determines

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that a postponement is in the best interest of the Company and its stockholders generally due to a proposed transaction involving the Company and determines in good faith that the Company’s ability to pursue or consummate such a transaction would be materially and adversely affected by any required disclosure of such transaction in the Shelf Registration Statement, (ii) the board of directors determines such registration would render the Company unable to comply with applicable securities laws or (iii) the board of directors determines such registration would require disclosure of material information that the Company has a bona fide business purpose for preserving as confidential (any such period, a “Blackout Period”); provided, however, that in no event shall any Blackout Period and/or Suspension Period collectively exceed an aggregate of 90 days in any 12-month period.

2.5Suspension of Dispositions.Each Holder agrees by acquisition of any Registrable Securities that, upon receipt of any notice (a “Suspension Notice”) from the Company of the occurrence of any event of the kind described in Section 2.4(f), Section 2.4(n) or Section 2.4(s), such Holder will forthwith discontinue disposition of Registrable Securities pursuant to the Registration Statement until such Holder’s receipt of the copies of the supplemented or amended Prospectus, or until it is advised in writing (the “Advice”) by the Company that the use of the Prospectus may be resumed, and has received copies of any additional or supplemental filings which are incorporated by reference in the Prospectus. The Company shall extend the period of time during which the Company is required to maintain the Registration Statement effective pursuant to this Agreement by the number of days during the period from and including the date of the giving of such Suspension Notice to and including the date such Holder either receives the supplemented or amended Prospectus or receives the Advice. If so directed by the Company, such Holder will deliver to the Company all copies, other than permanent file copies then in such Holder’s possession, of the Prospectus covering such Registrable Securities current at the time of receipt of such notice. The Company shall use its reasonable best efforts and take such actions as are reasonably necessary to render the Advice as promptly as practicable. The Holders acknowledge and agree that receipt of a Suspension Notice may constitute material non-public information regarding the Company and shall keep the existence and contents of any such Suspension Notice confidential. Any Underwritten Shelf Takedown which is suspended because of a Suspension Notice shall not be deemed to be a Demand Request for purposes of Section 2.1(b)unless and until a suspension pursuant to this Section 2.5 is concluded and such Underwritten Shelf Offering is completed.

2.6Registration Expenses.All Registration Expenses shall be borne by the Company.In addition, for the avoidance of doubt, the Company shall pay its internal expenses in connection with the performance of or compliance with this Agreement (including, without limitation, all salaries and expenses of its officers and employees performing legal or accounting duties), the expense of any annual audit or quarterly review, the expense of any liability insurance and the expenses and fees for listing the securities to be registered on each securities exchange on which they are to be listed. All Selling Expenses relating to Registrable Securities registered shall be borne by the Holders of such Registrable Securities pro rata on the basis of the number of Registrable Securities sold.

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2.7Indemnification.

(a)The Company agrees to indemnify and reimburse, to the fullest extent permitted by law, each Holder that is a seller of Registrable Securities, and each of its employees, advisors, agents, representatives, partners, officers, and directors and each Person who controls such Holder (within the meaning of the Securities Act or the Exchange Act) (collectively, the “Seller Affiliates”) (i) against any and all losses, claims, damages, liabilities and expenses, joint or several (including, without limitation, attorneys’ fees and disbursements except as limited by Section 2.7(c)) based upon, arising out of, related to or resulting from any untrue or alleged untrue statement of a material fact contained in any Registration Statement or Prospectus or any amendment thereof or supplement thereto, or any omission or alleged omission of a material fact required to be stated therein or necessary to make the statements therein not misleading, (ii) against any and all losses, liabilities, claims, damages and expenses whatsoever, as incurred, to the extent of the aggregate amount paid in settlement of any litigation or investigation or proceeding by any governmental agency or body, commenced or threatened, or of any claim whatsoever based upon, arising out of, related to or resulting from any such untrue statement or omission or alleged untrue statement or omission, and (iii) against any and all costs and expenses (including reasonable fees, charges and disbursements of counsel) as may be reasonably incurred in investigating, preparing or defending against any litigation, investigation or proceeding by any governmental agency or body, commenced or threatened, or any claim whatsoever based upon, arising out of, related to or resulting from any such untrue statement or omission or alleged untrue statement or omission, or such violation of the Securities Act or Exchange Act, to the extent that any such expense or cost is not paid under subparagraph (i) or (ii) above; except insofar as any such statements are made in reliance upon information furnished to the Company in writing by such seller or any Seller Affiliate expressly for use therein. The reimbursements required by this Section 2.7(a) will be made by periodic payments during the course of the investigation or defense, as and when bills are received or expenses incurred.

(b)In connection with any Registration Statement or Prospectus covering the sale of Registrable Securities in which a Holder that is a seller of Registrable Securities is participating, each such Holder will (i) cooperate with and furnish to the Company such information and affidavits as the Company reasonably requests for use in connection with any such Registration Statement or Prospectus or any filings with any state securities commissions, (ii) to the extent required by the Securities Act, deliver or cause delivery of the Prospectus to any purchaser of the Registrable Securities covered by such Prospectus from such Holder and (iii) if requested by the Company, notify the Company of any sale of Registrable Securities by such Holder, and to the fullest extent permitted by law, each such seller will indemnify the Company and its directors and officers and each Person who controls the Company (within the meaning of the Securities Act or the Exchange Act) against any and all losses, claims, damages, liabilities and expenses (including, without limitation, reasonable attorneys’ fees and disbursements except as limited by Section 2.7(c)) resulting from any untrue statement or alleged untrue statement of a material fact contained in the Registration Statement or Prospectus or any omission or alleged omission of a material fact required to be stated therein or necessary to make the statements therein not misleading, but only to the extent that such untrue statement or alleged untrue statement or omission or alleged omission is contained in any information or affidavit so furnished by such seller or any of its Seller Affiliates in writing expressly for inclusion in the Registration Statement; provided that the obligation to indemnify will be several, not joint and several, among such sellers of Registrable Securities, and the liability of each such seller of Registrable Securities will be in proportion to the amount of Registrable Securities registered by them, and, provided, further, that such liability will be limited to the net amount received by such seller from the sale of Registrable Securities pursuant to such Registration Statement.

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(c)Any Person entitled to indemnification hereunder will (i) give prompt written notice to the indemnifying party of any claim with respect to which it seeks indemnification (provided that the failure to give such notice shall not limit the rights of such Person) and (ii) unless in such indemnified party’s reasonable judgment a conflict of interest between such indemnified and indemnifying parties may exist with respect to such claim, permit such indemnifying party to assume the defense of such claim with counsel reasonably satisfactory to the indemnified party; provided, however, that any Person entitled to indemnification hereunder shall have the right to employ separate counsel and to participate in the defense of such claim, but the fees and expenses of such counsel shall be at the expense of such Person unless (A) the indemnifying party has agreed to pay such fees or expenses or (B) the indemnifying party shall have failed to assume the defense of such claim and employ counsel reasonably satisfactory to such Person. If such defense is not assumed by the indemnifying party as permitted hereunder, the indemnifying party will not be subject to any liability for any settlement made by the indemnified party without its consent (but such consent will not be unreasonably withheld, conditioned or delayed). If such defense is assumed by the indemnifying party pursuant to the provisions hereof, such indemnifying party shall not settle or otherwise compromise the applicable claim unless (i) such settlement or compromise contains a full and unconditional release of the indemnified party or (ii) the indemnified party otherwise consents in writing (which consent will not be unreasonably withheld, conditioned or delayed). An indemnifying party who is not entitled to, or elects not to, assume the defense of a claim will not be obligated to pay the fees and expenses of more than one counsel for all parties indemnified (which shall be chosen by the Holders of a majority of Registrable Securities so indemnified) by such indemnifying party with respect to such claim, unless in the reasonable judgment of any indemnified party, a conflict of interest may exist between such indemnified party and any other of such indemnified parties with respect to such claim, in which event the indemnifying party shall be obligated to pay the reasonable fees and disbursements of such additional counsel or counsels.

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(d)Each party hereto agrees that, if for any reason the indemnification provisions contemplated by Section 2.7(a) or Section 2.7(b) are unavailable to or insufficient to hold harmless an indemnified party in respect of any losses, claims, damages, liabilities or expenses (or actions in respect thereof) referred to therein, then each indemnifying party shall contribute to the amount paid or payable by such indemnified party as a result of such losses, claims, liabilities or expenses (or actions in respect thereof) in such proportion as is appropriate to reflect the relative fault of the indemnifying party and the indemnified party in connection with the actions which resulted in the losses, claims, damages, liabilities or expenses as well as any other relevant equitable considerations. The relative fault of such indemnifying party and indemnified party shall be determined by reference to, among other things, whether the untrue or alleged untrue statement of a material fact or omission or alleged omission to state a material fact relates to information supplied by such indemnifying party or indemnified party, and the parties’ relative intent, knowledge, access to information and opportunity to correct or prevent such statement or omission. The parties hereto agree that it would not be just and equitable if contribution pursuant to this Section 2.7(d) were determined by pro rata allocation (even if the Holders or any underwriters or all of them were treated as one entity for such purpose) or by any other method of allocation which does not take account of the equitable considerations referred to in this Section 2.7(d). The amount paid or payable by an indemnified party as a result of the losses, claims, damages, liabilities or expenses (or actions in respect thereof) referred to above shall be deemed to include any legal or other fees or expenses reasonably incurred by such indemnified party in connection with investigating or, except as provided in Section 2.7(c), defending any such action or claim. Notwithstanding the provisions of this Section 2.7(d), no Holder shall be required to contribute an amount greater than the dollar amount by which the net proceeds received by such Holder with respect to the sale of any Registrable Securities exceeds the amount of damages which such Holder has otherwise been required to pay by reason of any and all untrue or alleged untrue statements of material fact or omissions or alleged omissions of material fact made in any Registration Statement or Prospectus or any amendment thereof or supplement thereto related to such sale of Registrable Securities. No person guilty of fraudulent misrepresentation (within the meaning of Section 11(f) of the Securities Act) shall be entitled to contribution from any person who was not guilty of such fraudulent misrepresentation. The Holders’ obligations in this Section 2.7(d) to contribute shall be several in proportion to the amount of Registrable Securities registered by them and not joint.

If indemnification is available under this Section 2.7, the indemnifying parties shall indemnify each indemnified party to the full extent provided in Section 2.7(a) and Section 2.7(b) without regard to the relative fault of said indemnifying party or indemnified party or any other equitable consideration provided for in this Section 2.7(d) subject, in the case of the Holders, to the limited dollar amounts set forth in Section 2.7(b).

(e)No indemnifying party shall be liable for any settlement effected without its written consent (which consent may not be unreasonably delayed or withheld). Each indemnifying party agrees that it will not, without the indemnified party’s prior written consent, consent to entry of any judgment or settle or compromise any pending or threatened claim, action or proceeding in respect to which indemnification or contribution may be sought hereunder unless the foregoing contains and unconditional release, in form and substance reasonably satisfactory to the indemnified parties, of the indemnified parties from all liability and obligation arising therefrom.

(f)The indemnification and contribution provided for under this Agreement will remain in full force and effect regardless of any investigation made by or on behalf of the indemnified party or any officer, director or controlling Person of such indemnified party and will survive the transfer of securities.

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2. 8Transfer of Registration Rights.The registration rights of a Holder under this Agreement with respect to any Registrable Securities may be transferred or assigned to any purchaser or transferee of Registrable Securities; provided, however, that (i) such Holder shall give the Company written notice prior to the time of such transfer stating the name and address of the transferee and identifying the securities with respect to which the rights under this Agreement are being transferred; (ii) such transferee shall agree in writing, in form and substance reasonably satisfactory to the Company, to be bound as a Holder by the provisions of this Agreement; and (iii) immediately following such transfer the further disposition of such securities by such transferee shall be restricted to the extent set forth under applicable law.

2.9Free Writing Prospectuses.The Company shall not permit any officer, director, underwriter, broker or any other person acting on behalf of the Company to use any free writing prospectus (as defined in Rule 405 under the Securities Act) in connection with any registration statement covering Registrable Securities, without the prior written consent of each participating Holder and any underwriter. No Holder shall, or permit any officer, manager, underwriter, broker or any other person acting on behalf of such Holder to use any free-writing prospectus in connection with any registration statement covering Registrable Securities, without the prior written consent of the Company.

2.10Current Public Information. With a view to making available to the Holders of Registrable Securities the benefits of Rule 144 and Rule 144A promulgated under the Securities Act and other rules and regulations of the SEC that may at any time permit a Holder of Registrable Securities to sell securities of the Company to the public without registration, the Company covenants that it will (i) for as long as the Common Stock is registered pursuant to Section 12(b), Section 12(g) or Section 15(d) of the Exchange Act, use its reasonable best efforts to file in a timely manner all reports and other documents required, if any, to be filed by it under the Securities Act and the Exchange Act and the rules and regulations adopted thereunder and (ii) if it is not required to file such reports, make available information necessary to comply with Rule 144 and Rule 144A, if available with respect to resales of the Registrable Securities under the Securities Act, at all times, all to the extent required from time to time to enable such Holder to sell Registrable Securities to the public without registration under the Securities Act within the limitation of the exemptions provided by (x) Rule 144 and Rule 144A promulgated under the Securities Act (if available with respect to resales of the Registrable Securities), as such rules may be amended from time to time or (y) any other rules or regulations now existing or hereafter adopted by the SEC.

2.11Company Obligations Regarding Transfers. The Company shall instruct the transfer agent to remove any legend, notation or similar designation restricting transferability of the Registrable Securities from the certificates or book-entries evidencing Registrable Securities if such Common Stock (i) is sold pursuant to an effective registration statement under the Securities Act, (ii) is sold or transferred pursuant to Rule 144 (if the transferor is not an Affiliate of the Company) or (iii) is eligible for sale under Rule 144. Each Holder agrees to provide the Company, its counsel and/or the transfer agent with evidence reasonably requested by it in order to cause the removal of such legend, including, as may be appropriate, any information the Company deems necessary to determine that the legend, notation or similar designation is no longer required under the Securities Act or applicable state laws, including a certification that the holder is not an Affiliate of the Company (and a covenant to inform the Company if it should thereafter become an Affiliate and to consent to exchange any certificates or instruments representing the Common Stock for ones bearing an appropriate restrictive legend) and regarding the length of time the Common Stock has been held. Any fees of the Company, the transfer agent and Company counsel associated with the issuance of any legal opinion required by the Company’s transfer agent or the removal of such legend shall be borne by the Company.

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2.12No Conflict of Rights.The Company represents and warrants that except for the Existing Registration Rights Agreement, it is not subject to any registration rights that are superior to, inconsistent with or that in any way violate or subordinate the rights granted to the Holders hereby. The Company shall not, prior to the termination of this Agreement, grant any registration rights that conflict with, or would prevent the Company from performing, the rights granted to the Holders hereby.

2.13Approved Block Trades.To the extent that a Shelf Registration Statement is effective, then in addition to the Underwritten Shelf Takedown specified in Section 2.1(b), the Holders shall have the right, if required by the Securities Act, to request that the Company file a prospectus supplement in connection with up to two (2) Approved Block Trades: provided, however, if an Approved Block Trade occurs prior to the Marketed Underwritten Shelf Takedown, such Approved Block Trade shall constitute the one Marketed Underwritten Shelf Takedown and the holders will no longer be entitled to a Marketed Underwritten Shelf Takedown.

ARTICLE III - TERMINATION

2.13Termination. The provisions of this Agreement shall terminate and be of no further force and effect upon the date when there shall no longer be any Registrable Securities outstanding.

ARTICLE IV - MISCELLANEOUS

4.1Notices. Any notice or other communication required or permitted hereunder shall be in writing and shall be delivered by hand, by facsimile transmission or electronic mail transmission, or by certified or registered mail, postage prepaid and return receipt requested. Notices shall be deemed to have been given upon delivery, if delivered by hand, three days after mailing, if mailed, and upon receipt of an appropriate electronic confirmation, if delivered by facsimile or electronic mail transmission. Notices shall be delivered to the parties at the addresses set forth below:

If to the Company:	Diamondback Energy, Inc. 9400 N. Broadway, Suite 700 Oklahoma City, Oklahoma 73114 Attn: Randall J. Holder, General Counsel Facsimile: (405) 463-6999 Email: rjholder@diamondbackenergy.com
With copies to (which shall not constitute notice):	Akin Gump Strauss Hauer & Feld LLP 1700 Pacific Avenue Suite 4100 Dallas, Texas 75201 Attention: Seth R. Molay Facsimile: (214) 969-4343 Email: smolay@akingump.com
If to any Holder, at its address listed on the signature pages hereof.

Any party may from time to time change its address or designee for notification purposes by giving the other parties prior notice in the manner specified above of the new address or the new designee and the subsequent date upon which the change shall be effective.

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4.2Choice of Law; Exclusive Jurisdiction; Waiver of Jury Trial.

(a)This Agreement shall be constructed, interpreted and enforced in accordance with, and the respective rights and obligations of the parties shall be governed by, the laws of the State of Delaware without regard to principles of conflicts of law.

(b)All actions and proceedings for the enforcement of or based on, arising out of or relating to this Agreement shall be heard and determined exclusively in the Delaware Court of Chancery (or, only if the Delaware Court of Chancery declines to accept jurisdiction over the particular matter, any other court of the State of Delaware, or any federal court sitting in the State of Delaware), and each of the parties hereto hereby (i) irrevocably submits to the exclusive jurisdiction of such courts (and, in the case of appeals, appropriate appellate courts therefrom) in any such action or proceeding, (ii) irrevocably waives the defense of an inconvenient forum to the maintenance of any such action or proceeding, (iii) agrees that it shall not bring any such action in any court other than the Court of Chancery of the State of Delaware (or, only if the Delaware Court of Chancery declines to accept jurisdiction over the particular matter, any other court of the State of Delaware, or any federal court sitting in the State of Delaware), and (iv) irrevocably consents to service of process by first class certified mail, return receipt requested, postage prepaid, to the address at which the Company or Holder, as the case may be, is to receive notice in accordance with Section 4.1. The parties hereto agree that a final judgment in any such action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by applicable law.

(c)Each of the parties hereto hereby irrevocably waives any and all rights to trial by jury in any legal proceeding arising out of or related to this Agreement.

4.3No Third-Party Beneficiaries. This Agreement is for the sole benefit of the parties hereto and their respective successors and permitted assigns and nothing herein, express or implied, is intended to or shall confer upon any other Person any legal or equitable right, benefit or remedy of any nature whatsoever, under or by reason of this Agreement; provided, however, the parties hereto hereby acknowledge that the Persons set forth in Section 2.7 are express third-party beneficiaries of the obligations of the parties hereto set forth in Section 2.7.

4.4Successors and Assigns. Except as otherwise expressly provided herein, this Agreement shall be binding upon and benefit the Company, each Holder and their respective successors and assigns.The Company shall not, directly or indirectly, enter into any merger, consolidation or reorganization in which the Company shall not be the surviving entity unless the surviving entity shall, prior to such merger, consolidation or reorganization, agree in writing to assume the obligations of the Company under this Agreement, and for that purpose references hereunder to “Registrable Securities” shall be deemed to include the common equity interests or other securities, if any, which the Holders would be entitled to receive in exchange for Registrable Securities under any such merger, consolidation or reorganization, provided that, to the extent the Holders receive securities that are by their terms convertible into common equity interests of the issuer thereof, then any such common equity interests as are issued or issuable upon conversion of said convertible securities shall be included within the definition of “Registrable Securities.”

4.5Counterparts. This Agreement may be executed by the parties in separate counterparts (including by means of executed counterparts delivered via facsimile or other electronic means), each of which shall be deemed an original, but all of which together shall constitute one and the same instrument.

19

4.6Severability. In case any provision in this Agreement shall be held invalid, illegal or unenforceable in any respect for any reason, the validity, legality and enforceability of any such provision in every other respect and the remaining provisions shall not in any way be affected or impaired thereby.

4.7No Waivers; Amendments.

(a)No failure or delay on the part of the Company or any Holder in exercising any right, power or remedy hereunder shall operate as a waiver thereof, nor shall any single or partial exercise of any such right, power or remedy preclude any other or further exercise thereof or the exercise of any other right, power or remedy. The remedies provided for herein are cumulative and are not exclusive of any remedies that may be available to the Company or any Holder at law or in equity or otherwise.

(b)Any provision of this Agreement may be amended or waived if, but only if, such amendment or waiver is in writing and is signed by the Company and the Required Holders.

4.8Entire Agreement. This Agreement and the other writings referred to herein or therein or delivered pursuant hereto or thereto, contain the entire agreement between the Holders and the Company with respect to the subject matter hereof and supersede all prior and contemporaneous arrangements or understandings with respect thereto.

4.9Remedies; Specific Performance.

(a)Each Holder shall have all rights and remedies reserved for such Holder pursuant to this Agreement and all rights and remedies which such Holder has been granted at any time under any other agreement or contract and all of the rights which such Holder has under any law or equity. Any Person having any rights under any provision of this Agreement will be entitled to enforce such rights specifically, to recover damages by reason of any breach of any provision of this Agreement and to exercise all other rights granted by law or equity.

(b)The parties hereto recognize and agree that money damages may be insufficient to compensate the Holders of any Registrable Securities for breaches by the Company of the terms hereof and, consequently, that the equitable remedies of injunctive relief and of specific performance of the terms hereof will be available in the event of any such breach. If any action should be brought in equity to enforce any of the provisions of this Agreement, none of the parties hereto shall raise the defense that there is an adequate remedy at law.

4.10Negotiated Agreement. This Agreement was negotiated by the parties with the benefit of legal representation, and any rule of construction or interpretation otherwise requiring this Agreement to be construed or interpreted against any party shall not apply to the construction or interpretation hereof.

[THE REMAINDER OF THIS PAGE IS INTENTIONALLY LEFT BLANK]

20

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed by their respective authorized officers as of the date first written above.

DIAMONDBACK ENERGY, INC.
By:	/s/ Travis D. Stice
Name:	Travis D. Stice
Title:	President & CEO

Signature Page to the Registration Rights Agreement

AJAX RESOURCES, LLC
By:	Ajax Intermediate, LLC, its sole owner
By:	Ajax Resources Holding, LLC, its managing member
By:	/s/ Richard H. Little
Name:	Richard H. Little
Title:	Manager

Address:

24 Greenway Plaza, Suite 650

Houston, Texas 77046

Attention: Richard Little

E-mail: rlittle@ajaxres.com

With copies to (which shall not constitute notice):

Kelso & Company

320 Park Avenue, 24th Floor

New York, New York 10022

Attention: Jim Connors

Fax: (212) 223-2379

E-mail: JConnors@kelso.com

and

Thompson & Knight LLP

1722 Routh Street, Suite 1500

Dallas, Texas 75201

Attention: Robert Dougherty

Fax: (214) 999-1505

Email: robert.dougherty@tklaw.com

Signature Page to the Registration Rights Agreement

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Travis D. Stice, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Diamondback Energy, Inc.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 7, 2018	/s/ Travis D. Stice
		Travis D. Stice
		Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Teresa L. Dick, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Diamondback Energy, Inc.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 7, 2018	/s/ Teresa L. Dick
		Teresa L. Dick
		Chief Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF PERIOD REPORT

In connection with the Quarterly Report on Form 10-Q of Diamondback Energy, Inc. (the "Company"), as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned, Travis D. Stice, Chief Executive Officer of Diamondback Energy, Inc., certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that, to the best of my knowledge:

(1) The Report fully complies with the requirements of Section 13 (a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	November 7, 2018	/s/ Travis D. Stice
		Travis D. Stice
		Chief Executive Officer

EX-32.2

EXHIBIT 32.2

CERTIFICATION OF PERIOD REPORT

In connection with the Quarterly Report on Form 10-Q of Diamondback Energy, Inc. (the "Company"), as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned, Teresa L. Dick, Chief Financial Officer of Diamondback Energy, Inc., certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that, to the best of my knowledge:

(1) the Report fully complies with the requirements of Section 13 (a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	November 7, 2018	/s/ Teresa L. Dick
		Teresa L. Dick
		Chief Financial Officer

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Nov. 02, 2018
Document and Entity Information [Abstract]
Document type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q3
Entity Registrant Name	Diamondback Energy, Inc.
Entity Central Index Key	0001539838
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Ex Transition Period	false
Entity Common Stock, Shares Outstanding		101,257,911

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 508,446	$ 112,446
Accounts receivable:
Joint interest and other	81,955	73,038
Oil and natural gas sales	182,362	158,575
Inventories	14,815	9,108
Derivative instruments	0	531
Prepaid expenses and other	8,111	4,903
Total current assets	795,689	358,601
Property and equipment:
Oil and natural gas properties, full cost method of accounting ($4,283,629 and $4,105,865 excluded from amortization at September 30, 2018 and December 31, 2017, respectively)	10,818,378	9,232,694
Midstream assets	355,758	191,519
Other property, equipment and land	85,882	80,776
Accumulated depletion, depreciation, amortization and impairment	(2,545,412)	(2,161,372)
Net property and equipment	8,714,606	7,343,617
Funds held in escrow	62,034	6,304
Deferred tax asset	95,551	0
Investment in real estate, net	106,834	0
Other assets	31,859	62,463
Total assets	9,806,573	7,770,985
Current liabilities:
Accounts payable-trade	85,869	94,590
Accrued capital expenditures	292,700	221,256
Other accrued liabilities	143,792	92,512
Revenues and royalties payable	75,600	68,703
Derivative instruments	123,826	100,367
Total current liabilities	721,787	577,428
Long-term debt	2,332,359	1,477,347
Derivative instruments	5,931	6,303
Asset retirement obligations	23,897	20,122
Deferred income taxes	292,795	108,048
Other long-term liabilities	7	0
Total liabilities	3,376,776	2,189,248
Commitments and contingencies
Stockholders’ equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 98,673,563 issued and outstanding at September 30, 2018; 98,167,289 issued and outstanding at December 31, 2017	987	982
Additional paid-in capital	5,464,542	5,291,011
Retained earnings (accumulated deficit)	467,830	(37,133)
Total Diamondback Energy, Inc. stockholders’ equity	5,933,359	5,254,860
Non-controlling interest	496,438	326,877
Total equity	6,429,797	5,581,737
Total liabilities and equity	$ 9,806,573	$ 7,770,985

XML

Consolidated Balance Sheets Consolidated Balance Sheets (Parentheticals) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Oil and natural gas properties, amortization excluded	$ 4,283,629	$ 4,105,865
Common Stock, Par Value (in dollars per share)	$ 0.01	$ 0.01
Shares authorized	200,000,000	200,000,000
Shares Issued	98,673,563	98,167,289
Shares Outstanding	98,673,563	98,167,289

XML

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenues:
Revenue	$ 538,029	$ 301,253	$ 1,544,497	$ 805,917
Lease bonus	1,322	322	2,250	2,507
Other operating income	2,359	0	6,825	0
Costs and expenses:
Lease operating expenses	49,111	32,498	129,103	88,113
Production and ad valorem taxes	33,536	18,371	93,042	49,975
Depreciation, depletion and amortization	146,318	87,579	391,401	221,681
General and administrative expenses (including non-cash equity-based compensation, net of capitalized amounts, of $5,350 and $6,187 for the three months ended September 30, 2018 and 2017, respectively, and $18,451 and $19,418 for the nine months ended September 30, 2018 and 2017, respectively)	14,185	11,888	45,039	37,524
Asset retirement obligation accretion	387	357	1,107	1,030
Other operating expense	940	0	2,416	0
Total costs and expenses	271,178	158,614	728,697	414,560
Income from operations	266,851	142,639	815,800	391,357
Other income (expense):
Interest expense, net	(18,548)	(9,192)	(49,345)	(29,662)
Other income, net	1,962	3	89,170	9,472
Gain (loss) on derivative instruments, net	(48,373)	(50,645)	(139,305)	20,376
Gain (loss) on revaluation of investment	(199)	0	5,165	0
Total other income (expense), net	(65,158)	(59,834)	(94,315)	186
Income before income taxes	201,693	82,805	721,485	391,543
Provision for income taxes	42,276	857	82,750	4,393
Net income	159,417	81,948	638,735	387,150
Net income attributable to non-controlling interest	2,363	8,924	99,723	19,448
Net income attributable to Diamondback Energy, Inc.	$ 157,054	$ 73,024	$ 539,012	$ 367,702
Earnings per common share:
Basic (in dollars per share)	$ 1.59	$ 0.74	$ 5.47	$ 3.81
Diluted (in dollars per share)	$ 1.59	$ 0.74	$ 5.45	$ 3.80
Weighted average common shares outstanding:
Basic (in shares)	98,638	98,144	98,603	96,491
Diluted (in shares)	98,818	98,369	98,820	96,752
Dividends declared per share	$ 0.125	$ 0.000	$ 0.375	$ 0.000
Oil sales
Revenues:
Revenue	$ 454,644	$ 259,049	$ 1,334,349	$ 704,007
Natural gas sales
Revenues:
Revenue	14,814	14,922	40,557	37,537
Natural gas liquid sales
Revenues:
Revenue	57,610	25,266	133,858	57,625
Midstream services
Revenues:
Revenue	7,280	1,694	26,658	4,241
Costs and expenses:
Cost of Goods and Services Sold	19,725	4,445	48,515	7,127
Gathering and transportation
Costs and expenses:
Cost of Goods and Services Sold	$ 6,976	$ 3,476	$ 18,074	$ 9,110

XML

Consolidated Statements of Operations Consolidated Statements of Operations (Parentheticals) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
General and Administrative Expense [Member]
Non-cash stock based compensation, net of capitalized amount	$ 5,350	$ 6,187	$ 18,451	$ 19,418

XML

Consolidated Statement of Stockholders' Equity - USD ($) $ in Thousands	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Noncontrolling Interest [Member]
Balance at beginning of period at Dec. 31, 2016	$ 4,018,292	$ 901	$ 4,215,955	$ (519,394)	$ 320,830
Balance at beginning of period, shares at Dec. 31, 2016		90,144,000
Increase (Decrease) in Stockholders' Equity
Net proceeds from issuance of common units - Viper Energy Partners LP	369,896	$ 0	0	0	369,896
Unit-based compensation	2,039	0	0	0	2,039
Common units issued for acquisition	3,050	0	0	0	3,050
Stock-based compensation	23,790	0	23,790	0	0
Distribution to non-controlling interest	(27,640)	0	0	0	(27,640)
Common shares issued in public offering, net of offering costs	14	0	14	0	0
Common shares issued for acquisition	809,173	$ 77	809,096	0	0
Common shares issued for acquisition, shares		7,686,000
Exercise of stock options and vesting of restricted stock units	359	$ 4	355	0	0
Exercise of stock options and awards of restricted stock, shares		337,000
Net income	387,150	$ 0	0	367,702	19,448
Balance at end of period at Sep. 30, 2017	5,586,123	$ 982	5,049,210	(151,692)	687,623
Balance at end of period, shares at Sep. 30, 2017		98,167,000
Balance at beginning of period at Dec. 31, 2017	$ 5,581,737	$ 982	5,291,011	(37,133)	326,877
Balance at beginning of period, shares at Dec. 31, 2017	98,167,289	98,167,000
Increase (Decrease) in Stockholders' Equity
Net proceeds from issuance of common units - Viper Energy Partners LP	$ 303,137	$ 0	0	0	303,137
Unit-based compensation	2,166	0	0	0	2,166
Stock-based compensation	23,613	0	23,613	0	0
Distribution to non-controlling interest	(68,801)	0	0	0	(68,801)
Dividend paid	(24,656)	0	0	(24,656)	0
Exercise of stock options and vesting of restricted stock units	140	5	(5)	0	140
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Changes, Net	(10,210)	$ 0	149,923	0	(160,133)
Exercise of stock options and awards of restricted stock, shares		506,000
Net income	638,735	$ 0	0	539,012	99,723
Balance at end of period at Sep. 30, 2018	$ 6,429,797	$ 987	5,464,542	467,830	496,438
Balance at end of period, shares at Sep. 30, 2018	98,673,563	98,674,000
Increase (Decrease) in Stockholders' Equity
Impact of adoption of ASU 2016-01, net of tax	$ (16,064)	$ 0	$ 0	$ (9,393)	$ (6,671)

XML

Consolidated Statements of Cash Flows - USD ($) shares in Thousands, $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Cash flows from operating activities:
Net income	$ 638,735	$ 387,150
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for deferred income taxes	81,573	3,313
Asset retirement obligation accretion	1,107	1,030
Depreciation, depletion and amortization	391,401	221,681
Amortization of debt issuance costs	2,291	2,828
Change in fair value of derivative instruments	23,618	(9,365)
Income from equity investment	0	(309)
Gain on revaluation of investment	(5,165)	0
Equity-based compensation expense	18,451	19,418
Loss (gain) on sale of assets, net	3,071	(386)
Changes in operating assets and liabilities:
Accounts receivable	(21,611)	(23,422)
Accounts receivable-related party	0	283
Restricted cash	0	500
Inventories	(14,196)	(2,700)
Prepaid expenses and other	(5,813)	(9,242)
Accounts payable and accrued liabilities	18,383	18,305
Accounts payable and accrued liabilities-related party	0	(2)
Accrued interest	12,663	(1,738)
Income tax payable	311	1,017
Revenues and royalties payable	6,897	29,657
Net cash provided by operating activities	1,151,716	638,018
Cash flows from investing activities:
Additions to oil and natural gas properties	(1,010,325)	(531,489)
Additions to midstream assets	(129,820)	(22,491)
Purchase of other property, equipment and land	(2,049)	(21,534)
Acquisition of leasehold interests	(185,658)	(1,892,864)
Acquisition of mineral interests	(335,574)	(370,855)
Acquisition of midstream assets	0	(50,279)
Proceeds from sale of assets	6,771	3,584
Investment in real estate	(110,654)	0
Funds held in escrow	(51,045)	121,391
Equity investments	(604)	(188)
Net cash used in investing activities	(1,818,958)	(2,764,725)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	1,027,500	533,000
Repayment under credit facility	(1,221,500)	(383,500)
Proceeds from senior notes	1,062,000	0
Debt issuance costs	(14,578)	(1,714)
Public offering costs	(2,636)	(510)
Proceeds from public offerings	305,773	370,344
Proceeds from unit options exercised	140	0
Proceeds from exercise of stock options	0	358
Dividends to stockholders	(24,656)	0
Distributions to non-controlling interest	(68,801)	(27,640)
Net cash provided by financing activities	1,063,242	490,338
Net increase (decrease) in cash and cash equivalents	396,000	(1,636,369)
Cash and cash equivalents at beginning of period	112,446	1,666,574
Cash and cash equivalents at end of period	508,446	30,205
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest	51,658	28,702
Supplemental disclosure of non-cash transactions:
Change in accrued capital expenditures	71,444	129,105
Capitalized stock-based compensation	$ 7,328	$ 6,411
Common stock issued for oil and natural gas properties	0	809,173
Asset retirement obligations acquired	$ 270	$ 2,411

XML

Description of the Business and Basis of Presentation

9 Months Ended

Sep. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Description of the Business and Basis of Presentation

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.

The wholly-owned subsidiaries of Diamondback, as of September 30, 2018, 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, Rattler Midstream LLC (formerly known as White Fang Energy LLC), a Delaware limited liability company, and Tall City Towers LLC, a Delaware limited liability company. The consolidated subsidiaries include these wholly-owned subsidiaries as well as Viper Energy Partners LP, a Delaware limited partnership (the “Partnership”), and the Partnership’s wholly-owned subsidiary Viper Energy Partners LLC, a Delaware limited liability company (the “Operating 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, 2018, the Company owned approximately 59% of the Partnership’s total units outstanding. 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 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 GAAP have been omitted pursuant to such rules and regulations, although the Company believes the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10–Q should be read in conjunction with the Company’s most recent Annual Report on Form 10–K for the fiscal year ended December 31, 2017, which contains a summary of the Company’s significant accounting policies and other disclosures.

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Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

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.

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

Investments

The Partnership has an equity interest in a limited partnership that is so minor that the Partnership has no influence over the limited partnership’s operating and financial policies. This interest was acquired during the year ended December 31, 2014 and is accounted for under the cost method. Effective January 1, 2018, the Partnership adopted Accounting Standards Update 2016-01 which requires the Partnership to measure this investment at fair value which resulted in a downward adjustment of $18.7 million to record the impact of this adoption. For the three months and nine months endedSeptember 30, 2018, the Partnership recorded a gain (loss) of $(0.2) million and $5.2 million, respectively. The Partnership’s investment balance as of September 30, 2018 was $20.2 million, which is included in other assets in the accompanying consolidated balance sheets.

Funds Held in Escrow

The funds held in escrow represent amounts in deposit to fund acquisitions. During the nine months ended September 30, 2018, there was $62.0 million in deposit to be applied to the purchase price for the acquisition of leasehold interests and related assets from Ajax Resources, LLC that closed on October 31, 2018. See Note 4— Acquisitions for information relating to this acquisition. During the nine months ended September 30, 2017, there was $6.3 million in deposit to fund other acquisitions which closed in the first quarter of 2018.

New Accounting Pronouncements

Recently Adopted Pronouncements

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”. This standard included a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. Among other things, the standard also eliminated industry-specific revenue guidance, required enhanced disclosures about revenue, provided guidance for transactions that were not previously addressed comprehensively and improved guidance for multiple-element arrangements. The Company adopted this Accounting Standards Update effective January 1, 2018 using the modified retrospective approach. The Company utilized a bottom-up approach to analyze the impact of the new standard by reviewing its current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard to its revenue contracts and the impact of adopting this standards update on its total revenues, operating income and its consolidated balance sheet. The adoption of this standard did not result in a cumulative-effect adjustment.

In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. This update applies to any entity that holds financial assets or owes financial liabilities. This update requires equity investments (except for those accounted for under the equity method or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. The Partnership adopted this standard effective January 1, 2018 by means of a negative cumulative-effect adjustment totaling $18.7 million.

In August 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-15, “Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments”. This update apples to all entities that are required to present a statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; including bank-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The Company adopted this update effective January 1, 2018 using the retrospective transition method. Adoption of this standard did not have an effect on the presentation on the Statement of Cash Flows.

In November 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-18, “Statement of Cash Flows - Restricted Cash”. This update affects entities that have restricted cash or restricted cash equivalents. The Company adopted this update effective January 1, 2018. The adoption of this update did not have an effect on the presentation on the Statement of Cash Flows.

In January 2017, the Financial Accounting Standards Board issued Accounting Standards Update 2017-01, “Business Combinations - Clarifying the Definition of a Business”. This update apples to all entities that must determine whether they acquired or sold a business. This update provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The Company adopted this update prospectively effective January 1, 2018. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.

Accounting Pronouncements Not Yet Adopted

In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Company believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases. The Company is still evaluating the impact of this standard.

In January 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-01, “Leases - Land Easement Practical Expedient for Transition to Topic 842”. This update applies to any entity that holds land easements. The update allows entities to adopt a practical expedient to not evaluate existing or expired land easements under Topic 842 that were not previously accounted for as leases under the current leases guidance. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. The Company believes the adoption of this update will not have an impact on its financial position, results of operations or liquidity.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-10, “Codification Improvements to Topic 842, Leases”. This update provides clarification and corrects unintended application of certain sections in the new lease guidance. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases. The Company is still evaluating the impact of this standard.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-11, “Lease (Topic 842): Targeted Improvements”. This update provides another transition method of allowing entities to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases. The Company is still evaluating the impact of this standard.

In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company does not believe the adoption of this standard will have a material impact on the Company’s consolidated financial statements since the Company does not have a history of credit losses.

In June 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-07, “Stock Compensation - Improvements to Nonemployee Share-Based Payment Accounting”. This update applies the existing employee guidance to nonemployee share-based transactions, with the exception of specific guidance related to the attribution of compensation cost. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-09, “Codification Improvements”. This update provides clarification and corrects unintended application of the guidance in various sections. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

In August 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-13, “Fair Value Measurement (Topic 820) - Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement”. This update modifies the fair value measurement disclosure requirements specifically related to Level 3 fair value measurements and transfers between levels. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied prospectively. The Company is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

In August 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-15, “Intangibles - Goodwill and Other - Internal - Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract”. This update requires the capitalization of implementation costs incurred in a hosting arrangement that is a service contract for internal-use software. Training and certain data conversion costs cannot be capitalized. The entity is required to expense the capitalized implementation costs over the term of the hosting agreement. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update should be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. The Company believes the adoption of this update will not have an impact on its financial position, results of operations or liquidity.

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Revenue from Contracts with Customers

9 Months Ended

Sep. 30, 2018

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customer [Text Block]

REVENUE FROM CONTRACTS WITH CUSTOMERS

Revenue from Contracts with Customers

Sales of oil, natural gas and natural gas liquids are recognized at the point control of the product is transferred to the customer. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, the quality of the oil or natural gas and the prevailing supply and demand conditions. As a result, the price of the oil, natural gas and natural gas liquids fluctuates to remain competitive with other available oil, natural gas and natural gas liquids supplies.

Oil sales

The Company’s oil sales contracts are generally structured where it delivers oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, the Company or a third party transports the product to the delivery point and receives a specified index price from the purchaser with no deduction. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Oil revenues are recorded net of any third-party transportation fees and other applicable differentials in the Company’s consolidated statements of operations.

Natural gas and natural gas liquids sales

Under the Company’s natural gas processing contracts, it delivers natural gas to a midstream processing entity at the wellhead, battery facilities or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of natural gas liquids and residue gas. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For those contracts where the Company has concluded it is the principal and the ultimate third party is its customer, the Company recognizes revenue on a gross basis, with transportation, gathering, processing, treating and compression fees presented as an expense in its consolidated statements of operations.

In certain natural gas processing agreements, the Company may elect to take its residue gas and/or natural gas liquids in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing, treating and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing, treating and compression expense in its consolidated statements of operations.

Midstream Revenue

Substantially all revenues from gathering, compression, water handling, disposal and treatment operations are derived from intersegment transactions for services Rattler Midstream LLC (“Rattler”) provides to exploration and production operations. The portion of such fees shown in the Company’s consolidated financial statements represent amounts charged to interest owners in the Company’s operated wells, as well as fees charged to other third parties for water handling and treatment services provided by Rattler or usage of Rattler’s gathering and compression systems. For gathering and compression revenue, Rattler satisfies its performance obligations and recognizes revenue when low pressure volumes are delivered to a specified delivery point. Revenue is recognized based on the per MMbtu gathering fee or a per barrel gathering fee charged by Rattler in accordance with the gathering and compression agreement. For water handling and treatment revenue, Rattler satisfies its performance obligations and recognizes revenue when the fresh water volumes have been delivered to the fracwater meter for a specified well pad and the wastewater volumes have been metered downstream of the Company’s facilities. For services contracted through third party providers, Rattler’s performance obligation is satisfied when the service performed by the third party provider has been completed. Revenue is recognized based on the per barrel fresh water delivery or a wastewater gathering and disposal fee charged by Rattler in accordance with the water services agreement.

Transaction price allocated to remaining performance obligations

The Company’s upstream product sales contracts do not originate until production occurs and, therefore, are not considered to exist beyond each days’ production. Therefore, there are no remaining performance obligation under any of our product sales contracts.

The majority of the Company’s midstream revenue agreements have a term greater than one year, and as such Rattler LLC has utilized the practical expedient in ASC 606, which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under its revenue agreements, each delivery generally represents a separate performance obligation; therefore, future volumes delivered are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

The remainder of the Company’s midstream revenue agreements, which relate to agreements with third parties, are short-term in nature with a term of one year or less. Rattler LLC has utilized an additional practical expedient in ASC 606 which exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of an agreement that has an original expected duration of one year or less.

Contract balances

Under the Company’s product sales contracts, it has the right to invoice its customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606.

Prior-period performance obligations

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the three months ended September 30, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Company believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the revenue related to expected sales volumes and prices for those properties are estimated and recorded.

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Acquisitions

9 Months Ended

Sep. 30, 2018

Business Combinations [Abstract]

Mergers, Acquisitions and Dispositions Disclosures [Text Block]

ACQUISITIONS

Tall City Towers LLC

On January 31, 2018, Tall City Towers LLC, a subsidiary of the Company, completed its acquisition of the Fasken Center office buildings in Midland, TX where the Company’s corporate offices are located for a net purchase price of $109.7 million.

Pending Merger with Energen Corporation

On August 14, 2018, the Company entered into a definitive merger agreement providing for the Company’s acquisition of Energen Corporation (“Energen”) in an all-stock transaction valued at approximately $9.2 billion including Energen’s net debt of $831.0 million as of June 30, 2018 (the “Pending Merger”). The addition of Energen’s assets will increase the Company’s assets to: (i) over 273,000 net Tier One acres in the Permian Basin, an increase of 57% from its current Tier One acreage of approximately 174,000 net acres, (ii) approximately 7,200 estimated total net horizontal Permian locations, an increase of over 120% from its current estimated net locations and (iii) approximately 394,000 net acres across the Midland and Delaware Basins, an increase of 82% from our approximately 216,000 net acres as September 30, 2018, in each case after giving effect to the Company’s recently completed Ajax Resources, LLC, ExL Management, LLC and EnergyQuest II LLC acquisitions described below.

The completion of the Pending Merger is subject to the satisfaction or waiver of certain customary mutual closing conditions. The Company’s registration statement on Form S-4 relating to the Pending Merger was declared effective by the SEC on October 24, 2018, and the Pending Merger is expected to be completed at the end of November of 2018.

Under the terms of the merger agreement relating to the Pending Merger, the Company has agreed to assume Energen’s outstanding debt, which as of June 30, 2018 was approximately $831.0 million. This amount consists of $301.0 million of borrowings under Energen’s existing credit facility, $400.0 million aggregate principal amount of 4.625% Notes, due September 1, 2021, $20.0 million aggregate principal amount of 7.32% Medium-term Notes, Series A, due July 28, 2022, $10.0 million aggregate principal amount of 7.35% Medium-term Notes, Series A, due July 28, 2027, and $100.0 million aggregate principal amount of 7.125% Medium-term Notes, Series B, due February 15, 2028 (collectively, the “Energen Notes”). The Company may choose to refinance the Energen credit facility and the Company’s credit facility into a combined credit facility in connection with the consummation of the Pending Merger or the Company may choose to repay the outstanding borrowings under the Energen credit facility using cash on hand or borrowings under the Company’s revolving credit facility. With respect to the outstanding Energen Notes, the Company may take no action, or the Company may seek to amend the terms of the indenture governing the Energen Notes or engage in liability management transactions with respect to, repay or refinance any or all of the Energen Notes, with any repayment coming from cash on hand or borrowings under the Company’s revolving credit facility.

Ajax Resources, LLC

On July 22, 2018, the Company entered into a definitive purchase agreement to acquire all leasehold interests and related assets of Ajax Resources, LLC, which include approximately 25,493 net leasehold acres in the Northern Midland Basin, for $900.0 million in cash, subject to certain adjustments, and approximately 2.6 million shares of the Company’s common stock (the “Ajax acquisition”). This transaction closed on October 31, 2018 and was effective as of July 1, 2018. The cash portion of this transaction was funded through a combination of cash on hand, proceeds from the sale of mineral interests to the Partnership (described below), borrowing under the Company’s revolving credit facility and a portion of the proceeds from the Company’s September 2018 senior note offering. See Note 9—Debt for information relating to this offering.

In connection with the closing of the Ajax acquisition on October 31, 2018, the Company entered into a registration rights agreement with Ajax Resources, LLC and certain other holders of the Company’s common stock. Pursuant to this agreement, the Company agreed to (i) file with the SEC a shelf registration statement to facilitate the resale of common stock issued in the Ajax acquisition and any shares of common stock that may be issued or distributed in respect of such shares upon certain events and (ii) use its reasonable best efforts to cause such registration statement to become effective by November 30, 2018. Pursuant to this registration rights agreement, the Company also agreed to provide certain demand and piggyback registration rights to such holders.

ExL Petroleum Management, LLC and EnergyQuest II LLC

On September 21, 2018, the Company entered into two definitive purchase agreements to acquire leasehold interests and related assets, one with ExL Petroleum Management, LLC and ExL Petroleum Operating, Inc. and one with EnergyQuest II LLC, for an aggregate of approximately 3,646 net leasehold acres in the Northern Midland Basin for a total of $312.5 million in cash, subject to certain adjustments. These transactions closed on October 31, 2018 and were effective as of August 1, 2018. These transactions were funded through a combination of cash on hand, proceeds from the sale of assets to the Partnership (described below) and borrowing under the Company’s revolving credit facility.

Drop-down Transaction

On August 15, 2018, the Company completed a transaction to sell to the Partnership mineral interests underlying 32,424 gross (1,696 net royalty) acres primarily in Pecos County, Texas, in the Permian Basin, approximately 80% of which are operated by the Company, for $175.0 million (the “Drop-down Transaction”).

Oil and Natural Gas Properties

On February 28, 2017, the Company completed its acquisition of certain oil and natural gas properties, midstream assets and other related assets in the Delaware Basin for an aggregate purchase price consisting of $1.74 billion in cash and 7.69 million shares of the Company’s common stock, of which approximately 1.15 million shares were placed in an indemnity escrow. This transaction included the acquisition of (i) approximately 100,306 gross (80,339 net) acres primarily in Pecos and Reeves counties for approximately $2.5 billion and (ii) midstream assets for approximately $47.6 million. The Company used the net proceeds from its December 2016 equity offering, net proceeds from its December 2016 debt offering, cash on hand and other financing sources to fund the cash portion of the purchase price for this acquisition.

The following represents the fair value of the assets and liabilities assumed on the acquisition date. The aggregate consideration transferred was $2.5 billion, resulting in no goodwill or bargain purchase gain.

	(in thousands)
Proved oil and natural gas properties	$	386,308
Unevaluated oil and natural gas properties	2,122,597
Midstream assets	47,432
Prepaid capital costs	3,460
Oil inventory	839
Equipment	163
Revenues and royalties payable	(9,650		)
Asset retirement obligations	(1,550		)
Total fair value of net assets	$	2,549,599

The Company included in its consolidated statements of operations revenues of $84.3 million and direct operating expenses of $16.0 million for the period from February 28, 2017 to September 30, 2017 due to the acquisition.

Pro Forma Financial Information

The following unaudited summary pro forma consolidated statement of operations data of Diamondback for the three months and nine months endedSeptember 30, 2017 have been prepared to give effect to the February 28, 2017 acquisition as if it had occurred on January 1, 2016. The pro forma data are not necessarily indicative of financial results that would have been attained had the acquisitions occurred on January 1, 2016. The pro forma data also necessarily exclude various operation expenses related to the properties and the financial statements should not be viewed as indicative of operations in future periods.

	Three Months Ended September 30, 2017		Nine Months Ended September 30, 2017
	(in thousands, except per share amounts)
Revenues	$	301,253	$	828,846
Income from operations	142,639		405,699
Net income	81,948		382,044
Basic earnings per common share	0.74		3.96
Diluted earnings per common share	0.74		3.95

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Viper Energy Partners LP

9 Months Ended

Sep. 30, 2018

Noncontrolling Interest [Abstract]

Viper Energy Partners LP

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 and the Eagle Ford Shale. Viper Energy Partners GP LLC, a fully-consolidated subsidiary of Diamondback, serves as the general partner of the Partnership. As of September 30, 2018, the Company owned approximately 59% of the Partnership’s total units outstanding.

Recapitalization,Tax Status Election and Related Transactions by Viper

In March 2018, the Partnership announced that the Board of Directors of the General Partner had unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election. In connection with making this election, on May 9, 2018 the Partnership (i) amended and restated its First Amended and Restated Partnership Agreement, (ii) amended and restated the First Amended and Restated Limited Liability Company Agreement of the Operating Company, (iii) amended and restated its existing registration rights agreement with the Company and (iv) entered into an exchange agreement with the Company, the General Partner and the Operating Company. Simultaneously with the effectiveness of these agreements, the Company delivered and assigned to the Partnership the 73,150,000 common units the Company owned in exchange for (i) 73,150,000 of the Partnership’s newly-issued Class B units and (ii) 73,150,000 newly-issued units of the Operating Company pursuant to the terms of a Recapitalization Agreement dated March 28, 2018, as amended as of May 9, 2018 (the “Recapitalization Agreement”). Immediately following that exchange, the Partnership continued to be the managing member of the Operating Company, with sole control of its operations, and owned approximately 36% of the outstanding units issued by the Operating Company, and the Company owned the remaining approximately 64% of the outstanding units issued by the Operating Company. Upon completion of the Partnership’s July 2018 offering of units, it owned approximately 41% of the outstanding units issued by the Operating Company and the Company owned the remaining approximately 59%. The Operating Company units and the Partnership’s Class B units owned by the Company are exchangeable from time to time for the Partnership’s common units (that is, one Operating Company unit and one Partnership Class B unit, together, will be exchangeable for one Partnership common unit).

On May 10, 2018, the change in the Partnership’s income tax status became effective. On that date, pursuant to the terms of the Recapitalization Agreement, (i) the General Partner made a cash capital contribution of $1.0 million to the Partnership in respect of its general partner interest and (ii) the Company made a cash capital contribution of $1.0 million to the Partnership in respect of the Class B units. The Company, as the holder of the Class B units, and the General Partner, as the holder of the general partner interest, are entitled to receive an 8% annual distribution on the outstanding amount of these capital contributions, payable quarterly, as a return on this invested capital. On May 10, 2018, the Company also exchanged 731,500 Class B units and 731,500 units in the Operating Company for 731,500 common units of the Partnership and a cash amount of $10,000 representing a proportionate return of the $1.0 million invested capital in respect of the Class B units. The General Partner continues to serve as the Partnership’s general partner and the Company continues to control the Partnership. After the effectiveness of the tax status election and the completion of related transactions, the Partnership’s minerals business continues to be conducted through the Operating Company, which continues to be taxed as a partnership for federal and state income tax purposes. This structure is anticipated to provide significant benefits to the Partnership’s business, including operational effectiveness, acquisition and disposition transactional planning flexibility and income tax efficiency. For additional information regarding the tax status election and related transactions, please refer to the Partnership’s Definitive Information Statement on Schedule 14C filed with the SEC on April 17, 2018 and the Partnership’s Current Report on Form 8-K filed with the SEC on May 15, 2018.

Partnership Agreement

The second amended and restated agreement of limited partnership, dated as of May 9, 2018, as amended as of May 10, 2018 (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. For the three months ended September 30, 2018 and 2017, the General Partner allocated $0.6 million to the Partnership. For the nine months ended September 30, 2018 and 2017, the General Partner allocated $1.8 million to the Partnership.

Tax Sharing

In connection with the closing of the Viper Offering, the Partnership entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to which the Partnership agreed to 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 agreed to 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. For the three months and nine months endedSeptember 30, 2018, the Partnership accrued state income tax expense (benefit) of $(0.1) million and $0.1 million, respectively, for its share of Texas margin tax for which the Partnership’s results are included in a combined tax return filed by Diamondback.

Other Agreements

See Note 12—Related Party Transactions for information regarding the advisory services agreement the Partnership and the General Partner entered into with Wexford Capital LP (“Wexford”).

The Partnership has entered into a secured revolving credit facility with Wells Fargo, as administrative agent sole book runner and lead arranger. See Note 9—Debt for a description of this credit facility.

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Property and Equipment

9 Months Ended

Sep. 30, 2018

Property, Plant and Equipment [Abstract]

Property and Equipment

PROPERTY AND EQUIPMENT

Property and equipment includes the following:

	September 30,			December 31,
	2018			2017
	(in thousands)
Oil and natural gas properties:
Subject to depletion	$	6,534,749		$	5,126,829
Not subject to depletion	4,283,629			4,105,865
Gross oil and natural gas properties	10,818,378			9,232,694
Accumulated depletion	(1,375,163		)	(1,009,893		)
Accumulated impairment	(1,143,498		)	(1,143,498		)
Oil and natural gas properties, net	8,299,717			7,079,303
Midstream assets	355,758			191,519
Other property, equipment and land	85,882			80,776
Accumulated depreciation	(26,751		)	(7,981		)
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment	$	8,714,606		$	7,343,617
Balance of costs not subject to depletion:
Incurred in 2018	$	589,352
Incurred in 2017	2,563,902
Incurred in 2016	714,467
Incurred in 2015	234,948
Incurred in 2014	180,960
Total not subject to depletion	$	4,283,629

The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. 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. Costs, including related employee costs, associated with production and operation of the properties are charged to expense as incurred. All other internal costs not directly associated with exploration and development activities are charged to expense as they are incurred. Capitalized internal costs were approximately $6.7 million and $5.7 million for the three months ended September 30, 2018 and 2017, respectively, and $20.4 million and $15.9 million for the nine months ended September 30, 2018 and 2017, 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. Acquisition costs not currently being amortized are primarily related to unproved acreage that the Company plans to prove up through drilling. The Company has no plans to let any acreage expire. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas.

Under this method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions or financial derivatives, if any, that hedge the Company’s oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required.

At September 30, 2018, there was $50.1 million in exploration costs and development costs and $42.0 million in capitalized interest that was not subject to depletion. At December 31, 2017, there were $26.0 million in exploration costs and development costs and $22.1 million in capitalized interest that was not subject to depletion.

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2018

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

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,
	2018			2017
	(in thousands)
Asset retirement obligations, beginning of period	$	21,285		$	17,422
Additional liabilities incurred	2,229			1,196
Liabilities acquired	270			2,411
Liabilities settled	(1,474		)	(689		)
Accretion expense	1,107			1,030
Revisions in estimated liabilities	568			4
Asset retirement obligations, end of period	23,985			21,374
Less current portion	88			1,392
Asset retirement obligations - long-term	$	23,897		$	19,982

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. The current portion of the asset retirement obligation liability is included in other accrued liabilities in the Company’s consolidated balance sheets.

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Equity Method Investments

9 Months Ended

Sep. 30, 2018

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments

EQUITY METHOD INVESTMENTS

In October 2014, the Company obtained a 25% interest in HMW Fluid Management LLC (“HMW LLC”), which 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. On June 30, 2018, HMW LLC’s operating agreement was amended effective January 1, 2018. As a result of the amendment, the Company will no longer recognize an equity investment in HMW LLC but will instead consolidate its interests in the net assets of HMW LLC. In exchange for the Company’s 25% investment, the Company received a 50% undivided ownership interest in two of the four salt water disposal wells and associated assets previously owned by HMW LLC. The Company’s basis in the assets is equivalent to its basis in the equity investment in HMW LLC. During the nine months ended September 30, 2017, the Company invested $0.2 million in this entity and recorded $0.3 million, which is the Company’s share of HMW LLC’s net income, bringing its total investment to $6.8 million at September 30, 2017.

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Debt

9 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Debt

DEBT

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

	September 30,			December 31,
	2018			2017
	(in thousands)
4.750 % Senior Notes due 2024	$	1,250,000		$	500,000
5.375 % Senior Notes due 2025	800,000			500,000
Unamortized debt issuance costs	(25,038		)	(13,153		)
Unamortized premium costs	10,897			—
Revolving credit facility	—			397,000
Partnership revolving credit facility	296,500			93,500
Total long-term debt	$	2,332,359		$	1,477,347

2024 Senior Notes

On October 28, 2016, the Company issued $500.0 million in aggregate principal amount of 4.750% Senior Notes due 2024 (the “2024 Senior Notes”). The 2024 Senior Notes bear interest at a rate of 4.750% per annum, payable semi-annually, in arrears on May 1 and November 1 of each year, commencing on May 1, 2017 and will mature on November 1, 2024. All of the Company’s existing and future restricted subsidiaries that guarantee its revolving credit facility or certain other debt guarantee the 2024 Senior Notes; provided, however, that the 2024 Senior Notes are not guaranteed by the Partnership, the General Partner, Viper Energy Partners LLC or Rattler Midstream LLC, and will not be guaranteed by any of the Company’s future unrestricted subsidiaries.

On September 25, 2018, the Company issued $750.0 million aggregate principal amount of new 4.750% Senior Notes due 2024 (the “New 2024 Notes”) as additional notes under, and subject to the terms of, the 2024 Indenture. The New 2024 Notes were issued in a transaction exempt from the registration requirements under the Securities Act. The Company received approximately $740.7 million in net proceeds, after deducting the initial purchasers’ discount and its estimated offering expenses, but disregarding accrued interest, from the issuance of the New 2024 Notes. The Company used a portion of the net proceeds from the issuance of the New 2024 Notes to repay the outstanding borrowings under its revolving credit facility and intends to use the balance for general corporate purposes, including funding a portion of the cash consideration for the acquisition of assets from Ajax Resources, LLC.

The 2024 Senior Notes were issued under, and are governed by, an indenture among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented (the “2024 Indenture”). The 2024 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 capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted 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 natural gas business and designate certain of the Company’s subsidiaries as unrestricted subsidiaries.

The Company may on any one or more occasions redeem some or all of the 2024 Senior Notes at any time on or after November 1, 2019 at the redemption prices (expressed as percentages of principal amount) of 103.563% for the 12-month period beginning on November 1, 2019, 102.375% for the 12-month period beginning on November 1, 2020, 101.188% for the 12-month period beginning on November 1, 2021 and 100.000% beginning on November 1, 2022 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to November 1, 2019, the Company may on any one or more occasions redeem all or a portion of the 2024 Senior Notes (including the New 2024 Notes) at a price equal to 100% of the principal amount of the 2024 Senior Notes (including the New 2024 Notes) plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to November 1, 2019, the Company may on any one or more occasions redeem the 2024 Senior Notes (including the New 2024 Notes) in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2024 Senior Notes (including the New 2024 Notes) issued prior to such date at a redemption price of 104.750%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings.

2025 Senior Notes

On December 20, 2016, the Company issued $500.0 million in aggregate principal amount of 5.375% Senior Notes due 2025 (the “2025 Senior Notes”). The 2025 Senior Notes bear interest at a rate of 5.375% per annum, payable semi-annually, in arrears on May 31 and November 30 of each year, commencing on May 31, 2017 and will mature on May 31, 2025. All of the Company’s existing and future restricted subsidiaries that guarantee its revolving credit facility or certain other debt guarantee the 2025 Senior Notes, provided, however, that the 2025 Senior Notes are not guaranteed by the Partnership, the General Partner, Viper Energy Partners LLC or Rattler Midstream LLC, and will not be guaranteed by any of the Company’s future unrestricted subsidiaries.

On January 29, 2018, the Company issued $300.0 million aggregate principal amount of new 5.375% Senior Notes due 2025 (the “New 2025 Notes”) as additional notes under, and subject to the terms of, the 2025 Indenture. The New 2025 Notes were issued in a transaction exempt from the registration requirements under the Securities Act. The Company received approximately $308.4 million in net proceeds, after deducting the initial purchaser’s discount and its estimated offering expenses, but disregarding accrued interest, from the issuance of the New 2025 Notes. The Company used the net proceeds from the issuance of the New 2025 Notes to repay a portion of the outstanding borrowings under its revolving credit facility.

The 2025 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 capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting the Company’s restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of the Company’s assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and natural gas business and designate certain of the Company’s subsidiaries as unrestricted subsidiaries.

The Company may on any one or more occasions redeem some or all of the 2025 Senior Notes (including the New 2025 Notes) at any time on or after May 31, 2020 at the redemption prices (expressed as percentages of principal amount) of 104.031% for the 12-month period beginning on May 31, 2020, 102.688% for the 12-month period beginning on May 31, 2021, 101.344% for the 12-month period beginning on May 31, 2022 and 100.000% beginning on May 31, 2023 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to May 31, 2020, the Company may on any one or more occasions redeem all or a portion of the 2025 Senior Notes (including the New 2025 Notes) at a price equal to 100% of the principal amount of the 2025 Senior Notes (including the New 2025 Notes) plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to May 31, 2020, the Company may on any one or more occasions redeem the 2025 Senior Notes (including the New 2025 Notes) in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2025 Senior Notes (including the New 2025 Notes) issued prior to such date at a redemption price of 105.375%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings.

The Company’s Credit Facility

The Company and Diamondback O&G LLC, as borrower, entered into the second amended and restated credit agreement, dated November 1, 2013, as amended, with a syndicate of banks, including Wells Fargo, as administrative agent, and its affiliate Wells Fargo Securities, LLC, as sole book runner and lead arranger. The credit agreement provides for a revolving credit facility in the maximum credit amount of $5.0 billion, subject to a borrowing base based on the Company’s oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be redetermined, under certain circumstances, annually with an effective date of May 1st, and, under certain circumstances, semi-annually with effective dates of May 1st and November 1st. In addition, the Company and Wells Fargo may each request up to two interim redeterminations of the borrowing base during any 12-month period. As of September 30, 2018, the borrowing base was set at $2.0 billion, the Company had elected a commitment amount of $1.0 billion and the Company had no outstanding borrowings under the revolving credit facility and $1.0 billion available for future borrowings under its revolving credit facility. On October 26, 2018, the credit agreement was amended to increase the borrowing base to $2.5 billion, which was increased further to $2.65 billion on November 6, 2018 following the closing of the Company’s acquisition of assets from Ajax Resources, LLC and satisfaction of certain other conditions. The Company also elected to increase the commitment amount from $1.0 billion to $2.0 billion effective October 26, 2018. In addition, this amendment increased the Company’s flexibility to make restricted payments and redeem senior unsecured notes.

Diamondback O&G LLC is the borrower under the credit agreement. As of December 31, 2017, the credit agreement is guaranteed by the Company, Diamondback E&P LLC and Rattler Midstream LLC (formerly known as White Fang Energy LLC) and will also be guaranteed by any of the Company’s future subsidiaries that are classified as restricted subsidiaries under the credit agreement. The credit agreement is also secured by substantially all of the assets of the Company, Diamondback O&G LLC and the guarantors.

The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by the Company that is equal to an alternate 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 0.25% to 1.25% in the case of the alternate base rate and from 1.25% to 2.25% in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the least of the maximum credit amount, the borrowing base and the elected commitment amount. 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 commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. 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 commitment or 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, 2022.

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

Financial Covenant	Required Ratio
Ratio of total net debt to EBITDAX, as defined in the credit agreement	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, as amended in November 2017, allows for the issuance of unsecured debt in the form of senior or senior subordinated notes if no default would result from the incurrence of such debt after giving effect thereto and if, in connection with any such issuance, the borrowing base is reduced by 25% of the stated principal amount of each such issuance.

As of September 30, 2018 and December 31, 2017, 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.

The Partnership’s Credit Agreement

On July 8, 2014, the Partnership entered into a secured revolving credit agreement with Wells Fargo, as administrative agent, certain other lenders and the Operating Company, the Partnership’s consolidated subsidiary, as guarantor. On May 8, 2018, the Operating Company assumed all liabilities as borrower under the credit agreement and the Partnership became a guarantor of the credit agreement. On July 20, 2018, the Operating Company, the Partnership, Wells Fargo and the other lenders amended and restated the credit agreement to reflect the assumption by the Operating Company.

The credit agreement, as amended and restated, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base based on the Partnership’s oil and natural gas reserves and other factors (the “borrowing base”) of $475.0 million, subject to scheduled semi-annual and other borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and October 26th. In addition, the Operating Company and Wells Fargo each may request up to three interim redeterminations of the borrowing base during any 12-month period. As of September 30, 2018, the borrowing base was set at $475.0 million, and there was $296.5 million of outstanding borrowings and $178.5 million available for future borrowings under the revolving credit facility. In connection with the Partnership’s fall 2018 redetermination, the Partnership’s borrowing base was increased to $555.0 million effective October 26, 2018.

The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by the Operating Company that is equal to an alternate 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 0.75% to 1.75% per annum in the case of the alternate base rate and from 1.75% to 2.75% per annum in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the lesser of the maximum credit amount and the borrowing base. The Operating Company is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. 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 (i) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (ii) 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 (iii) at the maturity date of November 1, 2022. The loan is secured by substantially all of the assets of the Partnership and the Operating Company.

The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, purchases of margin stock, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements, and require the maintenance of the financial ratios described below:

Financial Covenant	Required Ratio
Ratio of total net debt to EBITDAX, as defined in the credit agreement	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 $400.0 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.

The lenders may accelerate all of the indebtedness under the credit agreement 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.

Alliance with Obsidian Resources, L.L.C.

The Company entered into a participation and development agreement (the “DrillCo Agreement”), dated September 10, 2018, with Obsidian Resources, L.L.C. (“CEMOF”) to fund oil and natural gas development. Funds managed by CEMOF and its affiliates have agreed to commit to funding certain costs out of CEMOF’s net production revenue and, for a period of time, to the extent not funded by such revenue, up to an additional $300.0 million, to fund drilling programs on locations provided by the Company. Subject to adjustments depending on asset characteristics and return expectations of the selected drilling plan, CEMOF will fund up to 85% of the costs associated with new wells drilled under the DrillCo Agreement and is expected to receive an 80% working interest in these wells until it reaches certain payout thresholds equal to a cumulative 9% and then 13% internal rate of return. Upon reaching the final internal rate of return target, CEMOF’s interest will be reduced to 15%, while the Company’s interest will increase to 85%.

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Capital Stock and Earnings Per Share

9 Months Ended

Sep. 30, 2018

Equity [Abstract]

Capital Stock and Earnings Per Share

CAPITAL STOCK AND EARNINGS PER SHARE

Diamondback did not complete any equity offerings during the nine months endedSeptember 30, 2018 and September 30, 2017.

Partnership Equity Offerings

In January 2017, the Partnership completed an underwritten public offering of 9,775,000 common units, which included 1,275,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. The Partnership received net proceeds from this offering of approximately $147.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which the Partnership used $120.5 million to repay the outstanding borrowings under its revolving credit agreement and the balance was used for general partnership purposes, which included additional acquisitions.

In July 2017, the Partnership completed an underwritten public offering of 16,100,000 common units, which included 2,100,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. In this offering, the Company purchased 700,000 common units, an affiliate of the General Partner purchased 3,000,000 common units and certain officers and directors of the Company and the General Partner purchased an aggregate of 114,000 common units, in each case directly from the underwriters. The Partnership received net proceeds from this offering of approximately $232.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which the Partnership used $152.8 million to repay all of the then-outstanding borrowings under the Partnership’s revolving credit facility and the balance was used to fund a portion of the purchase price for acquisitions and for general partnership purposes.

In July 2018, the Partnership completed an underwritten public offering of 10,080,000 common units, which included 1,080,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Following this offering, Diamondback owned approximate 59% of the total Partnership units then outstanding. The Partnership received net proceeds from this offering of approximately $303.1 million, after deducting underwriting discounts and commissions and estimated offering expenses. The Partnership used the net proceeds to purchase units of the Operating Company. The Operating Company in turn used the net proceeds to repay a portion of the $361.5 million then outstanding borrowings under its revolving credit facility.

Earnings Per Share

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

A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands, except per share amounts)
Net income attributable to common stock	$	157,054	$	73,024	$	539,012	$	367,702
Weighted average common shares outstanding
Basic weighted average common units outstanding	98,638		98,144		98,603		96,491
Effect of dilutive securities:
Potential common shares issuable	180		225		217		261
Diluted weighted average common shares outstanding	98,818		98,369		98,820		96,752
Basic net income attributable to common stock	$	1.59	$	0.74	$	5.47	$	3.81
Diluted net income attributable to common stock	$	1.59	$	0.74	$	5.45	$	3.80

For the three months ended September 30, 2018 and 2017, there were 12,699 shares and 52,857 shares, respectively, and during the nine months ended September 30, 2018 and 2017, there were 2,300 and 1,248 shares, respectively, that were not included in the computation of diluted earnings per share because their inclusion would have been anti-dilutive for the periods presented. These shares could dilute basic earnings per share in future periods.

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Equity-Based Compensation

9 Months Ended

Sep. 30, 2018

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Equity Based Compensation

EQUITY-BASED COMPENSATION

The following table presents the effects of the equity compensation plans and related costs:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands)
General and administrative expenses	$	5,350	$	6,187	$	18,451	$	19,418
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	2,338		2,167		7,328		6,411

Restricted Stock Units

The following table presents the Company’s restricted stock units activity under the Equity Plan during the nine months ended September 30, 2018:

	Restricted Stock Awards & Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2017	243,577		$	90.88
Granted	90,115		$	115.03
Vested	(170,014	)	$	89.08
Forfeited	(7,597	)	$	95.80
Unvested at September 30, 2018	156,081		$	106.54

The aggregate fair value of restricted stock units that vested during the nine months ended September 30, 2018 and 2017 was $15.1 million and $14.8 million, respectively. As of September 30, 2018, the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $13.0 million. Such cost is expected to be recognized over a weighted-average period of 1.4 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 two-year or three-year performance period.

In February 2018, eligible employees received performance restricted stock unit awards totaling 117,423 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, 2018 to December 31, 2020 and cliff vest at December 31, 2020.

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 for the February 2018 awards.

	2018
	Three-Year Performance Period
Grant-date fair value	$	170.45
Risk-free rate	1.99		%
Company volatility	35.90		%

The following table presents the Company’s performance restricted stock units activity under the Equity Plan for the nine months ended September 30, 2018:

	Performance Restricted Stock Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2017	202,326		$	139.83
Granted	285,737		$	130.96
Vested	(168,314	)	$	103.41
Unvested at September 30, 2018(1)	319,749		$	151.08

(1) A maximum of 639,498 units could be awarded based upon the Company’s final TSR ranking.

As of September 30, 2018, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $23.0 million. Such cost is expected to be recognized over a weighted-average period of 1.2 years.

Partnership Unit Options

The following table presents the unit option activity under the Viper LTIP for the nine months ended September 30, 2018:

			Weighted Average
	Unit Options		Exercise Price		Remaining Term	Intrinsic Value
					(in years)	(in thousands)
Outstanding at December 31, 2017	7,600		$	18.49
Exercised	(7,600	)	$	18.49
Outstanding at September 30, 2018	—		$	—	0.00	$	—

The aggregate intrinsic value of unit options that were exercised during the nine months ended September 30, 2018 were $0.2 million.

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 units entitle 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 nine months ended September 30, 2018.

	Phantom Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2017	105,439		$	17.10
Granted	119,818		$	24.46
Vested	(102,811	)	$	19.23
Unvested at September 30, 2018	122,446		$	22.52

The aggregate fair value of phantom units that vested during the nine months ended September 30, 2018 was $2.0 million. As of September 30, 2018, the unrecognized compensation cost related to unvested phantom units was $2.0 million. Such cost is expected to be recognized over a weighted-average period of 1.3 years.

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Related Party Transactions

9 Months Ended

Sep. 30, 2018

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS

Advisory Services Agreement - The Partnership

In connection with the closing of the Viper Offering, the Partnership and the 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 the General Partner with general financial and strategic advisory services related to the business in return for an annual fee of $0.5 million, plus reasonable out-of-pocket expenses. The Viper Advisory Services Agreement had an initial term of two years commencing on June 23, 2014, and will continue for additional one-year periods unless terminated in writing by either party at least ten days prior to the expiration of the then current term. The Partnership did not pay any amounts during the three months and nine months endedSeptember 30, 2018 or September 30, 2017 under the Viper Advisory Services Agreement.

Lease Bonus - The Partnership

During the three months and nine months endedSeptember 30, 2018, the Company paid the Partnership $2.9 million in lease bonus payments to extend the term of 12 leases, reflecting an average bonus of $6,412 per acre. During the three months ended September 30, 2017, the Company did not pay the Partnership any lease bonus payments. During the nine months ended September 30, 2017, the Company paid the Partnership $0.1 million in lease bonus payments to extend the term of two leases, reflecting an average bonus of $7,459 per acre.

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Income Taxes

9 Months Ended

Sep. 30, 2018

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

INCOME TAXES

The Company’s effective income tax rates were 11.5% and 1.2% for the nine months endedSeptember 30, 2018 and 2017, respectively. Total income tax expense for the nine months endedSeptember 30, 2018 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income primarily due to (i) the impact of deferred taxes recognized by the Partnership as a result of its change in tax status, (ii) current and deferred state income taxes, (iii) net income attributable to the non-controlling interest, and (iv) the impact of permanent differences between book and taxable income. The Company recorded a discrete income tax benefit of approximately $0.8 million related to equity-based compensation for the nine months endedSeptember 30, 2018 and a discrete benefit of approximately $72.7 million related to deferred taxes on the Partnership’s investment in the Operating Company arising from the change in the Partnership’s tax status. Total income tax expense for the nine months endedSeptember 30, 2017differed from amounts computed by applying the federal statutory rate to pre-tax income primarily due to state income taxes and the change in the valuation allowance which offset the Company’s federal net deferred tax position in that period.

The Tax Cuts and Jobs Act, a historic reform of the U.S. federal income tax statutes, was enacted on December 22, 2017. As of the completion of the Company’s financial statements for the year ended December 31, 2017, the Company had substantially completed its accounting for the effects of the enactment of the Tax Cuts and Jobs Act and, with respect to those items for which the Company’s accounting was not complete, the Company made reasonable estimates of the effects on its deferred tax balances. At September 30, 2018, the Company had not made an adjustment to the provisional estimates recorded for the year ended December 31, 2017. The Company has considered in its estimated annual effective tax rate for 2018 the impact of the statutory changes enacted by the Tax Cuts and Jobs Act, including reasonable estimates of those provisions effective for the 2018 tax year.

As discussed further in Note 5, on March 29, 2018, the Partnership announced that the Board of Directors of its General Partner had unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity, which change became effective on May 10, 2018. The transactions undertaken in connection with the change in the Partnership’s tax status were not taxable to the Company. Subsequent to the Partnership’s change in tax status, the Partnership’s provision for income taxes for the period ended September 30, 2018 is based on its estimated annual effective tax rate plus discrete items. As such, the Partnership’s provision for income taxes is included in the Company’s consolidated financial statements and to the extent applicable, in net income attributable to the non-controlling interest.

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Derivatives

9 Months Ended

Sep. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

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 fixed price swap contracts, fixed price basis swap contracts and three-way costless collars with corresponding put, short put and call options to reduce price volatility associated with certain of its oil and natural gas sales. With respect to the Company’s fixed price swap contracts and fixed price basis 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 or basis 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 or basis price. The Company has fixed price basis swaps for the spread between the WTI Midland price and the WTI Cushing price.

Under the Company’s costless collar contracts, a three-way collar is a combination of three options: a ceiling call, a floor put, and a short put. The counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the ceiling price to a maximum of the difference between the floor price and the short put price.  The Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the ceiling price. If the settlement price is between the floor and the ceiling price, there is no payment required.

The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing (Cushing and Magellan East Houston) and Crude Oil Brent, and with natural gas derivative settlements based on the New York Mercantile Exchange Henry Hub pricing.

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

As of September 30, 2018, the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.

	2018				2019
	Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)			Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)
Oil Swaps - WTI Cushing	2,392,000	$	51.27		1,638,000	$	52.78
Oil Swaps - WTI Magellan East Houston	644,000	$	71.06		1,087,000	$	40.37
Oil Swaps - BRENT	920,000	$	62.51		725,000	$	72.63
Oil Basis Swaps	1,380,000	$	(0.88	)	270,000	$	(9.42	)
Natural Gas Swaps	1,840,000	$	3.07		—	$	—

	October 2018 - December 2018		January 2019 - December 2019
Oil Three-Way Collars	WTI Magellan East Houston		WTI Cushing		Brent		WTI Magellan East Houston
Volume (Bbls)	644,000		1,810,000		2,000,000		994,000
Short put price (per Bbl)	$	56.43	$	45.00	$	55.00	$	56.82
Floor price (per Bbl)	$	66.43	$	55.00	$	65.00	$	66.82
Ceiling price (per Bbl)	$	78.82	$	70.23	$	82.47	$	77.60

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, 2018 and December 31, 2017.

	September 30, 2018		December 31, 2017
	(in thousands)
Gross amounts of assets presented in the Consolidated Balance Sheet	$	—	$	531
Net amounts of assets presented in the Consolidated Balance Sheet	—		531
Gross amounts of liabilities presented in the Consolidated Balance Sheet	129,757		106,670
Net amounts of liabilities presented in the Consolidated Balance Sheet	$	129,757	$	106,670

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, 2018		December 31, 2017
	(in thousands)
Current assets: derivative instruments	$	—	$	531
Noncurrent assets: derivative instruments	—		—
Total assets	$	—	$	531
Current liabilities: derivative instruments	$	123,826	$	100,367
Noncurrent liabilities: derivative instruments	5,931		6,303
Total liabilities	$	129,757	$	106,670

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(in thousands)
Change in fair value of open non-hedge derivative instruments	$	(9,913	)	$	(58,645	)	$	(23,618	)	$	9,365
Gain (loss) on settlement of non-hedge derivative instruments	(38,460		)	8,000			(115,687		)	11,011
Gain (loss) on derivative instruments	$	(48,373	)	$	(50,645	)	$	(139,305	)	$	20,376

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Fair Value Measurements

9 Months Ended

Sep. 30, 2018

Fair Value Disclosures [Abstract]

Fair Value Measurements

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.

The Company estimates the fair values of proved oil and natural gas properties assumed in business combinations using discounted cash flow techniques and based on market assumptions as to the future commodity prices, internal estimates of future quantities of oil and natural gas reserves, future estimated rates of production, expected recovery rates and risk-adjustment discounts. The estimated fair values of unevaluated oil and natural gas properties were based on the location, engineering and geological studies, historical well performance, and applicable mineral lease terms. Given the unobservable nature of the inputs, the estimated fair values of oil and natural gas properties assumed is deemed to use Level 3 inputs. The asset retirement obligations assumed as part of business combinations are estimated using the same assumptions and methodology as described below.

The Company estimates asset retirement obligations pursuant to the provisions of the Financial Accounting Standards Board issued Accounting Standards Codification Topic 410, “Asset Retirement and Environmental Obligations”. The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with the future plugging and abandonment of wells and related facilities. Given the unobservable nature of the inputs, including plugging costs and useful lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 7—Asset Retirement Obligations for further discussion of the Company’s asset retirement obligations.

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 and cost method investment. The fair values of the Company’s fixed price swaps, fixed price basis swaps and costless collars are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs.

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2018 and December 31, 2017.

	September 30, 2018
	Level 1		Level 2			Level 3
	(in thousands)
Assets:
Investment	$	20,240	$	—		$	—
Liabilities:
Fixed price swaps	$	—	$	(129,757	)	$	—

	December 31, 2017
	Level 1		Level 2			Level 3
	(in thousands)
Assets:
Investment	$	—	$	—		$	—
Liabilities:
Fixed price swaps	$	—	$	(106,139	)	$	—

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 balance sheets:

	September 30, 2018				December 31, 2017
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
	(in thousands)
Debt:
Revolving credit facility	$	—	$	—	$	397,000	$	397,000
4.750% Senior Notes due 2024	$	1,250,000	$	1,252,613	$	500,000	$	501,855
5.375% Senior Notes due 2025	$	800,000	$	819,000	$	500,000	$	515,000
Partnership revolving credit facility	$	296,500	$	296,500	$	93,500	$	93,500

The fair value of the revolving credit facility and the Partnership’s revolving credit facility approximates their 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, 2018 quoted market price, a Level 1 classification in the fair value hierarchy.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

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

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Subsequent Events

9 Months Ended

Sep. 30, 2018

Subsequent Events [Abstract]

Subsequent Events [Text Block]

SUBSEQUENT EVENTS

Recent Acquisitions and Divestitures

Ajax Resources, LLC

On July 22, 2018, the Company entered into a definitive purchase agreement to acquire all leasehold interests and related assets of Ajax Resources, LLC which includes approximately 25,493 net leasehold acres in the Northern Midland Basin for $900.0 million in cash, subject to certain adjustments, and approximately 2.6 million shares of the Company’s common stock. This transaction closed October 31, 2018, and was effective as of July 1, 2018. See Note 4—Acquisitions for additional information regarding the Ajax acquisition.

The cash portion of the purchase price for the Ajax acquisition was funded through a combination of cash on hand, proceeds from the sale of mineral interests to the Partnership, borrowing under the Company’s revolving credit facility and a portion of the proceeds from the Company’s September 2018 senior note offering. See Note 9—Debt for information relating to this offering.

ExL Petroleum Management, LLC and Energy Quest II LLC

On October 31, 2018, the Company completed the acquisition of approximately 3,646 net leasehold acres and related assets in the Northern Midland Basin from ExL Petroleum Management, LLC, ExL Petroleum Operating, Inc. and EnergyQuest II LLC for $312.5 million in cash, subject to certain adjustments. See Note 4—Acquisitions for additional information regarding this acquisition.

Divestiture of Oil and Natural Gas Properties

On November 1, 2018, the Company completed its divestiture of certain oil and natural gas properties in the Delaware Basin for an aggregate sale price of $62.1 million. This transaction included the divestiture of approximately 2,485 gross (2,072 net) acres primarily in Pecos county, Texas.

Third Quarter Dividend Declaration

On November 5, 2018, the Board of Directors of the Company declared a cash dividend for the third quarter of 2018 of $0.125 per share of common stock, payable on November 26, 2018 to its stockholders of record at the close of business on November 19, 2018.

Commodity Contracts

Subsequent to September 30, 2018, the Company entered into new fixed price basis swaps. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing (Cushing and Magellan East Houston) and Crude Oil Brent.

The following tables present the derivative contracts entered into by the Company subsequent to September 30, 2018. When aggregating multiple contracts, the weighted average contract price is disclosed.

	Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)
April 2019 - December 2019
Oil Swaps - WTI Magellan East Houston	458,000	$	76.18
Oil Swaps - BRENT	275,000	$	77.58

The Company’s Credit Facility

On October 26, 2018, the Company’s borrowing base under its credit agreement was increased to $2.5 billion and was increased further to $2.65 billion on November 6, 2018 following the closing of the Company’s acquisition of assets from Ajax Resources, LLC and satisfaction of certain other conditions. The Company also elected to increase the commitment amount from $1.0 billion to $2.0 billion effective October 26, 2018.

The Partnership’s Credit Facility

In connection with the Partnership’s fall 2018 redetermination, the Partnership’s borrowing base was increased to $555.0 million effective October 26, 2018.

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Guarantor Financial Statements

9 Months Ended

Sep. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Guarantor Financial Statements

GUARANTOR FINANCIAL STATEMENTS

As of September 30, 2018, Diamondback E&P LLC and Diamondback O&G LLC (the “Guarantor Subsidiaries”) are guarantors under the indentures relating to the 2024 Senior Notes and the 2025 Senior Notes, as supplemented. In connection with the issuance of the 2024 Senior Notes and the 2025 Senior Notes (including the New 2025 Senior Notes), the Partnership, the General Partner, Viper Energy Partners LLC and Rattler Midstream LLC were designated as Non-Guarantor Subsidiaries. The following presents condensed consolidated financial information for the Company (which for purposes of this Note 18 is referred to as the “Parent”), the Guarantor Subsidiaries and the Non–Guarantor Subsidiaries 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.

Condensed Consolidated Balance Sheet
September 30, 2018
(In thousands)
						Non–
			Guarantor			Guarantor
	Parent		Subsidiaries			Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	471,148	$	20,469		$	16,829		$	—		$	508,446
Accounts receivable	—		226,299			38,018			—			264,317
Accounts receivable - related party	—		—			7,758			(7,758		)	—
Intercompany receivable	3,199,881		262,503			—			(3,462,384		)	—
Inventories	—		14,815			—			—			14,815
Other current assets	257		7,708			146			—			8,111
Total current assets	3,671,286		531,794			62,751			(3,470,142		)	795,689
Property and equipment:
Oil and natural gas properties, at cost, full cost method of accounting	—		9,209,250			1,612,425			(3,297		)	10,818,378
Midstream assets	—		355,758			—			—			355,758
Other property, equipment and land	—		80,194			5,688			—			85,882
Accumulated depletion, depreciation, amortization and impairment	—		(2,306,710		)	(230,784		)	(7,918		)	(2,545,412		)
Net property and equipment	—		7,338,492			1,387,329			(11,215		)	8,714,606
Funds held in escrow	—		62,034			—			—			62,034
Investment in subsidiaries	4,631,753		989			—			(4,632,742		)	—
Deferred tax asset	—		—			95,551			—			95,551
Investment in real estate, net	—		106,834			—			—			106,834
Other assets	—		8,513			23,346			—			31,859
Total assets	$	8,303,039	$	8,048,656		$	1,568,977		$	(8,114,099	)	$	9,806,573
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	—	$	85,865		$	4		$	—		$	85,869
Intercompany payable	—		3,470,142			—			(3,470,142		)	—
Other current liabilities	41,026		590,186			4,706			—			635,918
Total current liabilities	41,026		4,146,193			4,710			(3,470,142		)	721,787
Long-term debt	2,035,859		—			296,500			—			2,332,359
Derivative instruments	—		5,931			—			—			5,931
Asset retirement obligations	—		23,897			—			—			23,897
Deferred income taxes	292,795		—			—			—			292,795
Other long-term liabilities	—		7			—			—			7
Total liabilities	2,369,680		4,176,028			301,210			(3,470,142		)	3,376,776
Commitments and contingencies
Stockholders’ equity	5,933,359		3,872,628			572,217			(4,444,845		)	5,933,359
Non-controlling interest	—		—			695,550			(199,112		)	496,438
Total equity	5,933,359		3,872,628			1,267,767			(4,643,957		)	6,429,797
Total liabilities and equity	$	8,303,039	$	8,048,656		$	1,568,977		$	(8,114,099	)	$	9,806,573

Condensed Consolidated Balance Sheet
December 31, 2017
(In thousands)
						Non–
			Guarantor			Guarantor
	Parent		Subsidiaries			Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	54,074	$	34,175		$	24,197		$	—		$	112,446
Accounts receivable	—		205,859			25,754			—			231,613
Accounts receivable - related party	—		—			5,142			(5,142		)	—
Intercompany receivable	2,624,810		2,267,308			—			(4,892,118		)	—
Inventories	—		9,108			—			—			9,108
Other current assets	618		4,461			355			—			5,434
Total current assets	2,679,502		2,520,911			55,448			(4,897,260		)	358,601
Property and equipment:
Oil and natural gas properties, at cost, full cost method of accounting	—		8,129,211			1,103,897			(414		)	9,232,694
Midstream assets	—		191,519			—			—			191,519
Other property, equipment and land	—		80,776			—			—			80,776
Accumulated depletion, depreciation, amortization and impairment	—		(1,976,248		)	(189,466		)	4,342			(2,161,372		)
Net property and equipment	—		6,425,258			914,431			3,928			7,343,617
Funds held in escrow	—		—			6,304			—			6,304
Investment in subsidiaries	3,809,557		—			—			(3,809,557		)	—
Other assets	—		25,609			36,854			—			62,463
Total assets	$	6,489,059	$	8,971,778		$	1,013,037		$	(8,702,889	)	$	7,770,985
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	1	$	91,629		$	2,960		$	—		$	94,590
Intercompany payable	132,067		4,765,193			—			(4,897,260		)	—
Other current liabilities	7,236		472,933			2,669			—			482,838
Total current liabilities	139,304		5,329,755			5,629			(4,897,260		)	577,428
Long-term debt	986,847		397,000			93,500			—			1,477,347
Derivative instruments	—		6,303			—			—			6,303
Asset retirement obligations	—		20,122			—			—			20,122
Deferred income taxes	108,048		—			—			—			108,048
Total liabilities	1,234,199		5,753,180			99,129			(4,897,260		)	2,189,248
Commitments and contingencies
Stockholders’ equity	5,254,860		3,218,598			913,908			(4,132,506		)	5,254,860
Non-controlling interest	—		—			—			326,877			326,877
Total equity	5,254,860		3,218,598			913,908			(3,805,629		)	5,581,737
Total liabilities and equity	$	6,489,059	$	8,971,778		$	1,013,037		$	(8,702,889	)	$	7,770,985

Condensed Consolidated Statement of Operations
Three Months Ended September 30, 2018
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues:
Oil sales	$	—		$	391,051		$	—		$	63,593		$	454,644
Natural gas sales	—			10,891			—			3,923			14,814
Natural gas liquid sales	—			50,740			—			6,870			57,610
Royalty income	—			—			74,386			(74,386		)	—
Lease bonus	—			—			4,205			(2,883		)	1,322
Midstream services	—			7,280			—			—			7,280
Other operating income	—			2,347			12			—			2,359
Total revenues	—			462,309			78,603			(2,883		)	538,029
Costs and expenses:
Lease operating expenses	—			49,111			—			—			49,111
Production and ad valorem taxes	—			28,509			5,027			—			33,536
Gathering and transportation	—			6,087			889			—			6,976
Midstream services	—			19,725			—			—			19,725
Depreciation, depletion and amortization	—			125,627			16,532			4,159			146,318
General and administrative expenses	6,862			6,629			1,309			(615		)	14,185
Asset retirement obligation accretion	—			387			—			—			387
Other operating expense	—			940			—			—			940
Total costs and expenses	6,862			237,015			23,757			3,544			271,178
Income (loss) from operations	(6,862		)	225,294			54,846			(6,427		)	266,851
Other income (expense)
Interest expense, net	(10,868		)	(3,969		)	(3,711		)	—			(18,548		)
Other income (expense), net	416			1,521			640			(615		)	1,962
Loss on derivative instruments, net	—			(48,373		)	—			—			(48,373		)
Loss on revaluation of investment	—			—			(199		)	—			(199		)
Total other income (expense), net	(10,452		)	(50,821		)	(3,270		)	(615		)	(65,158		)
Income (loss) before income taxes	(17,314		)	174,473			51,576			(7,042		)	201,693
Provision for income taxes	41,512			—			764			—			42,276
Net income (loss)	(58,826		)	174,473			50,812			(7,042		)	159,417
Net income attributable to non-controlling interest	—			—			48,466			(46,103		)	2,363
Net income (loss) attributable to Diamondback Energy, Inc.	$	(58,826	)	$	174,473		$	2,346		$	39,061		$	157,054

Condensed Consolidated Statement of Operations
Three Months Ended September 30, 2017
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues:
Oil sales	$	—		$	223,038		$	—		$	36,011		$	259,049
Natural gas sales	—			11,774			—			3,148			14,922
Natural gas liquid sales	—			22,214			—			3,052			25,266
Royalty income	—			—			42,211			(42,211		)	—
Lease bonus	—			—			322			—			322
Midstream services	—			1,694			—			—			1,694
Total revenues	—			258,720			42,533			—			301,253
Costs and expenses:
Lease operating expenses	—			32,498			—			—			32,498
Production and ad valorem taxes	—			15,546			2,825			—			18,371
Gathering and transportation	—			3,271			205			—			3,476
Midstream services	—			4,445			—			—			4,445
Depreciation, depletion and amortization	—			74,766			11,068			1,745			87,579
General and administrative expenses	6,506			4,629			1,368			(615		)	11,888
Asset retirement obligation accretion	—			357			—			—			357
Total costs and expenses	6,506			135,512			15,466			1,130			158,614
Income (loss) from operations	(6,506		)	123,208			27,067			(1,130		)	142,639
Other income (expense)
Interest expense, net	(6,393		)	(1,940		)	(859		)	—			(9,192		)
Other income (expense), net	9			210			399			(615		)	3
Loss on derivative instruments, net	—			(50,645		)	—			—			(50,645		)
Total other income (expense), net	(6,384		)	(52,375		)	(460		)	(615		)	(59,834		)
Income (loss) before income taxes	(12,890		)	70,833			26,607			(1,745		)	82,805
Provision for income taxes	857			—			—			—			857
Net income (loss)	(13,747		)	70,833			26,607			(1,745		)	81,948
Net income attributable to non-controlling interest	—			—			—			8,924			8,924
Net income (loss) attributable to Diamondback Energy, Inc.	$	(13,747	)	$	70,833		$	26,607		$	(10,669	)	$	73,024

Condensed Consolidated Statement of Operations
Nine Months Ended September 30, 2018
(In thousands)
					Non–
			Guarantor		Guarantor
	Parent		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Revenues:
Oil sales	—		1,149,184		—		185,165		1,334,349
Natural gas sales	—		31,405		—		9,152		40,557
Natural gas liquid sales	—		116,976		—		16,882		133,858
Royalty income	—		—		211,199		(211,199	)	—
Lease bonus	—		—		5,133		(2,883	)	2,250
Midstream services	—		26,658		—		—		26,658
Other operating income	—		6,705		120		—		6,825
Total revenues	—		1,330,928		216,452		(2,883	)	1,544,497
Costs and expenses:
Lease operating expenses	—		129,103		—		—		129,103
Production and ad valorem taxes	—		78,909		14,133		—		93,042
Gathering and transportation	—		16,777		1,297		—		18,074
Midstream services	—		48,515		—		—		48,515
Depreciation, depletion and amortization	—		337,823		41,317		12,261		391,401
General and administrative expenses	20,891		19,763		6,230		(1,845	)	45,039
Asset retirement obligation accretion	—		1,107		—		—		1,107
Other operating expense	—		2,416		—		—		2,416
Total costs and expenses	20,891		634,413		62,977		10,416		728,697
Income (loss) from operations	(20,891	)	696,515		153,475		(13,299	)	815,800
Other income (expense)
Interest expense, net	(29,945	)	(10,339	)	(9,061	)	—		(49,345	)
Other income (expense), net	750		88,786		1,479		(1,845	)	89,170
Loss on derivative instruments, net	—		(139,305	)	—		—		(139,305	)
Gain on revaluation of investment	—		—		5,165		—		5,165
Total other income (expense), net	(29,195	)	(60,858	)	(2,417	)	(1,845	)	(94,315	)
Income (loss) before income taxes	(50,086	)	635,657		151,058		(15,144	)	721,485
Provision for (benefit from) income taxes	153,864		—		(71,114	)	—		82,750
Net income (loss)	(203,950	)	635,657		222,172		(15,144	)	638,735
Net income attributable to non-controlling interest	—		—		77,526		22,197		99,723
Net income (loss) attributable to Diamondback Energy, Inc.	(203,950	)	635,657		144,646		(37,341	)	539,012

Condensed Consolidated Statement of Operations
Nine Months Ended September 30, 2017
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues:
Oil sales	$	—		$	607,381		$	—		$	96,626		$	704,007
Natural gas sales	—			31,088			—			6,449			37,537
Natural gas liquid sales	—			50,506			—			7,119			57,625
Royalty income	—			—			110,194			(110,194		)	—
Lease bonus	—			—			2,613			(106		)	2,507
Midstream services	—			4,241			—			—			4,241
Total revenues	—			693,216			112,807			(106		)	805,917
Costs and expenses:
Lease operating expenses	—			88,113			—			—			88,113
Production and ad valorem taxes	—			42,307			7,668			—			49,975
Gathering and transportation	—			8,618			492			—			9,110
Midstream services	—			7,127			—			—			7,127
Depreciation, depletion and amortization	—			190,748			28,587			2,346			221,681
General and administrative expenses	20,046			14,259			5,064			(1,845		)	37,524
Asset retirement obligation accretion	—			1,030			—			—			1,030
Total costs and expenses	20,046			352,202			41,811			501			414,560
Income (loss) from operations	(20,046		)	341,014			70,996			(607		)	391,357
Other income (expense)
Interest expense, net	(23,526		)	(4,022		)	(2,114		)	—			(29,662		)
Other income (expense), net	1,101			9,690			526			(1,845		)	9,472
Gain on derivative instruments, net	—			20,376			—			—			20,376
Total other income (expense), net	(22,425		)	26,044			(1,588		)	(1,845		)	186
Income (loss) before income taxes	(42,471		)	367,058			69,408			(2,452		)	391,543
Provision for income taxes	4,393			—			—			—			4,393
Net income (loss)	(46,864		)	367,058			69,408			(2,452		)	387,150
Net income attributable to non-controlling interest	—			—			—			19,448			19,448
Net income (loss) attributable to Diamondback Energy, Inc.	$	(46,864	)	$	367,058		$	69,408		$	(21,900	)	$	367,702

Condensed Consolidated Statement of Cash Flows
Nine Months Ended September 30, 2018
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Net cash provided by operating activities	$	220		$	975,082		$	176,414		$	—		$	1,151,716
Cash flows from investing activities:
Additions to oil and natural gas properties	—			(1,010,325		)	—			—			(1,010,325		)
Additions to midstream assets	—			(129,820		)	—			—			(129,820		)
Purchase of other property, equipment and land	—			2,638			(4,687		)	—			(2,049		)
Acquisition of leasehold interests	—			(185,658		)	—			—			(185,658		)
Acquisition of mineral interests	—			170,268			(505,842		)	—			(335,574		)
Proceeds from sale of assets	—			6,206			565			—			6,771
Funds held in escrow	—			(51,045		)	—			—			(51,045		)
Equity investments	—			(604		)	—			—			(604		)
Intercompany transfers	(22,310		)	22,310			—			—			—
Investment in real estate	—			(110,654		)	—			—			(110,654		)
Net cash used in investing activities	(22,310		)	(1,286,684		)	(509,964		)	—			(1,818,958		)
Cash flows from financing activities:
Proceeds from borrowing under credit facility	—			470,500			557,000			—			1,027,500
Repayment under credit facility	—			(867,500		)	(354,000		)	—			(1,221,500		)
Proceeds from senior notes	1,062,000			—			—			—			1,062,000
Debt issuance costs	(13,723		)	(232		)	(623		)	—			(14,578		)
Public offering costs	—			—			(2,636		)	—			(2,636		)
Proceeds from public offerings	—			—			305,773			—			305,773
Contributions to subsidiaries	(1,000		)	—			(1,000		)	2,000			—
Contributions by members	—			—			2,000			(2,000		)	—
Distributions from subsidiary	112,671			—			—			(112,671		)	—
Unit options exercised	—			—			140			—			140
Dividends to stockholders	(24,656		)	—			—			—			(24,656		)
Distributions to non-controlling interest	—			—			(181,472		)	112,671			(68,801		)
Intercompany transfers	(696,128		)	695,128			1,000			—			—
Net cash provided by financing activities	439,164			297,896			326,182			—			1,063,242
Net increase (decrease) in cash and cash equivalents	417,074			(13,706		)	(7,368		)	—			396,000
Cash and cash equivalents at beginning of period	54,074			34,175			24,197			—			112,446
Cash and cash equivalents at end of period	$	471,148		$	20,469		$	16,829		$	—		$	508,446

Condensed Consolidated Statement of Cash Flows
Nine Months Ended September 30, 2017
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(25,369	)	$	569,330		$	94,057		$	—		$	638,018
Cash flows from investing activities:
Additions to oil and natural gas properties	—			(531,489		)	—			—			(531,489		)
Additions to midstream assets	—			(22,491		)	—			—			(22,491		)
Purchase of other property, equipment and land	—			(21,534		)	—			—			(21,534		)
Acquisition of leasehold interests	—			(1,892,864		)	—			—			(1,892,864		)
Acquisition of mineral interests	—			(69,722		)	(301,133		)	—			(370,855		)
Acquisition of midstream assets	—			(50,279		)	—			—			(50,279		)
Proceeds from sale of assets	—			3,584			—			—			3,584
Funds held in escrow	—			121,391			—			—			121,391
Equity investments	—			(188		)	—			—			(188		)
Intercompany transfers	(1,651,328		)	1,651,328			—			—			—
Net cash used in investing activities	(1,651,328		)	(812,264		)	(301,133		)	—			(2,764,725		)
Cash flows from financing activities:
Proceeds from borrowing under credit facility	—			312,500			220,500			—			533,000
Repayment under credit facility	—			(78,000		)	(305,500		)	—			(383,500		)
Purchase of subsidiary units by parent	(10,068		)	—			—			10,068			—
Debt issuance costs	(744		)	(790		)	(180		)	—			(1,714		)
Public offering costs	(77		)	—			(433		)	—			(510		)
Proceeds from public offerings	—			—			380,412			(10,068		)	370,344
Distributions from subsidiary	64,858			—			—			(64,858		)	—
Proceeds from exercise of stock options	358			—			—			—			358
Distributions to non-controlling interest	—			—			(92,498		)	64,858			(27,640		)
Net cash provided by financing activities	54,327			233,710			202,301			—			490,338
Net decrease in cash and cash equivalents	(1,622,370		)	(9,224		)	(4,775		)	—			(1,636,369		)
Cash and cash equivalents at beginning of period	1,643,226			14,135			9,213			—			1,666,574
Cash and cash equivalents at end of period	$	20,856		$	4,911		$	4,438		$	—		$	30,205

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2018

Accounting Policies [Abstract]

Basis of Presentation

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.

Use of Estimates

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.

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

New Accounting Pronouncements

New Accounting Pronouncements

Recently Adopted Pronouncements

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”. This standard included a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. Among other things, the standard also eliminated industry-specific revenue guidance, required enhanced disclosures about revenue, provided guidance for transactions that were not previously addressed comprehensively and improved guidance for multiple-element arrangements. The Company adopted this Accounting Standards Update effective January 1, 2018 using the modified retrospective approach. The Company utilized a bottom-up approach to analyze the impact of the new standard by reviewing its current accounting policies and practices to identify potential differences that would result from applying the requirements of the new standard to its revenue contracts and the impact of adopting this standards update on its total revenues, operating income and its consolidated balance sheet. The adoption of this standard did not result in a cumulative-effect adjustment.

In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. This update applies to any entity that holds financial assets or owes financial liabilities. This update requires equity investments (except for those accounted for under the equity method or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. The Partnership adopted this standard effective January 1, 2018 by means of a negative cumulative-effect adjustment totaling $18.7 million.

In August 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-15, “Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments”. This update apples to all entities that are required to present a statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; including bank-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The Company adopted this update effective January 1, 2018 using the retrospective transition method. Adoption of this standard did not have an effect on the presentation on the Statement of Cash Flows.

In November 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-18, “Statement of Cash Flows - Restricted Cash”. This update affects entities that have restricted cash or restricted cash equivalents. The Company adopted this update effective January 1, 2018. The adoption of this update did not have an effect on the presentation on the Statement of Cash Flows.

In January 2017, the Financial Accounting Standards Board issued Accounting Standards Update 2017-01, “Business Combinations - Clarifying the Definition of a Business”. This update apples to all entities that must determine whether they acquired or sold a business. This update provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The Company adopted this update prospectively effective January 1, 2018. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.

Accounting Pronouncements Not Yet Adopted

In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Company believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases. The Company is still evaluating the impact of this standard.

In January 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-01, “Leases - Land Easement Practical Expedient for Transition to Topic 842”. This update applies to any entity that holds land easements. The update allows entities to adopt a practical expedient to not evaluate existing or expired land easements under Topic 842 that were not previously accounted for as leases under the current leases guidance. An entity that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginning at the date that the entity adopts Topic 842. The Company believes the adoption of this update will not have an impact on its financial position, results of operations or liquidity.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-10, “Codification Improvements to Topic 842, Leases”. This update provides clarification and corrects unintended application of certain sections in the new lease guidance. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases. The Company is still evaluating the impact of this standard.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-11, “Lease (Topic 842): Targeted Improvements”. This update provides another transition method of allowing entities to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases. The Company is still evaluating the impact of this standard.

In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company does not believe the adoption of this standard will have a material impact on the Company’s consolidated financial statements since the Company does not have a history of credit losses.

In June 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-07, “Stock Compensation - Improvements to Nonemployee Share-Based Payment Accounting”. This update applies the existing employee guidance to nonemployee share-based transactions, with the exception of specific guidance related to the attribution of compensation cost. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

In July 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-09, “Codification Improvements”. This update provides clarification and corrects unintended application of the guidance in various sections. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

In August 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-13, “Fair Value Measurement (Topic 820) - Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement”. This update modifies the fair value measurement disclosure requirements specifically related to Level 3 fair value measurements and transfers between levels. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied prospectively. The Company is currently evaluating the impact of the adoption of this update, but does not believe it will have a material impact on its financial position, results of operations or liquidity.

In August 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-15, “Intangibles - Goodwill and Other - Internal - Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract”. This update requires the capitalization of implementation costs incurred in a hosting arrangement that is a service contract for internal-use software. Training and certain data conversion costs cannot be capitalized. The entity is required to expense the capitalized implementation costs over the term of the hosting agreement. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update should be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. The Company believes the adoption of this update will not have an impact on its financial position, results of operations or liquidity.

Revenue Recognition

Revenue from Contracts with Customers

Sales of oil, natural gas and natural gas liquids are recognized at the point control of the product is transferred to the customer. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, the quality of the oil or natural gas and the prevailing supply and demand conditions. As a result, the price of the oil, natural gas and natural gas liquids fluctuates to remain competitive with other available oil, natural gas and natural gas liquids supplies.

Oil sales

The Company’s oil sales contracts are generally structured where it delivers oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of loss of the product. Under this arrangement, the Company or a third party transports the product to the delivery point and receives a specified index price from the purchaser with no deduction. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. Oil revenues are recorded net of any third-party transportation fees and other applicable differentials in the Company’s consolidated statements of operations.

Natural gas and natural gas liquids sales

Under the Company’s natural gas processing contracts, it delivers natural gas to a midstream processing entity at the wellhead, battery facilities or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of natural gas liquids and residue gas. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For those contracts where the Company has concluded it is the principal and the ultimate third party is its customer, the Company recognizes revenue on a gross basis, with transportation, gathering, processing, treating and compression fees presented as an expense in its consolidated statements of operations.

In certain natural gas processing agreements, the Company may elect to take its residue gas and/or natural gas liquids in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing, treating and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as transportation, gathering, processing, treating and compression expense in its consolidated statements of operations.

Midstream Revenue

Substantially all revenues from gathering, compression, water handling, disposal and treatment operations are derived from intersegment transactions for services Rattler Midstream LLC (“Rattler”) provides to exploration and production operations. The portion of such fees shown in the Company’s consolidated financial statements represent amounts charged to interest owners in the Company’s operated wells, as well as fees charged to other third parties for water handling and treatment services provided by Rattler or usage of Rattler’s gathering and compression systems. For gathering and compression revenue, Rattler satisfies its performance obligations and recognizes revenue when low pressure volumes are delivered to a specified delivery point. Revenue is recognized based on the per MMbtu gathering fee or a per barrel gathering fee charged by Rattler in accordance with the gathering and compression agreement. For water handling and treatment revenue, Rattler satisfies its performance obligations and recognizes revenue when the fresh water volumes have been delivered to the fracwater meter for a specified well pad and the wastewater volumes have been metered downstream of the Company’s facilities. For services contracted through third party providers, Rattler’s performance obligation is satisfied when the service performed by the third party provider has been completed. Revenue is recognized based on the per barrel fresh water delivery or a wastewater gathering and disposal fee charged by Rattler in accordance with the water services agreement.

Transaction price allocated to remaining performance obligations

The Company’s upstream product sales contracts do not originate until production occurs and, therefore, are not considered to exist beyond each days’ production. Therefore, there are no remaining performance obligation under any of our product sales contracts.

The majority of the Company’s midstream revenue agreements have a term greater than one year, and as such Rattler LLC has utilized the practical expedient in ASC 606, which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under its revenue agreements, each delivery generally represents a separate performance obligation; therefore, future volumes delivered are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

The remainder of the Company’s midstream revenue agreements, which relate to agreements with third parties, are short-term in nature with a term of one year or less. Rattler LLC has utilized an additional practical expedient in ASC 606 which exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of an agreement that has an original expected duration of one year or less.

Contract balances

Under the Company’s product sales contracts, it has the right to invoice its customers once the performance obligations have been satisfied, at which point payment is unconditional. Accordingly, the Company’s product sales contracts do not give rise to contract assets or liabilities under Accounting Standards Codification 606.

Prior-period performance obligations

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the three months ended September 30, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Company believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the revenue related to expected sales volumes and prices for those properties are estimated and recorded.

Fair Value Measurement

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.

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Acquisitions (Tables)

9 Months Ended

Sep. 30, 2018

Business Acquisition [Line Items]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

The following represents the fair value of the assets and liabilities assumed on the acquisition date. The aggregate consideration transferred was $2.5 billion, resulting in no goodwill or bargain purchase gain.

	(in thousands)
Proved oil and natural gas properties	$	386,308
Unevaluated oil and natural gas properties	2,122,597
Midstream assets	47,432
Prepaid capital costs	3,460
Oil inventory	839
Equipment	163
Revenues and royalties payable	(9,650		)
Asset retirement obligations	(1,550		)
Total fair value of net assets	$	2,549,599

Business Acquisition, Pro Forma Information [Table Text Block]

The following unaudited summary pro forma consolidated statement of operations data of Diamondback for the three months and nine months endedSeptember 30, 2017 have been prepared to give effect to the February 28, 2017 acquisition as if it had occurred on January 1, 2016. The pro forma data are not necessarily indicative of financial results that would have been attained had the acquisitions occurred on January 1, 2016. The pro forma data also necessarily exclude various operation expenses related to the properties and the financial statements should not be viewed as indicative of operations in future periods.

	Three Months Ended September 30, 2017		Nine Months Ended September 30, 2017
	(in thousands, except per share amounts)
Revenues	$	301,253	$	828,846
Income from operations	142,639		405,699
Net income	81,948		382,044
Basic earnings per common share	0.74		3.96
Diluted earnings per common share	0.74		3.95

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Property and Equipment (Tables)

9 Months Ended

Sep. 30, 2018

Property, Plant and Equipment [Abstract]

Property and Equipment

Property and equipment includes the following:

	September 30,			December 31,
	2018			2017
	(in thousands)
Oil and natural gas properties:
Subject to depletion	$	6,534,749		$	5,126,829
Not subject to depletion	4,283,629			4,105,865
Gross oil and natural gas properties	10,818,378			9,232,694
Accumulated depletion	(1,375,163		)	(1,009,893		)
Accumulated impairment	(1,143,498		)	(1,143,498		)
Oil and natural gas properties, net	8,299,717			7,079,303
Midstream assets	355,758			191,519
Other property, equipment and land	85,882			80,776
Accumulated depreciation	(26,751		)	(7,981		)
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment	$	8,714,606		$	7,343,617
Balance of costs not subject to depletion:
Incurred in 2018	$	589,352
Incurred in 2017	2,563,902
Incurred in 2016	714,467
Incurred in 2015	234,948
Incurred in 2014	180,960
Total not subject to depletion	$	4,283,629

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2018

Asset Retirement Obligation [Abstract]

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,
	2018			2017
	(in thousands)
Asset retirement obligations, beginning of period	$	21,285		$	17,422
Additional liabilities incurred	2,229			1,196
Liabilities acquired	270			2,411
Liabilities settled	(1,474		)	(689		)
Accretion expense	1,107			1,030
Revisions in estimated liabilities	568			4
Asset retirement obligations, end of period	23,985			21,374
Less current portion	88			1,392
Asset retirement obligations - long-term	$	23,897		$	19,982

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Debt (Tables)

9 Months Ended

Sep. 30, 2018

Line of Credit Facility [Line Items]

Schedule of long-term debt

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

	September 30,			December 31,
	2018			2017
	(in thousands)
4.750 % Senior Notes due 2024	$	1,250,000		$	500,000
5.375 % Senior Notes due 2025	800,000			500,000
Unamortized debt issuance costs	(25,038		)	(13,153		)
Unamortized premium costs	10,897			—
Revolving credit facility	—			397,000
Partnership revolving credit facility	296,500			93,500
Total long-term debt	$	2,332,359		$	1,477,347

Financial Covenants

Financial Covenant	Required Ratio
Ratio of total net debt to EBITDAX, as defined in the credit agreement	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

Partnership Credit Facility [Member]

Line of Credit Facility [Line Items]

Financial Covenants

Financial Covenant	Required Ratio
Ratio of total net debt to EBITDAX, as defined in the credit agreement	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

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Capital Stock and Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2018

Equity [Abstract]

Schedule of reconciliation of basic and diluted net income per share

A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands, except per share amounts)
Net income attributable to common stock	$	157,054	$	73,024	$	539,012	$	367,702
Weighted average common shares outstanding
Basic weighted average common units outstanding	98,638		98,144		98,603		96,491
Effect of dilutive securities:
Potential common shares issuable	180		225		217		261
Diluted weighted average common shares outstanding	98,818		98,369		98,820		96,752
Basic net income attributable to common stock	$	1.59	$	0.74	$	5.47	$	3.81
Diluted net income attributable to common stock	$	1.59	$	0.74	$	5.45	$	3.80

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Equity-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2018

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

The effects of stock-based compensation plans and related costs

The following table presents the effects of the equity compensation plans and related costs:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
	(in thousands)
General and administrative expenses	$	5,350	$	6,187	$	18,451	$	19,418
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	2,338		2,167		7,328		6,411

Summary of restricted stock units

The following table presents the Company’s restricted stock units activity under the Equity Plan during the nine months ended September 30, 2018:

	Restricted Stock Awards & Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2017	243,577		$	90.88
Granted	90,115		$	115.03
Vested	(170,014	)	$	89.08
Forfeited	(7,597	)	$	95.80
Unvested at September 30, 2018	156,081		$	106.54

Summary of grant-date fair values of performance restricted stock units granted and related assumptions

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 2018 awards.

	2018
	Three-Year Performance Period
Grant-date fair value	$	170.45
Risk-free rate	1.99		%
Company volatility	35.90		%

Schedule of performance restricted stock units activity

The following table presents the Company’s performance restricted stock units activity under the Equity Plan for the nine months ended September 30, 2018:

	Performance Restricted Stock Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2017	202,326		$	139.83
Granted	285,737		$	130.96
Vested	(168,314	)	$	103.41
Unvested at September 30, 2018(1)	319,749		$	151.08

(1) A maximum of 639,498 units could be awarded based upon the Company’s final TSR ranking.

Viper Energy Partners LP Long Term Incentive Plan [Member] | Employee Stock Option [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Partnership unit options activity

The following table presents the unit option activity under the Viper LTIP for the nine months ended September 30, 2018:

			Weighted Average
	Unit Options		Exercise Price		Remaining Term	Intrinsic Value
					(in years)	(in thousands)
Outstanding at December 31, 2017	7,600		$	18.49
Exercised	(7,600	)	$	18.49
Outstanding at September 30, 2018	—		$	—	0.00	$	—

Viper Energy Partners LP Long Term Incentive Plan [Member] | Phantom Share Units (PSUs) [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Phantom units activity

The following table presents the phantom unit activity under the Viper LTIP for the nine months ended September 30, 2018.

	Phantom Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2017	105,439		$	17.10
Granted	119,818		$	24.46
Vested	(102,811	)	$	19.23
Unvested at September 30, 2018	122,446		$	22.52

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Derivatives (Tables)

9 Months Ended

Sep. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of derivative instruments

As of September 30, 2018, the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.

	2018				2019
	Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)			Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)
Oil Swaps - WTI Cushing	2,392,000	$	51.27		1,638,000	$	52.78
Oil Swaps - WTI Magellan East Houston	644,000	$	71.06		1,087,000	$	40.37
Oil Swaps - BRENT	920,000	$	62.51		725,000	$	72.63
Oil Basis Swaps	1,380,000	$	(0.88	)	270,000	$	(9.42	)
Natural Gas Swaps	1,840,000	$	3.07		—	$	—

	October 2018 - December 2018		January 2019 - December 2019
Oil Three-Way Collars	WTI Magellan East Houston		WTI Cushing		Brent		WTI Magellan East Houston
Volume (Bbls)	644,000		1,810,000		2,000,000		994,000
Short put price (per Bbl)	$	56.43	$	45.00	$	55.00	$	56.82
Floor price (per Bbl)	$	66.43	$	55.00	$	65.00	$	66.82
Ceiling price (per Bbl)	$	78.82	$	70.23	$	82.47	$	77.60

The following tables present the derivative contracts entered into by the Company subsequent to September 30, 2018. When aggregating multiple contracts, the weighted average contract price is disclosed.

	Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)
April 2019 - December 2019
Oil Swaps - WTI Magellan East Houston	458,000	$	76.18
Oil Swaps - BRENT	275,000	$	77.58

Schedule of netting offsets of derivative assets and liabilities

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, 2018 and December 31, 2017.

	September 30, 2018		December 31, 2017
	(in thousands)
Gross amounts of assets presented in the Consolidated Balance Sheet	$	—	$	531
Net amounts of assets presented in the Consolidated Balance Sheet	—		531
Gross amounts of liabilities presented in the Consolidated Balance Sheet	129,757		106,670
Net amounts of liabilities presented in the Consolidated Balance Sheet	$	129,757	$	106,670

Schedule of derivative instruments included in the consolidated balance sheet

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, 2018		December 31, 2017
	(in thousands)
Current assets: derivative instruments	$	—	$	531
Noncurrent assets: derivative instruments	—		—
Total assets	$	—	$	531
Current liabilities: derivative instruments	$	123,826	$	100,367
Noncurrent liabilities: derivative instruments	5,931		6,303
Total liabilities	$	129,757	$	106,670

Summary of derivative contract gains and losses included in the consolidated statements of operations

The following table summarizes the gains and losses on derivative instruments included in the consolidated statements of operations:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(in thousands)
Change in fair value of open non-hedge derivative instruments	$	(9,913	)	$	(58,645	)	$	(23,618	)	$	9,365
Gain (loss) on settlement of non-hedge derivative instruments	(38,460		)	8,000			(115,687		)	11,011
Gain (loss) on derivative instruments	$	(48,373	)	$	(50,645	)	$	(139,305	)	$	20,376

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2018

Fair Value Disclosures [Abstract]

Fair value measurement information for financial instruments measured on a recurring basis

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, 2018 and December 31, 2017.

	September 30, 2018
	Level 1		Level 2			Level 3
	(in thousands)
Assets:
Investment	$	20,240	$	—		$	—
Liabilities:
Fixed price swaps	$	—	$	(129,757	)	$	—

	December 31, 2017
	Level 1		Level 2			Level 3
	(in thousands)
Assets:
Investment	$	—	$	—		$	—
Liabilities:
Fixed price swaps	$	—	$	(106,139	)	$	—

Fair value measurement information for financial instruments measured on a nonrecurring basis

The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated balance sheets:

	September 30, 2018				December 31, 2017
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
	(in thousands)
Debt:
Revolving credit facility	$	—	$	—	$	397,000	$	397,000
4.750% Senior Notes due 2024	$	1,250,000	$	1,252,613	$	500,000	$	501,855
5.375% Senior Notes due 2025	$	800,000	$	819,000	$	500,000	$	515,000
Partnership revolving credit facility	$	296,500	$	296,500	$	93,500	$	93,500

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Subsequent Events (Tables)

9 Months Ended

Sep. 30, 2018

Subsequent Event [Line Items]

Schedule of derivative instruments

As of September 30, 2018, the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.

	2018				2019
	Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)			Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)
Oil Swaps - WTI Cushing	2,392,000	$	51.27		1,638,000	$	52.78
Oil Swaps - WTI Magellan East Houston	644,000	$	71.06		1,087,000	$	40.37
Oil Swaps - BRENT	920,000	$	62.51		725,000	$	72.63
Oil Basis Swaps	1,380,000	$	(0.88	)	270,000	$	(9.42	)
Natural Gas Swaps	1,840,000	$	3.07		—	$	—

	October 2018 - December 2018		January 2019 - December 2019
Oil Three-Way Collars	WTI Magellan East Houston		WTI Cushing		Brent		WTI Magellan East Houston
Volume (Bbls)	644,000		1,810,000		2,000,000		994,000
Short put price (per Bbl)	$	56.43	$	45.00	$	55.00	$	56.82
Floor price (per Bbl)	$	66.43	$	55.00	$	65.00	$	66.82
Ceiling price (per Bbl)	$	78.82	$	70.23	$	82.47	$	77.60

The following tables present the derivative contracts entered into by the Company subsequent to September 30, 2018. When aggregating multiple contracts, the weighted average contract price is disclosed.

	Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)
April 2019 - December 2019
Oil Swaps - WTI Magellan East Houston	458,000	$	76.18
Oil Swaps - BRENT	275,000	$	77.58

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Guarantor Financial Statements (Tables)

9 Months Ended

Sep. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Condensed Consolidated Balance Sheet

Condensed Consolidated Balance Sheet
September 30, 2018
(In thousands)
						Non–
			Guarantor			Guarantor
	Parent		Subsidiaries			Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	471,148	$	20,469		$	16,829		$	—		$	508,446
Accounts receivable	—		226,299			38,018			—			264,317
Accounts receivable - related party	—		—			7,758			(7,758		)	—
Intercompany receivable	3,199,881		262,503			—			(3,462,384		)	—
Inventories	—		14,815			—			—			14,815
Other current assets	257		7,708			146			—			8,111
Total current assets	3,671,286		531,794			62,751			(3,470,142		)	795,689
Property and equipment:
Oil and natural gas properties, at cost, full cost method of accounting	—		9,209,250			1,612,425			(3,297		)	10,818,378
Midstream assets	—		355,758			—			—			355,758
Other property, equipment and land	—		80,194			5,688			—			85,882
Accumulated depletion, depreciation, amortization and impairment	—		(2,306,710		)	(230,784		)	(7,918		)	(2,545,412		)
Net property and equipment	—		7,338,492			1,387,329			(11,215		)	8,714,606
Funds held in escrow	—		62,034			—			—			62,034
Investment in subsidiaries	4,631,753		989			—			(4,632,742		)	—
Deferred tax asset	—		—			95,551			—			95,551
Investment in real estate, net	—		106,834			—			—			106,834
Other assets	—		8,513			23,346			—			31,859
Total assets	$	8,303,039	$	8,048,656		$	1,568,977		$	(8,114,099	)	$	9,806,573
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	—	$	85,865		$	4		$	—		$	85,869
Intercompany payable	—		3,470,142			—			(3,470,142		)	—
Other current liabilities	41,026		590,186			4,706			—			635,918
Total current liabilities	41,026		4,146,193			4,710			(3,470,142		)	721,787
Long-term debt	2,035,859		—			296,500			—			2,332,359
Derivative instruments	—		5,931			—			—			5,931
Asset retirement obligations	—		23,897			—			—			23,897
Deferred income taxes	292,795		—			—			—			292,795
Other long-term liabilities	—		7			—			—			7
Total liabilities	2,369,680		4,176,028			301,210			(3,470,142		)	3,376,776
Commitments and contingencies
Stockholders’ equity	5,933,359		3,872,628			572,217			(4,444,845		)	5,933,359
Non-controlling interest	—		—			695,550			(199,112		)	496,438
Total equity	5,933,359		3,872,628			1,267,767			(4,643,957		)	6,429,797
Total liabilities and equity	$	8,303,039	$	8,048,656		$	1,568,977		$	(8,114,099	)	$	9,806,573

Condensed Consolidated Balance Sheet
December 31, 2017
(In thousands)
						Non–
			Guarantor			Guarantor
	Parent		Subsidiaries			Subsidiaries			Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	54,074	$	34,175		$	24,197		$	—		$	112,446
Accounts receivable	—		205,859			25,754			—			231,613
Accounts receivable - related party	—		—			5,142			(5,142		)	—
Intercompany receivable	2,624,810		2,267,308			—			(4,892,118		)	—
Inventories	—		9,108			—			—			9,108
Other current assets	618		4,461			355			—			5,434
Total current assets	2,679,502		2,520,911			55,448			(4,897,260		)	358,601
Property and equipment:
Oil and natural gas properties, at cost, full cost method of accounting	—		8,129,211			1,103,897			(414		)	9,232,694
Midstream assets	—		191,519			—			—			191,519
Other property, equipment and land	—		80,776			—			—			80,776
Accumulated depletion, depreciation, amortization and impairment	—		(1,976,248		)	(189,466		)	4,342			(2,161,372		)
Net property and equipment	—		6,425,258			914,431			3,928			7,343,617
Funds held in escrow	—		—			6,304			—			6,304
Investment in subsidiaries	3,809,557		—			—			(3,809,557		)	—
Other assets	—		25,609			36,854			—			62,463
Total assets	$	6,489,059	$	8,971,778		$	1,013,037		$	(8,702,889	)	$	7,770,985
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	1	$	91,629		$	2,960		$	—		$	94,590
Intercompany payable	132,067		4,765,193			—			(4,897,260		)	—
Other current liabilities	7,236		472,933			2,669			—			482,838
Total current liabilities	139,304		5,329,755			5,629			(4,897,260		)	577,428
Long-term debt	986,847		397,000			93,500			—			1,477,347
Derivative instruments	—		6,303			—			—			6,303
Asset retirement obligations	—		20,122			—			—			20,122
Deferred income taxes	108,048		—			—			—			108,048
Total liabilities	1,234,199		5,753,180			99,129			(4,897,260		)	2,189,248
Commitments and contingencies
Stockholders’ equity	5,254,860		3,218,598			913,908			(4,132,506		)	5,254,860
Non-controlling interest	—		—			—			326,877			326,877
Total equity	5,254,860		3,218,598			913,908			(3,805,629		)	5,581,737
Total liabilities and equity	$	6,489,059	$	8,971,778		$	1,013,037		$	(8,702,889	)	$	7,770,985

Condensed Consolidated Statement of Operations

Condensed Consolidated Statement of Operations
Three Months Ended September 30, 2018
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues:
Oil sales	$	—		$	391,051		$	—		$	63,593		$	454,644
Natural gas sales	—			10,891			—			3,923			14,814
Natural gas liquid sales	—			50,740			—			6,870			57,610
Royalty income	—			—			74,386			(74,386		)	—
Lease bonus	—			—			4,205			(2,883		)	1,322
Midstream services	—			7,280			—			—			7,280
Other operating income	—			2,347			12			—			2,359
Total revenues	—			462,309			78,603			(2,883		)	538,029
Costs and expenses:
Lease operating expenses	—			49,111			—			—			49,111
Production and ad valorem taxes	—			28,509			5,027			—			33,536
Gathering and transportation	—			6,087			889			—			6,976
Midstream services	—			19,725			—			—			19,725
Depreciation, depletion and amortization	—			125,627			16,532			4,159			146,318
General and administrative expenses	6,862			6,629			1,309			(615		)	14,185
Asset retirement obligation accretion	—			387			—			—			387
Other operating expense	—			940			—			—			940
Total costs and expenses	6,862			237,015			23,757			3,544			271,178
Income (loss) from operations	(6,862		)	225,294			54,846			(6,427		)	266,851
Other income (expense)
Interest expense, net	(10,868		)	(3,969		)	(3,711		)	—			(18,548		)
Other income (expense), net	416			1,521			640			(615		)	1,962
Loss on derivative instruments, net	—			(48,373		)	—			—			(48,373		)
Loss on revaluation of investment	—			—			(199		)	—			(199		)
Total other income (expense), net	(10,452		)	(50,821		)	(3,270		)	(615		)	(65,158		)
Income (loss) before income taxes	(17,314		)	174,473			51,576			(7,042		)	201,693
Provision for income taxes	41,512			—			764			—			42,276
Net income (loss)	(58,826		)	174,473			50,812			(7,042		)	159,417
Net income attributable to non-controlling interest	—			—			48,466			(46,103		)	2,363
Net income (loss) attributable to Diamondback Energy, Inc.	$	(58,826	)	$	174,473		$	2,346		$	39,061		$	157,054

Condensed Consolidated Statement of Operations
Three Months Ended September 30, 2017
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues:
Oil sales	$	—		$	223,038		$	—		$	36,011		$	259,049
Natural gas sales	—			11,774			—			3,148			14,922
Natural gas liquid sales	—			22,214			—			3,052			25,266
Royalty income	—			—			42,211			(42,211		)	—
Lease bonus	—			—			322			—			322
Midstream services	—			1,694			—			—			1,694
Total revenues	—			258,720			42,533			—			301,253
Costs and expenses:
Lease operating expenses	—			32,498			—			—			32,498
Production and ad valorem taxes	—			15,546			2,825			—			18,371
Gathering and transportation	—			3,271			205			—			3,476
Midstream services	—			4,445			—			—			4,445
Depreciation, depletion and amortization	—			74,766			11,068			1,745			87,579
General and administrative expenses	6,506			4,629			1,368			(615		)	11,888
Asset retirement obligation accretion	—			357			—			—			357
Total costs and expenses	6,506			135,512			15,466			1,130			158,614
Income (loss) from operations	(6,506		)	123,208			27,067			(1,130		)	142,639
Other income (expense)
Interest expense, net	(6,393		)	(1,940		)	(859		)	—			(9,192		)
Other income (expense), net	9			210			399			(615		)	3
Loss on derivative instruments, net	—			(50,645		)	—			—			(50,645		)
Total other income (expense), net	(6,384		)	(52,375		)	(460		)	(615		)	(59,834		)
Income (loss) before income taxes	(12,890		)	70,833			26,607			(1,745		)	82,805
Provision for income taxes	857			—			—			—			857
Net income (loss)	(13,747		)	70,833			26,607			(1,745		)	81,948
Net income attributable to non-controlling interest	—			—			—			8,924			8,924
Net income (loss) attributable to Diamondback Energy, Inc.	$	(13,747	)	$	70,833		$	26,607		$	(10,669	)	$	73,024

Condensed Consolidated Statement of Operations
Nine Months Ended September 30, 2018
(In thousands)
					Non–
			Guarantor		Guarantor
	Parent		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Revenues:
Oil sales	—		1,149,184		—		185,165		1,334,349
Natural gas sales	—		31,405		—		9,152		40,557
Natural gas liquid sales	—		116,976		—		16,882		133,858
Royalty income	—		—		211,199		(211,199	)	—
Lease bonus	—		—		5,133		(2,883	)	2,250
Midstream services	—		26,658		—		—		26,658
Other operating income	—		6,705		120		—		6,825
Total revenues	—		1,330,928		216,452		(2,883	)	1,544,497
Costs and expenses:
Lease operating expenses	—		129,103		—		—		129,103
Production and ad valorem taxes	—		78,909		14,133		—		93,042
Gathering and transportation	—		16,777		1,297		—		18,074
Midstream services	—		48,515		—		—		48,515
Depreciation, depletion and amortization	—		337,823		41,317		12,261		391,401
General and administrative expenses	20,891		19,763		6,230		(1,845	)	45,039
Asset retirement obligation accretion	—		1,107		—		—		1,107
Other operating expense	—		2,416		—		—		2,416
Total costs and expenses	20,891		634,413		62,977		10,416		728,697
Income (loss) from operations	(20,891	)	696,515		153,475		(13,299	)	815,800
Other income (expense)
Interest expense, net	(29,945	)	(10,339	)	(9,061	)	—		(49,345	)
Other income (expense), net	750		88,786		1,479		(1,845	)	89,170
Loss on derivative instruments, net	—		(139,305	)	—		—		(139,305	)
Gain on revaluation of investment	—		—		5,165		—		5,165
Total other income (expense), net	(29,195	)	(60,858	)	(2,417	)	(1,845	)	(94,315	)
Income (loss) before income taxes	(50,086	)	635,657		151,058		(15,144	)	721,485
Provision for (benefit from) income taxes	153,864		—		(71,114	)	—		82,750
Net income (loss)	(203,950	)	635,657		222,172		(15,144	)	638,735
Net income attributable to non-controlling interest	—		—		77,526		22,197		99,723
Net income (loss) attributable to Diamondback Energy, Inc.	(203,950	)	635,657		144,646		(37,341	)	539,012

Condensed Consolidated Statement of Operations
Nine Months Ended September 30, 2017
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Revenues:
Oil sales	$	—		$	607,381		$	—		$	96,626		$	704,007
Natural gas sales	—			31,088			—			6,449			37,537
Natural gas liquid sales	—			50,506			—			7,119			57,625
Royalty income	—			—			110,194			(110,194		)	—
Lease bonus	—			—			2,613			(106		)	2,507
Midstream services	—			4,241			—			—			4,241
Total revenues	—			693,216			112,807			(106		)	805,917
Costs and expenses:
Lease operating expenses	—			88,113			—			—			88,113
Production and ad valorem taxes	—			42,307			7,668			—			49,975
Gathering and transportation	—			8,618			492			—			9,110
Midstream services	—			7,127			—			—			7,127
Depreciation, depletion and amortization	—			190,748			28,587			2,346			221,681
General and administrative expenses	20,046			14,259			5,064			(1,845		)	37,524
Asset retirement obligation accretion	—			1,030			—			—			1,030
Total costs and expenses	20,046			352,202			41,811			501			414,560
Income (loss) from operations	(20,046		)	341,014			70,996			(607		)	391,357
Other income (expense)
Interest expense, net	(23,526		)	(4,022		)	(2,114		)	—			(29,662		)
Other income (expense), net	1,101			9,690			526			(1,845		)	9,472
Gain on derivative instruments, net	—			20,376			—			—			20,376
Total other income (expense), net	(22,425		)	26,044			(1,588		)	(1,845		)	186
Income (loss) before income taxes	(42,471		)	367,058			69,408			(2,452		)	391,543
Provision for income taxes	4,393			—			—			—			4,393
Net income (loss)	(46,864		)	367,058			69,408			(2,452		)	387,150
Net income attributable to non-controlling interest	—			—			—			19,448			19,448
Net income (loss) attributable to Diamondback Energy, Inc.	$	(46,864	)	$	367,058		$	69,408		$	(21,900	)	$	367,702

Condensed Consolidated Statement of Cash Flows

Condensed Consolidated Statement of Cash Flows
Nine Months Ended September 30, 2018
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Net cash provided by operating activities	$	220		$	975,082		$	176,414		$	—		$	1,151,716
Cash flows from investing activities:
Additions to oil and natural gas properties	—			(1,010,325		)	—			—			(1,010,325		)
Additions to midstream assets	—			(129,820		)	—			—			(129,820		)
Purchase of other property, equipment and land	—			2,638			(4,687		)	—			(2,049		)
Acquisition of leasehold interests	—			(185,658		)	—			—			(185,658		)
Acquisition of mineral interests	—			170,268			(505,842		)	—			(335,574		)
Proceeds from sale of assets	—			6,206			565			—			6,771
Funds held in escrow	—			(51,045		)	—			—			(51,045		)
Equity investments	—			(604		)	—			—			(604		)
Intercompany transfers	(22,310		)	22,310			—			—			—
Investment in real estate	—			(110,654		)	—			—			(110,654		)
Net cash used in investing activities	(22,310		)	(1,286,684		)	(509,964		)	—			(1,818,958		)
Cash flows from financing activities:
Proceeds from borrowing under credit facility	—			470,500			557,000			—			1,027,500
Repayment under credit facility	—			(867,500		)	(354,000		)	—			(1,221,500		)
Proceeds from senior notes	1,062,000			—			—			—			1,062,000
Debt issuance costs	(13,723		)	(232		)	(623		)	—			(14,578		)
Public offering costs	—			—			(2,636		)	—			(2,636		)
Proceeds from public offerings	—			—			305,773			—			305,773
Contributions to subsidiaries	(1,000		)	—			(1,000		)	2,000			—
Contributions by members	—			—			2,000			(2,000		)	—
Distributions from subsidiary	112,671			—			—			(112,671		)	—
Unit options exercised	—			—			140			—			140
Dividends to stockholders	(24,656		)	—			—			—			(24,656		)
Distributions to non-controlling interest	—			—			(181,472		)	112,671			(68,801		)
Intercompany transfers	(696,128		)	695,128			1,000			—			—
Net cash provided by financing activities	439,164			297,896			326,182			—			1,063,242
Net increase (decrease) in cash and cash equivalents	417,074			(13,706		)	(7,368		)	—			396,000
Cash and cash equivalents at beginning of period	54,074			34,175			24,197			—			112,446
Cash and cash equivalents at end of period	$	471,148		$	20,469		$	16,829		$	—		$	508,446

Condensed Consolidated Statement of Cash Flows
Nine Months Ended September 30, 2017
(In thousands)
							Non–
				Guarantor			Guarantor
	Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(25,369	)	$	569,330		$	94,057		$	—		$	638,018
Cash flows from investing activities:
Additions to oil and natural gas properties	—			(531,489		)	—			—			(531,489		)
Additions to midstream assets	—			(22,491		)	—			—			(22,491		)
Purchase of other property, equipment and land	—			(21,534		)	—			—			(21,534		)
Acquisition of leasehold interests	—			(1,892,864		)	—			—			(1,892,864		)
Acquisition of mineral interests	—			(69,722		)	(301,133		)	—			(370,855		)
Acquisition of midstream assets	—			(50,279		)	—			—			(50,279		)
Proceeds from sale of assets	—			3,584			—			—			3,584
Funds held in escrow	—			121,391			—			—			121,391
Equity investments	—			(188		)	—			—			(188		)
Intercompany transfers	(1,651,328		)	1,651,328			—			—			—
Net cash used in investing activities	(1,651,328		)	(812,264		)	(301,133		)	—			(2,764,725		)
Cash flows from financing activities:
Proceeds from borrowing under credit facility	—			312,500			220,500			—			533,000
Repayment under credit facility	—			(78,000		)	(305,500		)	—			(383,500		)
Purchase of subsidiary units by parent	(10,068		)	—			—			10,068			—
Debt issuance costs	(744		)	(790		)	(180		)	—			(1,714		)
Public offering costs	(77		)	—			(433		)	—			(510		)
Proceeds from public offerings	—			—			380,412			(10,068		)	370,344
Distributions from subsidiary	64,858			—			—			(64,858		)	—
Proceeds from exercise of stock options	358			—			—			—			358
Distributions to non-controlling interest	—			—			(92,498		)	64,858			(27,640		)
Net cash provided by financing activities	54,327			233,710			202,301			—			490,338
Net decrease in cash and cash equivalents	(1,622,370		)	(9,224		)	(4,775		)	—			(1,636,369		)
Cash and cash equivalents at beginning of period	1,643,226			14,135			9,213			—			1,666,574
Cash and cash equivalents at end of period	$	20,856		$	4,911		$	4,438		$	—		$	30,205

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Description of the Business and Basis of Presentation (Details)	Sep. 30, 2018
Viper Energy Partners LP [Member]
Noncontrolling Interest [Line Items]
Interest in Viper Energy Partners LP (percentage)	59.00%

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Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Investment [Line Items]
Cumulative effect due to the impact of adoption of ASU 2016.01	$ (16,064)		$ (16,064)
Gain (loss) on revaluation of investment	(199)	$ 0	5,165	$ 0
Funds Held in Escrow [Abstract]
Funds held in escrow	62,034		62,034		$ 6,304
Other Noncurrent Assets [Member]
Investment [Line Items]
Cost Method Investments	20,240		20,240
Viper Energy Partners LP [Member]
Investment [Line Items]
Cumulative effect due to the impact of adoption of ASU 2016.01	$ (18,651)		$ (18,651)

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Acquisitions (Details) $ / shares in Units, shares in Thousands, $ in Thousands					3 Months Ended		7 Months Ended	9 Months Ended
	Oct. 31, 2018 USD ($) a shares	Aug. 15, 2018 USD ($) a	Aug. 14, 2018 USD ($)	Feb. 28, 2017 USD ($) a shares	Mar. 31, 2018 USD ($)	Sep. 30, 2017 USD ($) $ / shares	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($) $ / shares	Jun. 30, 2018 USD ($) a	Dec. 31, 2017 USD ($)
Business Acquisition [Line Items]
Investment in real estate					$ 109,700			$ 110,654	$ 0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt										$ 831,000
Tier One Acres to be Acquired | a										273,000
Current Tier One Acreage | a										174,000
Combined Net Acreage After Close of Pending Acquisition | a										394,000
Current Net Acreage | a										216,000
Acquisition of leasehold interests								185,658	1,892,864
Acquisition of midstream assets								$ 129,820	22,491
Business Acquisition, Pro Forma Revenue						$ 301,253			828,846
Business Acquisition, Pro Forma Income from Operations						142,639			405,699
Business Acquisition, Pro Forma Net Income						$ 81,948			$ 382,044
Business Acquisition, Pro Forma Earnings Per Share, Basic | $ / shares						$ 0.74			$ 3.96
Business Acquisition, Pro Forma Earnings Per Share, Diluted | $ / shares						$ 0.74			$ 3.95
Delaware Basin Interests [Member]
Business Acquisition [Line Items]
Payments to acquire leasehold interests and related assets				$ 1,740,000
Number of shares issued to acquire leasehold interests and related assets | shares				7,690
Shares Held in Escrow | shares				1,150
Gross acres acquired | a				100,306
Net acres acquired | a				80,339
Acquisition of leasehold interests				$ 2,500,000
Acquisition of midstream assets				$ 47,600
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Proved Oil and Gas Properties											$ 386,308
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Unevaluated Oil and Natural Gas Properties											2,122,597
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Midstream Assets											47,432
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Prepaid Costs											3,460
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Oil Inventory											839
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Equipment											163
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Revenues Payable											(9,650)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Asset Retirement Obligation											(1,550)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net											$ 2,549,599
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual							$ 84,300
Business Combination, Pro Forma Information, Direct Operating Expenses since Acquisition Date, Actual							$ 16,000
Energen Corporation Acquisition [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred, Equity Interests Issued and Issuable			$ 9,200,000
Company Credit Facility [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt										$ 301,000
Senior Subordinated Notes [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt										$ 400,000
Debt Instrument, Interest Rate, Stated Percentage										4.625%
Medium-term Notes, Series A [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt										$ 20,000
Debt Instrument, Interest Rate, Stated Percentage										7.32%
Medium-term Notes, Series A, Due July 28, 2027 [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt										$ 10,000
Debt Instrument, Interest Rate, Stated Percentage										7.35%
Medium-term Notes, Series B [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt										$ 100,000
Debt Instrument, Interest Rate, Stated Percentage										7.125%
Subsequent Event [Member] | Ajax Acquisition [Member]
Business Acquisition [Line Items]
Net acres acquired | a	25,493
Payments to acquire leasehold interests and related assets	$ 900,000
Number of shares issued to acquire leasehold interests and related assets | shares	2,600
Viper Energy Partners LP [Member] | Series of Individually Immaterial Business Acquisitions [Member]
Business Acquisition [Line Items]
Mineral Properties Acquired, Gross Acres | a		32,424
Mineral Properties Acquired, Net Royalty Acres | a		1,696
Percentage of mineral acres operated by affiliate		80.00%
Business Combination, Consideration Transferred		$ 175,000

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Viper Energy Partners LP (Details) - USD ($)	2 Months Ended		3 Months Ended			6 Months Ended	9 Months Ended
	Sep. 30, 2018	Jun. 30, 2018	Sep. 30, 2018	Jun. 30, 2018	Sep. 30, 2017	Jun. 30, 2018	Sep. 30, 2018	Sep. 30, 2017	May 10, 2018
Noncontrolling Interest [Line Items]
General Partners' Contributed Capital									$ 1,000,000
Limited Partners' Contributed Capital									$ 1,000,000
Limited partners capital account, percentage of distribution									8.00%
Number of Class B Units Converted		731,500
Partners' Capital Account, Units, Converted		731,500
Limited Partners' Capital Account, Distribution Amount		$ 10,000
Viper Energy Partners LP [Member]
Noncontrolling Interest [Line Items]
Interest in Viper Energy Partners LP (percentage)	59.00%		59.00%				59.00%
Parent Company [Member]
Noncontrolling Interest [Line Items]
Units of Partnership Interest, Amount									73,150,000
Other Partners' Capital									73,150,000
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest		64.00%					59.00%
Partnership Agreement [Member] | General Partner [Member]
Noncontrolling Interest [Line Items]
Revenue from Related Parties				$ 615,000	$ 615,000	$ 1,845,000		$ 1,845,000
Tax Sharing Agreement [Member] | Viper Energy Partners LP [Member]
Noncontrolling Interest [Line Items]
Current State and Local Tax Expense (Benefit)			$ (101,000)				$ 69,000
General Partner [Member]
Noncontrolling Interest [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest	41.00%	36.00%

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Property and Equipment (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Oil and natural gas properties:
Not subject to depletion	$ 4,283,629		$ 4,283,629		$ 4,105,865
Gross oil and natural gas properties	10,818,378		10,818,378		9,232,694
Accumulated depletion and depreciation	(2,545,412)		(2,545,412)		(2,161,372)
Midstream assets	355,758		355,758		191,519
Other property, equipment and land	85,882		85,882		80,776
Net property and equipment	8,714,606		8,714,606		7,343,617
Capitalized internal costs	6,717	$ 5,710	20,370	$ 15,925
Exploration costs or development costs not subject to depletion	50,052		50,052		26,040
Capitalized interest not subject to depletion	41,953		$ 41,953		22,097
Minimum [Member]
Oil and natural gas properties:
Timing of inclusion of costs in amortization calculation			3 years
Maximum [Member]
Oil and natural gas properties:
Timing of inclusion of costs in amortization calculation			5 years
Oil and Gas Properties [Member]
Oil and natural gas properties:
Subject to depletion	6,534,749		$ 6,534,749		5,126,829
Not subject to depletion	4,283,629		4,283,629		4,105,865
Gross oil and natural gas properties	10,818,378		10,818,378		9,232,694
Accumulated depletion and depreciation	(1,375,163)		(1,375,163)		(1,009,893)
Accumulated impairment	(1,143,498)		(1,143,498)		(1,143,498)
Oil and natural gas properties, net	8,299,717		8,299,717		7,079,303
Balance of costs not subject to depletion:			589,352		2,563,902	$ 714,467	$ 234,948	$ 180,960
Other Property and Equipment, Net [Member]
Oil and natural gas properties:
Accumulated depletion and depreciation	(26,751)		(26,751)		(7,981)
Other property, equipment and land	$ 85,882		$ 85,882		$ 80,776

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Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Changes in ARO liability
Asset retirement obligations, beginning of period			$ 21,285	$ 17,422
Additional liabilities incurred			2,229	1,196
Liabilities acquired			270	2,411
Liabilities settled			(1,474)	(689)
Accretion expense	$ 387	$ 357	1,107	1,030
Revisions in estimated liabilities			568	4
Asset retirement obligations, end of period	23,985	21,374	23,985	21,374
Less current portion	88	1,392	88	1,392
Asset retirement obligations - long-term	$ 23,897	$ 19,982	$ 23,897	$ 19,982	$ 20,122

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Equity Method Investments (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Oct. 31, 2014
Schedule of Equity Method Investments [Line Items]
Amount invested in equity method investments	$ 604	$ 188
Income from equity method investments	$ 0	309
HMW Fluid Management LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage			25.00%
Amount invested in equity method investments		188
Income from equity method investments		309
Equity Method Investments		$ 6,847

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Debt - Long-term Debt (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017	Dec. 20, 2016	Oct. 28, 2016
Debt Instrument [Line Items]
Long-term Debt	$ 2,332,359	$ 1,477,347
Unamortized debt issuance costs	(25,038)	(13,153)
Unamortized premium cost	10,897	0
Senior Unsecured Notes due 2024 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,250,000	$ 500,000
Debt Instrument, Interest Rate, Stated Percentage	4.75%	4.75%		4.75%
Senior Unsecured Notes due 2025 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 800,000	$ 500,000
Debt Instrument, Interest Rate, Stated Percentage	5.375%	5.375%	5.375%
Company Credit Facility [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 0	$ 397,000
Partnership Credit Facility [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 296,500	$ 93,500

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Debt - Senior Notes (Details) - USD ($) $ in Thousands			9 Months Ended
	Sep. 18, 2018	Jan. 29, 2018	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017	Dec. 20, 2016	Oct. 28, 2016
Debt Instrument [Line Items]
Proceeds from Issuance of Senior Long-term Debt			$ 1,062,000	$ 0
Senior Unsecured Notes due 2024 [Member]
Debt Instrument [Line Items]
Aggregate principal amount							$ 500,000
Debt Instrument, Interest Rate, Stated Percentage			4.75%		4.75%		4.75%
Debt Instrument, Redemption Price, Percentage			100.00%
Senior Unsecured Notes due 2024 [Member] | Debt Instrument, Redemption, Period One [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage			103.563%
Debt Instrument, Redemption Period, Start Date			Nov. 01, 2019
Debt Instrument, Redemption Period, End Date			Oct. 31, 2020
Senior Unsecured Notes due 2024 [Member] | Debt Instrument, Redemption, Period Two [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage			102.375%
Debt Instrument, Redemption Period, Start Date			Nov. 01, 2020
Debt Instrument, Redemption Period, End Date			Oct. 31, 2021
Senior Unsecured Notes due 2024 [Member] | Debt Instrument, Redemption, Period Three [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage			101.188%
Debt Instrument, Redemption Period, Start Date			Nov. 01, 2021
Debt Instrument, Redemption Period, End Date			Oct. 31, 2022
Senior Unsecured Notes due 2024 [Member] | Debt Instrument, Redemption, Period Four [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage			100.00%
Debt Instrument, Redemption Period, Start Date			Nov. 01, 2022
Senior Unsecured Notes due 2024 [Member] | Debt Instrument, Redemption, Period Five [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage			104.75%
Debt Instrument, Redemption Period, Start Date			Oct. 28, 2016
Debt Instrument, Redemption Period, End Date			Oct. 31, 2019
Senior Unsecured Additional Notes due 2024 [Member]
Debt Instrument [Line Items]
Aggregate principal amount	$ 750,000
Debt Instrument, Interest Rate, Stated Percentage	4.75%
Proceeds from Issuance of Senior Long-term Debt	$ 740,700
Senior Unsecured Notes due 2025 [Member]
Debt Instrument [Line Items]
Aggregate principal amount						$ 500,000
Debt Instrument, Interest Rate, Stated Percentage			5.375%		5.375%	5.375%
Debt Instrument, Redemption Price, Percentage			100.00%
Senior Unsecured Notes due 2025 [Member] | Debt Instrument, Redemption, Period One [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage			104.031%
Debt Instrument, Redemption Period, Start Date			May 31, 2020
Debt Instrument, Redemption Period, End Date			May 30, 2021
Senior Unsecured Notes due 2025 [Member] | Debt Instrument, Redemption, Period Two [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage			102.688%
Debt Instrument, Redemption Period, Start Date			May 31, 2021
Debt Instrument, Redemption Period, End Date			May 30, 2022
Senior Unsecured Notes due 2025 [Member] | Debt Instrument, Redemption, Period Three [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage			101.344%
Debt Instrument, Redemption Period, Start Date			May 31, 2022
Debt Instrument, Redemption Period, End Date			May 30, 2023
Senior Unsecured Notes due 2025 [Member] | Debt Instrument, Redemption, Period Four [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage			100.00%
Debt Instrument, Redemption Period, Start Date			May 31, 2023
Senior Unsecured Notes due 2025 [Member] | Debt Instrument, Redemption, Period Five [Member]
Debt Instrument [Line Items]
Debt Instrument, Redemption Price, Percentage			105.375%
Debt Instrument, Redemption Period, Start Date			Dec. 20, 2016
Debt Instrument, Redemption Period, End Date			May 30, 2020
Senior Unsecured Additional Notes due 2025 [Member]
Debt Instrument [Line Items]
Aggregate principal amount		$ 300,000
Debt Instrument, Interest Rate, Stated Percentage		5.375%
Proceeds from Issuance of Senior Long-term Debt		$ 308,400
Maximum [Member] | Senior Unsecured Notes due 2024 [Member] | Debt Instrument, Redemption, Period Five [Member]
Debt Instrument [Line Items]
Debt Instrument Percentage Eligible for Redemption			35.00%
Maximum [Member] | Senior Unsecured Notes due 2025 [Member] | Debt Instrument, Redemption, Period Five [Member]
Debt Instrument [Line Items]
Debt Instrument Percentage Eligible for Redemption			35.00%

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Debt - Credit Facility - Wells Fargo Bank (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2018 USD ($) redetermindation	Nov. 06, 2018 USD ($)	Oct. 26, 2018 USD ($)	Dec. 31, 2017 USD ($)
Company Credit Facility [Member]
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 5,000,000
Number of interim redeterminations that may be requested | redetermindation	2
Period of redeterminations (in months)	12 months
Current borrowing base	$ 2,000,000
Line of Credit Facility, Elected Borrowing Base	1,000,000
Long-term Debt, Gross	0			$ 397,000
Remaining Borrowing Capacity	$ 1,000,000
Financial covenant, reduction of borrowing base (percentage)	25.00%
Company Credit Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base	0.375%
Company Credit Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base	0.50%
Company Credit Facility [Member] | Federal Funds Rate [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate (percentage)	0.50%
Company Credit Facility [Member] | LIBOR [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate (percentage)	1.00%
Company Credit Facility [Member] | LIBOR [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate (percentage)	1.25%
Company Credit Facility [Member] | LIBOR [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate (percentage)	2.25%
Company Credit Facility [Member] | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate (percentage)	0.25%
Company Credit Facility [Member] | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate (percentage)	1.25%
Subsequent Event [Member]
Line of Credit Facility [Line Items]
Current borrowing base			$ 555,000
Subsequent Event [Member] | Company Credit Facility [Member]
Line of Credit Facility [Line Items]
Current borrowing base		$ 2,650,000	2,500,000
Line of Credit Facility, Elected Borrowing Base			$ 2,000,000

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Debt - Partnership Credit Facility - Wells Fargo Bank (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2018 USD ($) redetermindation	Oct. 26, 2018 USD ($)	Dec. 31, 2017 USD ($)
Partnership Credit Facility [Member]
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 2,000,000
Number of interim redeterminations that may be requested | redetermindation	3
Period of redeterminations (in months)	12 months
Current borrowing base	$ 475,000
Long-term Debt, Gross	296,500		$ 93,500
Remaining Borrowing Capacity	178,500
Financial covenant, maximum issuance of unsecured debt	$ 400,000
Financial covenant, reduction of borrowing base (percentage)	25.00%
Partnership Credit Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base	0.375%
Partnership Credit Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Quarterly commitment fee percentage based on unused portion of borrowing base	0.50%
Partnership Credit Facility [Member] | Federal Funds Rate [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate (percentage)	0.50%
Partnership Credit Facility [Member] | LIBOR [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate (percentage)	1.00%
Partnership Credit Facility [Member] | LIBOR [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate (percentage)	1.75%
Partnership Credit Facility [Member] | LIBOR [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate (percentage)	2.75%
Partnership Credit Facility [Member] | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate (percentage)	0.75%
Partnership Credit Facility [Member] | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Basis spread on variable rate (percentage)	1.75%
Subsequent Event [Member]
Line of Credit Facility [Line Items]
Current borrowing base		$ 555,000

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Debt - Financial Covenant Table (Details)	Sep. 30, 2018
Company Credit Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Ratio of total net debt to EBITDAX	4.0
Company Credit Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Ratio of current assets to liabilities, as defined in the credit agreement	1.0
Partnership Credit Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Ratio of total net debt to EBITDAX	4.0
Partnership Credit Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Ratio of current assets to liabilities, as defined in the credit agreement	1.0

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Debt Alliance with Obsidian Resources, L.L.C. (Details) - USD ($) $ in Millions	Oct. 26, 2018	Sep. 30, 2018
Alliance with Obsidian Resources, L.L.C. [Line Items]
Maximum Funding Amount Through Joint Venture		$ 300.0
Company Credit Facility [Member]
Alliance with Obsidian Resources, L.L.C. [Line Items]
Line of Credit Facility, Elected Borrowing Base		$ 1,000.0
Company Credit Facility [Member] | Subsequent Event [Member]
Alliance with Obsidian Resources, L.L.C. [Line Items]
Line of Credit Facility, Elected Borrowing Base	$ 2,000.0

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Capital Stock and Earnings Per Share - Capital Stock (Details) - USD ($) $ in Thousands	1 Months Ended			2 Months Ended	9 Months Ended
	Jul. 31, 2018	Jul. 31, 2017	Jan. 31, 2017	Jun. 30, 2018	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Class of Stock [Line Items]
Repayments of Lines of Credit					$ 1,221,500	$ 383,500
Partnership Credit Facility [Member]
Class of Stock [Line Items]
Long-term Debt, Gross					$ 296,500		$ 93,500
Viper Energy Partners LP [Member]
Class of Stock [Line Items]
Interest in Viper Energy Partners LP (percentage)					59.00%
Parent Company [Member]
Class of Stock [Line Items]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest				64.00%	59.00%
Follow-on Public Offering [Member] | Viper Energy Partners LP [Member]
Class of Stock [Line Items]
Sale of Stock, Number of Shares Issued in Transaction	10,080,000	16,100,000	9,775,000
Sale of Stock, Consideration Received on Transaction	$ 303,100	$ 232,500	$ 147,500
Repayments of Lines of Credit		$ 152,800	$ 120,500
Long-term Debt, Gross	$ 361,500
Over-Allotment Option [Member] | Viper Energy Partners LP [Member]
Class of Stock [Line Items]
Sale of Stock, Number of Shares Issued in Transaction	1,080,000	2,100,000	1,275,000
Over-Allotment Option [Member] | Viper Energy Partners LP [Member] | Diamondback Energy, Inc. [Member]
Class of Stock [Line Items]
Sale of Stock, Number of Shares Issued in Transaction		700,000
Over-Allotment Option [Member] | Viper Energy Partners LP [Member] | Affiliated Entity [Member]
Class of Stock [Line Items]
Sale of Stock, Number of Shares Issued in Transaction		3,000,000
Over-Allotment Option [Member] | Viper Energy Partners LP [Member] | Executive Officer [Member]
Class of Stock [Line Items]
Sale of Stock, Number of Shares Issued in Transaction		114,000

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Capital Stock and Earnings Per Share - Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Basic:
Net income attributable to common stock	$ 157,054	$ 73,024	$ 539,012	$ 367,702
Basic weighted average common units outstanding	98,638,000	98,144,000	98,603,000	96,491,000
Basic net income attributable to common stock	$ 1.59	$ 0.74	$ 5.47	$ 3.81
Effect of Dilutive Securities:
Dilutive effect of potential common shares issuable (in shares)	180,000	225,000	217,000	261,000
Diluted:
Diluted weighted average common shares outstanding	98,818,000	98,369,000	98,820,000	96,752,000
Diluted net income attributable to common stock	$ 1.59	$ 0.74	$ 5.45	$ 3.80
Antidilutive securities excluded from earnings per share (in shares)	12,699	52,857	2,300	1,248

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Equity-Based Compensation - Schedule of Stock-Based Compensation Plans and Related Costs (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	$ 2,338	$ 2,167	$ 7,328	$ 6,411
General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items]
General and administrative expenses	$ 5,350	$ 6,187	$ 18,451	$ 19,418

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Equity-Based Compensation - Restricted Stock Units (Details) - Equity Plan [Member] - Restricted Stock Units (RSUs) [Member] - USD ($) $ / shares in Units, $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Awards & Units (in shares)
Unvested at December 31, 2017	243,577
Granted	90,115
Vested	(170,014)
Forfeited	(7,597)
Unvested at September 30, 2018	156,081
Weighted Average Grant-Date Fair Value (in dollars per share)
Unvested at December 31, 2017	$ 90.88
Granted	115.03
Vested	89.08
Forfeited	95.80
Unvested at September 30, 2018	$ 106.54
Aggregate fair value of share-based awards that vested	$ 15.1	$ 14.8
Unrecognized compensation cost related to unvested awards	$ 13.0
Unrecognized compensation cost, period of recognition (in years)	1 year 4 months 24 days

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Equity-Based Compensation - Performance Restricted Stock Activity (Details) - Equity Plan [Member] - Performance Shares [Member] - USD ($) $ / shares in Units, $ in Millions		1 Months Ended	9 Months Ended
		Feb. 28, 2018	Sep. 30, 2018
Awards & Units (in shares)
Unvested at December 31, 2017			202,326
Granted			285,737
Vested			(168,314)
Unvested at September 30, 2018	[1]		319,749
Weighted Average Grant-Date Fair Value (in dollars per share)
Unvested at December 31, 2017			$ 139.83
Granted			130.96
Vested			103.41
Unvested at September 30, 2018			$ 151.08
Share Based Compensation Arrangement by Share Based Payment Maximum Award Potential			639,498
Unrecognized compensation cost related to unvested awards			$ 23.0
Unrecognized compensation cost, period of recognition (in years)			1 year 2 months 12 days
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized to be awarded, percent of initial awards received		0.00%
Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized to be awarded, percent of initial awards received		200.00%
Two-Year [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance shares, performance period		2 years
Three-Year [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance shares, performance period		3 years
Awards & Units (in shares)
Granted		117,423
Weighted Average Grant-Date Fair Value (in dollars per share)
Granted		$ 170.45

[1] A maximum of 639,498 units could be awarded based upon the Company’s final TSR ranking.

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Equity-Based Compensation - Valuation Assumptions (Details) - Equity Plan [Member] - Performance Shares [Member] - $ / shares	1 Months Ended	9 Months Ended
	Feb. 28, 2018	Sep. 30, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted		$ 130.96
Three-Year [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted	$ 170.45
Risk-free rate (percentage)	1.99%
Company volatility (percentage)	35.90%

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Equity-Based Compensation - Partnership Unit Options (Details) - Employee Stock Option [Member] $ / shares in Units, $ in Thousands	9 Months Ended
	Sep. 30, 2018 USD ($) $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Intrinsic value of options outstanding | $	$ 0
Viper Energy Partners LP Long Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Outstanding at December 31, 2017 | shares	7,600
Exercised | shares	(7,600)
Outstanding at September 30, 2018 | shares	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price [Abstract]
Outstanding at December 31, 2017 | $ / shares	$ 18.49
Exercised | $ / shares	18.49
Outstanding at September 30, 2018 | $ / shares	$ 0.00
Weighted average remaining contractual term	0 years
Aggregate intrinsic value of options exercised in period | $	$ 200

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Equity-Based Compensation - Phantom Units (Details) - Viper Energy Partners LP Long Term Incentive Plan [Member] - Phantom Share Units (PSUs) [Member] $ / shares in Units, $ in Millions	9 Months Ended
	Sep. 30, 2018 USD ($) $ / shares shares
Awards & Units (in shares)
Unvested at December 31, 2017 | shares	105,439
Granted | shares	119,818
Vested | shares	(102,811)
Unvested at September 30, 2018 | shares	122,446
Weighted Average Grant-Date Fair Value (in dollars per share)
Unvested at December 31, 2017 | $ / shares	$ 17.10
Granted | $ / shares	24.46
Vested | $ / shares	19.23
Unvested at September 30, 2018 | $ / shares	$ 22.52
Aggregate fair value of share-based awards that vested | $	$ 2.0
Unrecognized compensation cost related to unvested awards | $	$ 2.0
Unrecognized compensation cost, period of recognition (in years)	1 year 3 months 18 days

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Related Party Transactions - Related Party Transactions (Details)		3 Months Ended		9 Months Ended
	Jun. 23, 2014 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)
Parent Company [Member]
Related Party Transaction [Line Items]
Payments for Operating Activities			$ 0		$ 106,000
Revenue from Related Parties		$ 2,884,000		$ 2,884,000
Number of leases extended		12	0	12	2
Average price per acre		$ 6,412	$ 0	$ 6,412	$ 7,459
Viper Energy Partners LP [Member] | Wexford [Member] | Advisory Services Agreement [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Annual Fee for Advisory Services with Related Party	$ 500,000
Related Party Transaction, Original Term for Advisory Services with Related Party	2 years
Related Party Transaction, Renewal Term for Advisory Services with Related Party	1 year
Related Party Transaction, Minimum Period for Cancellation of Renewal Term	10 days
Payments for Operating Activities		$ 0	$ 0	$ 0	$ 0

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Income Taxes (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Investments, Owned, Federal Income Tax Note [Line Items]
Effective income tax rate	11.50%	1.20%
Discrete income tax benefit recorded during the period	$ 0.8
Discrete income tax benefit related to deferred taxes recorded during the period	$ 72.7

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Derivatives - Open Derivative Positions (Details)	9 Months Ended
	Sep. 30, 2018 MMBTU $ / bbl $ / MMBTU bbl
WTI Cushing Oil Swaps 2018 [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	2,392,000
Fixed Swap Price (in dollars per bbl)	51.27
WTI Cushing Oil Swaps 2019 [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	1,638,000
Fixed Swap Price (in dollars per bbl)	52.78
WTI Magellan East Houston Oil Swaps 2018 [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	644,000
Fixed Swap Price (in dollars per bbl)	71.06
WTI Magellan East Houston Oil Swaps 2019 [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	1,087,000
Fixed Swap Price (in dollars per bbl)	40.37
BRENT Oil Swaps 2018 [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	920,000
Fixed Swap Price (in dollars per bbl)	62.51
BRENT Oil Swaps 2019 [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	725,000
Fixed Swap Price (in dollars per bbl)	72.63
Oil Basis Swaps 2018 [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	1,380,000
Fixed Swap Price (in dollars per bbl)	(0.88)
Oil Basis Swaps 2019 [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	270,000
Fixed Swap Price (in dollars per bbl)	(9.42)
Natural Gas Swaps 2018 [Member]
Derivative [Line Items]
Volume (MMBtu) | MMBTU	1,840,000
Fixed Swap Price (in dollars per bbl) | $ / MMBTU	3.07
Natural Gas Swaps 2019 [Member]
Derivative [Line Items]
Volume (MMBtu) | MMBTU	0
Fixed Swap Price (in dollars per bbl) | $ / MMBTU	0.00
2018 Three-Way Collars - WTI Magellan East Houston [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	644,000
Short put price (per Bbl)	56.43
Floor price (per Bbl)	66.43
Ceiling price (per Bbl)	78.82
2019 Three-Way Collars - WTI Cushing [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	1,810,000
Short put price (per Bbl)	45.00
Floor price (per Bbl)	55.00
Ceiling price (per Bbl)	70.23
2019 Three-Way Collars - BRENT [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	2,000,000
Short put price (per Bbl)	55.00
Floor price (per Bbl)	65.00
Ceiling price (per Bbl)	82.47
2019 Three-Way Collars - WTI Magellan East Houston [Member]
Derivative [Line Items]
Volume (Bbls) | bbl	994,000
Short put price (per Bbl)	56.82
Floor price (per Bbl)	66.82
Ceiling price (per Bbl)	77.60

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Derivatives - Offsetting Derivative Instruments (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Gross amounts of assets presented in the Consolidated Balance Sheet	$ 0	$ 531
Net amounts of assets presented in the Consolidated Balance Sheet	0	531
Gross amounts of liabilities presented in the Consolidated Balance Sheet	129,757	106,670
Net amounts of liabilities presented in the Consolidated Balance Sheet	$ 129,757	$ 106,670

XML

Derivatives - Balance Sheet Location (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Current assets: derivative instruments	$ 0	$ 531
Noncurrent assets: derivative instruments	0	0
Total assets	0	531
Current liabilities: derivative instruments	123,826	100,367
Noncurrent liabilities: derivative instruments	5,931	6,303
Total liabilities	$ 129,757	$ 106,670

XML

Derivatives - Gains and Losses on Derivative Instruments Included in Statement of Operations (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Change in fair value of open non-hedge derivative instruments	$ (9,913)	$ (58,645)	$ (23,618)	$ 9,365
Gain (loss) on settlement of non-hedge derivative instruments	(38,460)	8,000	(115,687)	11,011
Gain (loss) on derivative instruments	$ (48,373)	$ (50,645)	$ (139,305)	$ 20,376

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Fair Value Measurements - Recurring Measurements (Details) - Recurring [Member] - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Fair Value, Inputs, Level 1 [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Equity Method Investments, Fair Value Disclosure	$ 20,240	$ 0
Assets:
Fixed price swaps	0	0
Fair Value, Inputs, Level 2 [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Equity Method Investments, Fair Value Disclosure	0	0
Assets:
Fixed price swaps	(129,757)	(106,139)
Significant Unobservable Inputs Level 3 [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Equity Method Investments, Fair Value Disclosure	0	0
Assets:
Fixed price swaps	$ 0	$ 0

XML

Fair Value Measurements - Nonrecurring Measurements (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017	Dec. 20, 2016	Oct. 28, 2016
Senior Unsecured Notes due 2024 [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt Instrument, Interest Rate, Stated Percentage	4.75%	4.75%		4.75%
Senior Unsecured Notes due 2025 [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Debt Instrument, Interest Rate, Stated Percentage	5.375%	5.375%	5.375%
Reported Value Measurement [Member] | Company Credit Facility [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	$ 0	$ 397,000
Reported Value Measurement [Member] | Senior Unsecured Notes due 2024 [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior Notes	1,250,000	500,000
Reported Value Measurement [Member] | Senior Unsecured Notes due 2025 [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior Notes	800,000	500,000
Reported Value Measurement [Member] | Partnership Credit Facility [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	296,500	93,500
Fair Value, Inputs, Level 1 [Member] | Estimate of Fair Value Measurement [Member] | Senior Unsecured Notes due 2024 [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior Notes	1,252,613	501,855
Fair Value, Inputs, Level 1 [Member] | Estimate of Fair Value Measurement [Member] | Senior Unsecured Notes due 2025 [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Senior Notes	819,000	515,000
Fair Value, Inputs, Level 2 [Member] | Estimate of Fair Value Measurement [Member] | Company Credit Facility [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	0	397,000
Fair Value, Inputs, Level 2 [Member] | Estimate of Fair Value Measurement [Member] | Partnership Credit Facility [Member] | Nonrecurring [Member]
Fair value of assets and liabilities measured on a recurring and nonrecurring basis
Revolving credit facility	$ 296,500	$ 93,500

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Subsequent Events (Details) $ / shares in Units, $ in Millions		1 Months Ended	3 Months Ended			9 Months Ended
	Oct. 31, 2018 USD ($) a	Nov. 06, 2018 USD ($) a $ / bbl bbl	Dec. 31, 2018 $ / shares	Sep. 30, 2018 USD ($) $ / shares $ / bbl	Sep. 30, 2017 $ / shares	Sep. 30, 2018 USD ($) $ / shares $ / bbl bbl	Sep. 30, 2017 $ / shares	Nov. 01, 2018 USD ($)	Oct. 26, 2018 USD ($)
Subsequent Event [Line Items]
Dividends declared per share | $ / shares				$ 0.125	$ 0.000	$ 0.375	$ 0.000
2018 Three-Way Collars - WTI Magellan East Houston [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl						644,000
Short put price (per Bbl)				56.43		56.43
Floor price (per Bbl)				66.43		66.43
Ceiling price (per Bbl)				78.82		78.82
2019 Three-Way Collars - WTI Magellan East Houston [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl						994,000
Short put price (per Bbl)				56.82		56.82
Floor price (per Bbl)				66.82		66.82
Ceiling price (per Bbl)				77.60		77.60
BRENT Oil Swaps 2018 [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl						920,000
Fixed Swap Price (in dollars per bbl)				62.51		62.51
Subsequent Event [Member]
Subsequent Event [Line Items]
Divestiture of oil and natural gas properties, amount | $								$ 62.1
Divestiture of oil and natural gas properties, gross acreage | a		2,485
Divestiture of oil and natural gas properties, net acreage | a		2,072
Dividends Payable, Date Declared			Nov. 05, 2018
Dividends declared per share | $ / shares			$ 0.125
Dividends Payable, Date to be Paid			Nov. 26, 2018
Dividends Payable, Date of Record			Nov. 19, 2018
Current borrowing base | $									$ 555.0
Subsequent Event [Member] | Oil Swaps 2018 [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl		458,000
Fixed Swap Price (in dollars per bbl)		76.18
Subsequent Event [Member] | BRENT Oil Swaps 2018 [Member]
Subsequent Event [Line Items]
Volume (Bbls) | bbl		275,000
Fixed Swap Price (in dollars per bbl)		77.58
Company Credit Facility [Member]
Subsequent Event [Line Items]
Line of Credit Facility, Elected Borrowing Base | $				$ 1,000.0		$ 1,000.0
Current borrowing base | $				$ 2,000.0		$ 2,000.0
Company Credit Facility [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Line of Credit Facility, Elected Borrowing Base | $									2,000.0
Current borrowing base | $		$ 2,650.0							$ 2,500.0
Ajax Acquisition [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Net acres acquired | a	25,493
Payments to acquire leasehold interests and related assets | $	$ 900.0
ExL Acquisition [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Net acres acquired | a	3,646
Payments to acquire leasehold interests and related assets | $	$ 312.5

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Guarantor Financial Statements - Balance Sheet (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 508,446	$ 112,446	$ 30,205	$ 1,666,574
Accounts receivable	264,317	231,613
Accounts receivable - related party	0	0
Intercompany receivable	0	0
Inventories	14,815	9,108
Other current assets	8,111	5,434
Total current assets	795,689	358,601
Property and equipment:
Oil and natural gas properties, at cost, based on the full cost method of accounting	10,818,378	9,232,694
Midstream assets	355,758	191,519
Other property, equipment and land	85,882	80,776
Accumulated depletion, depreciation, amortization and impairment	(2,545,412)	(2,161,372)
Net property and equipment	8,714,606	7,343,617
Funds held in escrow	62,034	6,304
Investment in subsidiaries	0	0
Deferred tax asset	95,551	0
Investment in real estate, net	106,834	0
Other assets	31,859	62,463
Total assets	9,806,573	7,770,985
Current liabilities:
Accounts payable-trade	85,869	94,590
Intercompany payable	0	0
Other current liabilities	635,918	482,838
Total current liabilities	721,787	577,428
Long-term debt	2,332,359	1,477,347
Derivative instruments	5,931	6,303
Asset retirement obligations	23,897	20,122	19,982
Deferred income taxes	292,795	108,048
Other long-term liabilities	7	0
Total liabilities	3,376,776	2,189,248
Commitments and contingencies
Stockholders’ equity	5,933,359	5,254,860
Non-controlling interest	496,438	326,877
Total equity	6,429,797	5,581,737	5,586,123	4,018,292
Total liabilities and equity	9,806,573	7,770,985
Eliminations [Member]
Current assets:
Cash and cash equivalents	0	0	0	0
Accounts receivable	0	0
Accounts receivable - related party	(7,758)	(5,142)
Intercompany receivable	(3,462,384)	(4,892,118)
Inventories	0	0
Other current assets	0	0
Total current assets	(3,470,142)	(4,897,260)
Property and equipment:
Oil and natural gas properties, at cost, based on the full cost method of accounting	(3,297)	(414)
Midstream assets	0	0
Other property, equipment and land	0	0
Accumulated depletion, depreciation, amortization and impairment	(7,918)	4,342
Net property and equipment	(11,215)	3,928
Funds held in escrow	0	0
Investment in subsidiaries	(4,632,742)	(3,809,557)
Deferred tax asset	0
Investment in real estate, net	0
Other assets	0	0
Total assets	(8,114,099)	(8,702,889)
Current liabilities:
Accounts payable-trade	0	0
Intercompany payable	(3,470,142)	(4,897,260)
Other current liabilities	0	0
Total current liabilities	(3,470,142)	(4,897,260)
Long-term debt	0	0
Derivative instruments	0	0
Asset retirement obligations	0	0
Deferred income taxes	0	0
Other long-term liabilities	0
Total liabilities	(3,470,142)	(4,897,260)
Commitments and contingencies
Stockholders’ equity	(4,444,845)	(4,132,506)
Non-controlling interest	(199,112)	326,877
Total equity	(4,643,957)	(3,805,629)
Total liabilities and equity	(8,114,099)	(8,702,889)
Parent Company [Member] | Reportable Legal Entities [Member]
Current assets:
Cash and cash equivalents	471,148	54,074	20,856	1,643,226
Accounts receivable	0	0
Accounts receivable - related party	0	0
Intercompany receivable	3,199,881	2,624,810
Inventories	0	0
Other current assets	257	618
Total current assets	3,671,286	2,679,502
Property and equipment:
Oil and natural gas properties, at cost, based on the full cost method of accounting	0	0
Midstream assets	0	0
Other property, equipment and land	0	0
Accumulated depletion, depreciation, amortization and impairment	0	0
Net property and equipment	0	0
Funds held in escrow	0	0
Investment in subsidiaries	4,631,753	3,809,557
Deferred tax asset	0
Investment in real estate, net	0
Other assets	0	0
Total assets	8,303,039	6,489,059
Current liabilities:
Accounts payable-trade	0	1
Intercompany payable	0	132,067
Other current liabilities	41,026	7,236
Total current liabilities	41,026	139,304
Long-term debt	2,035,859	986,847
Derivative instruments	0	0
Asset retirement obligations	0	0
Deferred income taxes	292,795	108,048
Other long-term liabilities	0
Total liabilities	2,369,680	1,234,199
Commitments and contingencies
Stockholders’ equity	5,933,359	5,254,860
Non-controlling interest	0	0
Total equity	5,933,359	5,254,860
Total liabilities and equity	8,303,039	6,489,059
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Current assets:
Cash and cash equivalents	20,469	34,175	4,911	14,135
Accounts receivable	226,299	205,859
Accounts receivable - related party	0	0
Intercompany receivable	262,503	2,267,308
Inventories	14,815	9,108
Other current assets	7,708	4,461
Total current assets	531,794	2,520,911
Property and equipment:
Oil and natural gas properties, at cost, based on the full cost method of accounting	9,209,250	8,129,211
Midstream assets	355,758	191,519
Other property, equipment and land	80,194	80,776
Accumulated depletion, depreciation, amortization and impairment	(2,306,710)	(1,976,248)
Net property and equipment	7,338,492	6,425,258
Funds held in escrow	62,034	0
Investment in subsidiaries	989	0
Deferred tax asset	0
Investment in real estate, net	106,834
Other assets	8,513	25,609
Total assets	8,048,656	8,971,778
Current liabilities:
Accounts payable-trade	85,865	91,629
Intercompany payable	3,470,142	4,765,193
Other current liabilities	590,186	472,933
Total current liabilities	4,146,193	5,329,755
Long-term debt	0	397,000
Derivative instruments	5,931	6,303
Asset retirement obligations	23,897	20,122
Deferred income taxes	0	0
Other long-term liabilities	7
Total liabilities	4,176,028	5,753,180
Commitments and contingencies
Stockholders’ equity	3,872,628	3,218,598
Non-controlling interest	0	0
Total equity	3,872,628	3,218,598
Total liabilities and equity	8,048,656	8,971,778
Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Current assets:
Cash and cash equivalents	16,829	24,197	$ 4,438	$ 9,213
Accounts receivable	38,018	25,754
Accounts receivable - related party	7,758	5,142
Intercompany receivable	0	0
Inventories	0	0
Other current assets	146	355
Total current assets	62,751	55,448
Property and equipment:
Oil and natural gas properties, at cost, based on the full cost method of accounting	1,612,425	1,103,897
Midstream assets	0	0
Other property, equipment and land	5,688	0
Accumulated depletion, depreciation, amortization and impairment	(230,784)	(189,466)
Net property and equipment	1,387,329	914,431
Funds held in escrow	0	6,304
Investment in subsidiaries	0	0
Deferred tax asset	95,551
Investment in real estate, net	0
Other assets	23,346	36,854
Total assets	1,568,977	1,013,037
Current liabilities:
Accounts payable-trade	4	2,960
Intercompany payable	0	0
Other current liabilities	4,706	2,669
Total current liabilities	4,710	5,629
Long-term debt	296,500	93,500
Derivative instruments	0	0
Asset retirement obligations	0	0
Deferred income taxes	0	0
Other long-term liabilities	0
Total liabilities	301,210	99,129
Commitments and contingencies
Stockholders’ equity	572,217	913,908
Non-controlling interest	695,550	0
Total equity	1,267,767	913,908
Total liabilities and equity	$ 1,568,977	$ 1,013,037

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Guarantor Financial Statements - Income Statement (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenues:
Lease bonus	$ 1,322	$ 322	$ 2,250	$ 2,507
Other operating income	2,359	0	6,825	0
Revenue	538,029	301,253	1,544,497	805,917
Costs and expenses:
Lease operating expenses	49,111	32,498	129,103	88,113
Production and ad valorem taxes	33,536	18,371	93,042	49,975
Depreciation, depletion and amortization	146,318	87,579	391,401	221,681
General and administrative expenses	14,185	11,888	45,039	37,524
Asset retirement obligation accretion	387	357	1,107	1,030
Other operating expense	940	0	2,416	0
Total costs and expenses	271,178	158,614	728,697	414,560
Income (loss) from operations	266,851	142,639	815,800	391,357
Other income (expense):
Interest expense, net	(18,548)	(9,192)	(49,345)	(29,662)
Other income (expense), net	1,962	3	89,170	9,472
Gain (loss) on derivative instruments, net	(48,373)	(50,645)	(139,305)	20,376
Gain (loss) on revaluation of investment	(199)	0	5,165	0
Total other income (expense), net	(65,158)	(59,834)	(94,315)	186
Income (loss) before income taxes	201,693	82,805	721,485	391,543
Provision for income taxes	42,276	857	82,750	4,393
Net income	159,417	81,948	638,735	387,150
Net income attributable to non-controlling interest	2,363	8,924	99,723	19,448
Net income (loss) attributable to Diamondback Energy, Inc.	157,054	73,024	539,012	367,702
Eliminations [Member]
Revenues:
Lease bonus	(2,883)	0	(2,883)	(106)
Other operating income	0		0
Revenue	(2,883)	0	(2,883)	(106)
Costs and expenses:
Lease operating expenses	0	0	0	0
Production and ad valorem taxes	0	0	0	0
Depreciation, depletion and amortization	4,159	1,745	12,261	2,346
General and administrative expenses	(615)	(615)	(1,845)	(1,845)
Asset retirement obligation accretion	0	0	0	0
Other operating expense	0		0
Total costs and expenses	3,544	1,130	10,416	501
Income (loss) from operations	(6,427)	(1,130)	(13,299)	(607)
Other income (expense):
Interest expense, net	0	0	0	0
Other income (expense), net	(615)	(615)	(1,845)	(1,845)
Gain (loss) on derivative instruments, net	0	0	0	0
Gain (loss) on revaluation of investment	0		0
Total other income (expense), net	(615)	(615)	(1,845)	(1,845)
Income (loss) before income taxes	(7,042)	(1,745)	(15,144)	(2,452)
Provision for income taxes	0	0	0	0
Net income	(7,042)	(1,745)	(15,144)	(2,452)
Net income attributable to non-controlling interest	(46,103)	8,924	22,197	19,448
Net income (loss) attributable to Diamondback Energy, Inc.	39,061	(10,669)	(37,341)	(21,900)
Parent Company [Member] | Reportable Legal Entities [Member]
Revenues:
Lease bonus	0	0	0	0
Other operating income	0		0
Revenue	0	0	0	0
Costs and expenses:
Lease operating expenses	0	0	0	0
Production and ad valorem taxes	0	0	0	0
Depreciation, depletion and amortization	0	0	0	0
General and administrative expenses	6,862	6,506	20,891	20,046
Asset retirement obligation accretion	0	0	0	0
Other operating expense	0		0
Total costs and expenses	6,862	6,506	20,891	20,046
Income (loss) from operations	(6,862)	(6,506)	(20,891)	(20,046)
Other income (expense):
Interest expense, net	(10,868)	(6,393)	(29,945)	(23,526)
Other income (expense), net	416	9	750	1,101
Gain (loss) on derivative instruments, net	0	0	0	0
Gain (loss) on revaluation of investment	0		0
Total other income (expense), net	(10,452)	(6,384)	(29,195)	(22,425)
Income (loss) before income taxes	(17,314)	(12,890)	(50,086)	(42,471)
Provision for income taxes	41,512	857	153,864	4,393
Net income	(58,826)	(13,747)	(203,950)	(46,864)
Net income attributable to non-controlling interest	0	0	0	0
Net income (loss) attributable to Diamondback Energy, Inc.	(58,826)	(13,747)	(203,950)	(46,864)
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Revenues:
Lease bonus	0	0	0	0
Other operating income	2,347		6,705
Revenue	462,309	258,720	1,330,928	693,216
Costs and expenses:
Lease operating expenses	49,111	32,498	129,103	88,113
Production and ad valorem taxes	28,509	15,546	78,909	42,307
Depreciation, depletion and amortization	125,627	74,766	337,823	190,748
General and administrative expenses	6,629	4,629	19,763	14,259
Asset retirement obligation accretion	387	357	1,107	1,030
Other operating expense	940		2,416
Total costs and expenses	237,015	135,512	634,413	352,202
Income (loss) from operations	225,294	123,208	696,515	341,014
Other income (expense):
Interest expense, net	(3,969)	(1,940)	(10,339)	(4,022)
Other income (expense), net	1,521	210	88,786	9,690
Gain (loss) on derivative instruments, net	(48,373)	(50,645)	(139,305)	20,376
Gain (loss) on revaluation of investment	0		0
Total other income (expense), net	(50,821)	(52,375)	(60,858)	26,044
Income (loss) before income taxes	174,473	70,833	635,657	367,058
Provision for income taxes	0	0	0	0
Net income	174,473	70,833	635,657	367,058
Net income attributable to non-controlling interest	0	0	0	0
Net income (loss) attributable to Diamondback Energy, Inc.	174,473	70,833	635,657	367,058
Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Revenues:
Lease bonus	4,205	322	5,133	2,613
Other operating income	12		120
Revenue	78,603	42,533	216,452	112,807
Costs and expenses:
Lease operating expenses	0	0	0	0
Production and ad valorem taxes	5,027	2,825	14,133	7,668
Depreciation, depletion and amortization	16,532	11,068	41,317	28,587
General and administrative expenses	1,309	1,368	6,230	5,064
Asset retirement obligation accretion	0	0	0	0
Other operating expense	0		0
Total costs and expenses	23,757	15,466	62,977	41,811
Income (loss) from operations	54,846	27,067	153,475	70,996
Other income (expense):
Interest expense, net	(3,711)	(859)	(9,061)	(2,114)
Other income (expense), net	640	399	1,479	526
Gain (loss) on derivative instruments, net	0	0	0	0
Gain (loss) on revaluation of investment	(199)		5,165
Total other income (expense), net	(3,270)	(460)	(2,417)	(1,588)
Income (loss) before income taxes	51,576	26,607	151,058	69,408
Provision for income taxes	764	0	(71,114)	0
Net income	50,812	26,607	222,172	69,408
Net income attributable to non-controlling interest	48,466	0	77,526	0
Net income (loss) attributable to Diamondback Energy, Inc.	2,346	26,607	144,646	69,408
Oil sales
Revenues:
Revenue	454,644	259,049	1,334,349	704,007
Oil sales | Eliminations [Member]
Revenues:
Revenue	63,593	36,011	185,165	96,626
Oil sales | Parent Company [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	0	0	0	0
Oil sales | Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	391,051	223,038	1,149,184	607,381
Oil sales | Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	0	0	0	0
Natural gas sales
Revenues:
Revenue	14,814	14,922	40,557	37,537
Natural gas sales | Eliminations [Member]
Revenues:
Revenue	3,923	3,148	9,152	6,449
Natural gas sales | Parent Company [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	0	0	0	0
Natural gas sales | Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	10,891	11,774	31,405	31,088
Natural gas sales | Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	0	0	0	0
Natural gas liquid sales
Revenues:
Revenue	57,610	25,266	133,858	57,625
Natural gas liquid sales | Eliminations [Member]
Revenues:
Revenue	6,870	3,052	16,882	7,119
Natural gas liquid sales | Parent Company [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	0	0	0	0
Natural gas liquid sales | Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	50,740	22,214	116,976	50,506
Natural gas liquid sales | Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	0	0	0	0
Royalty [Member]
Revenues:
Revenue	0	0	0	0
Royalty [Member] | Eliminations [Member]
Revenues:
Revenue	(74,386)	(42,211)	(211,199)	(110,194)
Royalty [Member] | Parent Company [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	0	0	0	0
Royalty [Member] | Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	0	0	0	0
Royalty [Member] | Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	74,386	42,211	211,199	110,194
Midstream services
Revenues:
Revenue	7,280	1,694	26,658	4,241
Costs and expenses:
Cost of Goods and Services Sold	19,725	4,445	48,515	7,127
Midstream services | Eliminations [Member]
Revenues:
Revenue	0	0	0	0
Costs and expenses:
Cost of Goods and Services Sold	0	0	0	0
Midstream services | Parent Company [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	0	0	0	0
Costs and expenses:
Cost of Goods and Services Sold	0	0	0	0
Midstream services | Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	7,280	1,694	26,658	4,241
Costs and expenses:
Cost of Goods and Services Sold	19,725	4,445	48,515	7,127
Midstream services | Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Revenues:
Revenue	0	0	0	0
Costs and expenses:
Cost of Goods and Services Sold	0	0	0	0
Gathering and Transportation [Member]
Costs and expenses:
Cost of Goods and Services Sold	6,976	3,476	18,074	9,110
Gathering and Transportation [Member] | Eliminations [Member]
Costs and expenses:
Cost of Goods and Services Sold	0	0	0	0
Gathering and Transportation [Member] | Parent Company [Member] | Reportable Legal Entities [Member]
Costs and expenses:
Cost of Goods and Services Sold	0	0	0	0
Gathering and Transportation [Member] | Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Costs and expenses:
Cost of Goods and Services Sold	6,087	3,271	16,777	8,618
Gathering and Transportation [Member] | Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Costs and expenses:
Cost of Goods and Services Sold	$ 889	$ 205	$ 1,297	$ 492

XML

Guarantor Financial Statements - Cash Flow Statement (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	Mar. 31, 2018	Sep. 30, 2018	Sep. 30, 2017
Condensed Financial Statements, Captions [Line Items]
Net cash provided by (used in) operating activities		$ 1,151,716	$ 638,018
Cash flows from investing activities:
Additions to oil and natural gas properties		(1,010,325)	(531,489)
Additions to midstream assets		(129,820)	(22,491)
Purchase of other property, equipment and land		(2,049)	(21,534)
Acquisition of leasehold interests		(185,658)	(1,892,864)
Acquisition of mineral interests		(335,574)	(370,855)
Acquisition of midstream assets		0	(50,279)
Proceeds from sale of assets		6,771	3,584
Funds held in escrow		(51,045)	121,391
Equity investments		(604)	(188)
Intercompany transfers		0	0
Investment in real estate	$ (109,700)	(110,654)	0
Net cash used in investing activities		(1,818,958)	(2,764,725)
Cash flows from financing activities:
Proceeds from borrowing under credit facility		1,027,500	533,000
Repayment under credit facility		(1,221,500)	(383,500)
Proceeds from senior notes		1,062,000	0
Purchase of subsidiary units by parent			0
Debt issuance costs		(14,578)	(1,714)
Public offering costs		(2,636)	(510)
Proceeds from public offerings		305,773	370,344
Contributions to subsidiaries		0
Contributions by members		0
Distributions from subsidiary		0	0
Proceeds from exercise of stock options		0	358
Proceeds from unit options exercised		140	0
Dividends to stockholders		(24,656)	0
Distributions to non-controlling interest		(68,801)	(27,640)
Intercompany transfers		0
Net cash provided by financing activities		1,063,242	490,338
Net increase (decrease) in cash and cash equivalents		396,000	(1,636,369)
Cash and cash equivalents at beginning of period	112,446	112,446	1,666,574
Cash and cash equivalents at end of period		508,446	30,205
Eliminations [Member]
Condensed Financial Statements, Captions [Line Items]
Net cash provided by (used in) operating activities		0	0
Cash flows from investing activities:
Additions to oil and natural gas properties		0	0
Additions to midstream assets		0	0
Purchase of other property, equipment and land		0	0
Acquisition of leasehold interests		0	0
Acquisition of mineral interests		0	0
Acquisition of midstream assets			0
Proceeds from sale of assets		0	0
Funds held in escrow		0	0
Equity investments		0	0
Intercompany transfers		0	0
Investment in real estate		0
Net cash used in investing activities		0	0
Cash flows from financing activities:
Proceeds from borrowing under credit facility		0	0
Repayment under credit facility		0	0
Proceeds from senior notes		0
Purchase of subsidiary units by parent			10,068
Debt issuance costs		0	0
Public offering costs		0	0
Proceeds from public offerings		0	(10,068)
Contributions to subsidiaries		(2,000)
Contributions by members		(2,000)
Distributions from subsidiary		(112,671)	(64,858)
Proceeds from exercise of stock options			0
Proceeds from unit options exercised		0
Dividends to stockholders		0
Distributions to non-controlling interest		112,671	64,858
Intercompany transfers		0
Net cash provided by financing activities		0	0
Net increase (decrease) in cash and cash equivalents		0	0
Cash and cash equivalents at beginning of period	0	0	0
Cash and cash equivalents at end of period		0	0
Parent Company [Member] | Reportable Legal Entities [Member]
Condensed Financial Statements, Captions [Line Items]
Net cash provided by (used in) operating activities		220	(25,369)
Cash flows from investing activities:
Additions to oil and natural gas properties		0	0
Additions to midstream assets		0	0
Purchase of other property, equipment and land		0	0
Acquisition of leasehold interests		0	0
Acquisition of mineral interests		0	0
Acquisition of midstream assets			0
Proceeds from sale of assets		0	0
Funds held in escrow		0	0
Equity investments		0	0
Intercompany transfers		(22,310)	(1,651,328)
Investment in real estate		0
Net cash used in investing activities		(22,310)	(1,651,328)
Cash flows from financing activities:
Proceeds from borrowing under credit facility		0	0
Repayment under credit facility		0	0
Proceeds from senior notes		1,062,000
Purchase of subsidiary units by parent			(10,068)
Debt issuance costs		(13,723)	(744)
Public offering costs		0	(77)
Proceeds from public offerings		0	0
Contributions to subsidiaries		1,000
Contributions by members		0
Distributions from subsidiary		112,671	64,858
Proceeds from exercise of stock options			358
Proceeds from unit options exercised		0
Dividends to stockholders		(24,656)
Distributions to non-controlling interest		0	0
Intercompany transfers		(696,128)
Net cash provided by financing activities		439,164	54,327
Net increase (decrease) in cash and cash equivalents		417,074	(1,622,370)
Cash and cash equivalents at beginning of period	54,074	54,074	1,643,226
Cash and cash equivalents at end of period		471,148	20,856
Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Condensed Financial Statements, Captions [Line Items]
Net cash provided by (used in) operating activities		975,082	569,330
Cash flows from investing activities:
Additions to oil and natural gas properties		(1,010,325)	(531,489)
Additions to midstream assets		(129,820)	(22,491)
Purchase of other property, equipment and land		2,638	(21,534)
Acquisition of leasehold interests		(185,658)	(1,892,864)
Acquisition of mineral interests		170,268	(69,722)
Acquisition of midstream assets			(50,279)
Proceeds from sale of assets		6,206	3,584
Funds held in escrow		(51,045)	121,391
Equity investments		(604)	(188)
Intercompany transfers		22,310	1,651,328
Investment in real estate		(110,654)
Net cash used in investing activities		(1,286,684)	(812,264)
Cash flows from financing activities:
Proceeds from borrowing under credit facility		470,500	312,500
Repayment under credit facility		(867,500)	(78,000)
Proceeds from senior notes		0
Purchase of subsidiary units by parent			0
Debt issuance costs		(232)	(790)
Public offering costs		0	0
Proceeds from public offerings		0	0
Contributions to subsidiaries		0
Contributions by members		0
Distributions from subsidiary		0	0
Proceeds from exercise of stock options			0
Proceeds from unit options exercised		0
Dividends to stockholders		0
Distributions to non-controlling interest		0	0
Intercompany transfers		695,128
Net cash provided by financing activities		297,896	233,710
Net increase (decrease) in cash and cash equivalents		(13,706)	(9,224)
Cash and cash equivalents at beginning of period	34,175	34,175	14,135
Cash and cash equivalents at end of period		20,469	4,911
Non-Guarantor Subsidiaries [Member] | Reportable Legal Entities [Member]
Condensed Financial Statements, Captions [Line Items]
Net cash provided by (used in) operating activities		176,414	94,057
Cash flows from investing activities:
Additions to oil and natural gas properties		0	0
Additions to midstream assets		0	0
Purchase of other property, equipment and land		(4,687)	0
Acquisition of leasehold interests		0	0
Acquisition of mineral interests		(505,842)	(301,133)
Acquisition of midstream assets			0
Proceeds from sale of assets		565	0
Funds held in escrow		0	0
Equity investments		0	0
Intercompany transfers		0	0
Investment in real estate		0
Net cash used in investing activities		(509,964)	(301,133)
Cash flows from financing activities:
Proceeds from borrowing under credit facility		557,000	220,500
Repayment under credit facility		(354,000)	(305,500)
Proceeds from senior notes		0
Purchase of subsidiary units by parent			0
Debt issuance costs		(623)	(180)
Public offering costs		(2,636)	(433)
Proceeds from public offerings		305,773	380,412
Contributions to subsidiaries		1,000
Contributions by members		2,000
Distributions from subsidiary		0	0
Proceeds from exercise of stock options			0
Proceeds from unit options exercised		140
Dividends to stockholders		0
Distributions to non-controlling interest		(181,472)	(92,498)
Intercompany transfers		1,000
Net cash provided by financing activities		326,182	202,301
Net increase (decrease) in cash and cash equivalents		(7,368)	(4,775)
Cash and cash equivalents at beginning of period	$ 24,197	24,197	9,213
Cash and cash equivalents at end of period		$ 16,829	$ 4,438