Item 16. FORM 10-K SUMMARY

None

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:	February 22, 2019
			/s/ Travis D. Stice
			Travis D. Stice
			Chief Executive Officer
			(Principal Executive Officer)

Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature		Title		Date
/s/ Steven E. West		Chairman of the Board and Director		February 22, 2019
Steven E. West
/s/ Travis D. Stice		Chief Executive Officer and Director		February 22, 2019
Travis D. Stice		(Principal Executive Officer)
/s/ Michael P. Cross		Director		February 22, 2019
Michael P. Cross
/s/ Michael L. Hollis		President, Chief Operating Officer and Director		February 22, 2019
Michael L. Hollis
/s/ David L. Houston		Director		February 22, 2019
David L. Houston
/s/ Mark L. Plaumann		Director		February 22, 2019
Mark L. Plaumann
/s/ Melanie M. Trent		Director		February 22, 2019
Melanie M. Trent
/s/ Teresa L. Dick		Chief Financial Officer, Senior Vice President, and Assistant Secretary		February 22, 2019
Teresa L. Dick		(Principal Financial and Accounting Officer)

S-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

Diamondback Energy, Inc.

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Diamondback Energy, Inc. (a Delaware corporation) and subsidiaries (collectively the “Company”) as of December 31, 2018 and 2017, and the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2018, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 22, 2019 expressed an unqualified opinion.

Basis for opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP

We have served as the Company’s auditor since 2009.

Oklahoma City, Oklahoma

February 22, 2019

F-1

Diamondback Energy, Inc. and Subsidiaries

Consolidated Balance Sheets

	December 31,
	2018				2017
	(In thousands, except share amounts)
Assets
Current assets:
Cash and cash equivalents	$	214,516			$	112,446
Accounts receivable:
Joint interest and other, net	95,536				73,038
Oil and natural gas sales	296,525				158,575
Inventories	37,570				9,108
Derivative instruments	230,527				531
Prepaid expenses and other	50,347				4,903
Total current assets	925,021				358,601
Property and equipment:
Oil and natural gas properties, full cost method of accounting ($9,669,977 and $4,105,865 excluded from amortization at December 31, 2018 and 2017, respectively)	22,299,182				9,232,694
Midstream assets	700,295				191,519
Other property, equipment and land	146,963				80,776
Accumulated depletion, depreciation, amortization and impairment	(2,774,465		)		(2,161,372		)
Net property and equipment	20,371,975				7,343,617
Funds held in escrow	—				6,304
Deferred tax asset	96,670				—
Investment in real estate, net	115,625				—
Other assets	86,396				62,463
Total assets	$	21,595,687			$	7,770,985
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	127,979			$	94,590
Accrued capital expenditures	495,089				221,256
Other accrued liabilities	253,272				92,512
Revenues and royalties payable	143,272				68,703
Derivative instruments	—				100,367
Total current liabilities	1,019,612				577,428
Long-term debt	4,464,338				1,477,347
Derivative instruments	15,192				6,303
Asset retirement obligations	136,181				20,122
Deferred income taxes	1,784,532				108,048
Other long-term liabilities	9,570				—
Total liabilities	7,429,425				2,189,248
Commitments and contingencies (Note 17)
Stockholders’ equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 164,273,447 issued and outstanding at December 31, 2018; 200,000,000 shares authorized, 98,167,289 issued and outstanding at December 31, 2017	1,643				982
Additional paid-in capital	12,935,885				5,291,011
Retained earnings (accumulated deficit)	761,833				(37,133		)
Accumulated other comprehensive income	(74		)		—
Total Diamondback Energy, Inc. stockholders’ equity	13,699,287				5,254,860
Non-controlling interest	466,975				326,877
Total equity	14,166,262				5,581,737
Total liabilities and equity	$	21,595,687			$	7,770,985

See accompanying notes to consolidated financial statements.

F-2

Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

	Year Ended December 31,
	2018				2017				2016
	(In thousands, except per share amounts)
Revenues:
Oil sales	$	1,878,625			$	1,044,017			$	470,528
Natural gas sales	61,046				52,210				22,506
Natural gas liquid sales	190,109				90,048				34,073
Lease bonus	2,920				11,764				—
Midstream services	34,254				7,072				—
Other operating income	9,302				—				—
Total revenues	2,176,256				1,205,111				527,107
Costs and expenses:
Lease operating expenses	204,975				126,524				82,428
Production and ad valorem taxes	132,661				73,505				34,456
Gathering and transportation	26,113				12,834				11,606
Midstream services	71,878				10,409				—
Depreciation, depletion and amortization	623,039				326,759				178,015
Impairment of oil and natural gas properties	—				—				245,536
General and administrative expenses	64,554				48,669				42,619
Asset retirement obligation accretion	2,132				1,391				1,064
Merger and integration expense	36,831				—				—
Other operating expense	3,285				—				—
Total costs and expenses	1,165,468				600,091				595,724
Income (loss) from operations	1,010,788				605,020				(68,617		)
Other income (expense):
Interest expense, net	(87,276		)		(40,554		)		(40,684		)
Other income, net	88,996				10,235				3,064
Gain (loss) on derivative instruments, net	101,299				(77,512		)		(25,345		)
Loss on revaluation of investment	(550		)		—				—
Loss on extinguishment of debt	—				—				(33,134		)
Total other income (expense), net	102,469				(107,831		)		(96,099		)
Income (loss) before income taxes	1,113,257				497,189				(164,716		)
Provision for (benefit from) income taxes	168,362				(19,568		)		192
Net income (loss)	944,895				516,757				(164,908		)
Net income attributable to non-controlling interest	99,223				34,496				126
Net income (loss) attributable to Diamondback Energy, Inc.	$	845,672			$	482,261			$	(165,034	)
Earnings per common share:
Basic	$	8.09			$	4.95			$	(2.20	)
Diluted	$	8.06			$	4.94			$	(2.20	)
Weighted average common shares outstanding:
Basic	104,622				97,458				75,077
Diluted	104,929				97,688				75,077

See accompanying notes to consolidated financial statements.

F-3

Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income

	Year Ended December 31, 2018
	2018				2017				2016
	(In thousands)
Net income	$	944,895			$	516,757			$	(164,908	)
Other comprehensive income:
Postretirement plans:
Current period change in fair value of postretirement plans, net of tax of $0, $0 and $0, respectively	(74		)		—				—
Total other comprehensive income, net of tax	(74		)		—				—
Comprehensive income (loss)	944,821				516,757				(164,908		)
Comprehensive income attributable to noncontrolling interest	—				—				—
Comprehensive income (loss) attributable to Diamondback Energy, Inc.	$	944,821			$	516,757			$	(164,908	)

See accompanying notes to consolidated financial statements.

F-4

Diamondback Energy, Inc. and Subsidiaries

Consolidated Statement of Stockholders’ Equity

	Common Stock						Additional Paid-in Capital				Retained Earnings (Accumulated Deficit)				Accumulated Other Comprehensive Income (Loss)				Non-Controlling Interest
	Shares		Amount								Total
	(In thousands)
Balance December 31, 2015	66,797		$	668			$	2,229,664			$	(354,360	)		$	—			$	233,001			$	2,108,973
Net proceeds from issuance of common units - Viper Energy Partners LP	—		—				—				—				—				93,462				93,462
Unit-based compensation			—				—				—				—				3,815				3,815
Distribution to non-controlling interest			—				—				—				—				(9,574		)		(9,574		)
Stock-based compensation			—				29,717				—				—				—				29,717
Common shares issued in public offering, net of offering costs	23,000		229				1,956,079				—				—				—				1,956,308
Exercise of stock options and vesting of restricted stock units	347		4				495				—				—				—				499
Net income (loss)			—				—				(165,034		)		—				126				(164,908		)
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			—				—				—				—				2,395				2,395
Common units issued for acquisition			—				—				—				—				3,050				3,050
Stock-based compensation			—				31,783				—				—				—				31,783
Distribution to non-controlling interest			—				—				—				—				(41,367		)		(41,367		)
Common shares issued in public offering, net of offering costs			—				14				—				—				—				14
Common shares issued for Brigham	7,686		77				809,096				—				—				—				809,173
Exercise of stock options and vesting of restricted stock units	337		4				355				—				—				—				359
Change in ownership of consolidated subsidiaries, net			—				233,808				—				—				(362,423		)		(128,615		)
Net income			—				—				482,261				—				34,496				516,757
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			—				—				—				—				303,121				303,121
Unit-based compensation			—				—				—				—				2,763				2,763
Common shares issued for business combination	63,126		631				7,069,489				—				—				—				7,070,120
Stock options assumed in business combination			—				14,088				—				—				—				14,088
Restricted stock units assumed in business combination			—				51,829				—				—				—				51,829
Repurchased shares for tax withholding	(140	)	—				(14,460		)		—				—				—				(14,460		)
Stock-based compensation			—				34,035				—				—				—				34,035

F-5

Diamondback Energy, Inc. and Subsidiaries

Consolidated Statement of Stockholders’ Equity

	Common Stock						Additional Paid-in Capital				Retained Earnings (Accumulated Deficit)				Accumulated Other Comprehensive Income (Loss)				Non-Controlling Interest
	Shares		Amount								Total
Distribution to non-controlling interest			—				—				—				—				(98,345		)		(98,345		)
Common shares issued for Ajax	2,584		25				339,975				—				—				—				340,000
Dividend paid			—				—				(37,313		)		—				—				(37,313		)
Exercise of unit options and awards of restricted stock	536		5				(5		)		—				—				140				140
Other comprehensive income, net of tax			—				—				—				(74		)		—				(74		)
Change in ownership of consolidated subsidiaries, net			—				149,923				—				—				(160,133		)		(10,210		)
Net income			—				—				845,672				—				99,223				944,895
Balance December 31, 2018	164,273		$	1,643			$	12,935,885			$	761,833			$	(74	)		$	466,975			$	14,166,262

See accompanying notes to consolidated financial statements.

F-6

Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

	Year Ended December 31,
	2018				2017				2016
	(In thousands)
Cash flows from operating activities:
Net income (loss)	$	944,895			$	516,757			$	(164,908	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Provision for (benefit from) deferred income taxes	169,357				(20,567		)		—
Impairment of oil and natural gas properties	—				—				245,536
Asset retirement obligation accretion	2,132				1,391				1,064
Depreciation, depletion and amortization	623,039				326,759				178,015
Amortization of debt issuance costs	11,613				3,943				2,717
Loss on early extinguishment of debt	—				—				33,134
Change in fair value of derivative instruments	(221,732		)		84,240				26,522
Income from equity investment	—				(657		)		(676		)
Loss on revaluation of investment	550				—				—
Equity-based compensation expense	26,764				25,537				26,453
Loss (gain) on sale of assets, net	3,081				(455		)		(61		)
Changes in operating assets and liabilities:
Accounts receivable	13,160				(97,611		)		(35,030		)
Accounts receivable-related party	—				297				1,294
Restricted cash	—				500				—
Inventories	(14,774		)		(2,245		)		(255		)
Prepaid expenses and other	24,688				(11,362		)		(709		)
Accounts payable and accrued liabilities	(6,846		)		36,762				15,922
Accounts payable and accrued liabilities-related party	—				(2		)		(216		)
Income tax payable	(814		)		814				—
Accrued interest	(22,203		)		(20,774		)		(3,161		)
Revenues and royalties payable	11,595				45,298				6,439
Net cash provided by operating activities	1,564,505				888,625				332,080
Cash flows from investing activities:
Additions to oil and natural gas properties	(1,460,509		)		(792,599		)		(362,450		)
Additions to oil and natural gas properties-related party	—				—				(637		)
Additions to midstream assets	(204,222		)		(68,139		)		(1,188		)
Purchase of other property, equipment and land	(6,840		)		(22,779		)		(9,891		)
Acquisition of leasehold interests	(1,370,951		)		(1,960,591		)		(611,280		)
Acquisition of mineral interests	(440,303		)		(407,450		)		(205,721		)
Acquisition of midstream assets	—				(50,279		)		—
Proceeds from sale of assets	80,098				65,656				4,661
Investment in real estate	(110,685		)		—				—
Funds held in escrow	10,989				104,087				(121,391		)
Purchase of other investments	(8		)		—				—
Equity investments	(612		)		(188		)		(2,345		)
Net cash used in investing activities	(3,503,043		)		(3,132,282		)		(1,310,242		)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	2,651,500				753,500				164,000
Repayment under credit facility	(1,241,500		)		(383,500		)		(89,000		)
Repayment on Energen's credit facility	(559,000		)		—				—
Proceeds from senior notes	1,062,000				—				1,000,000

F-7

Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows - Continued

	Year Ended December 31,
	2018				2017				2016
	(In thousands)
Repayment of senior notes	—				—				(450,000		)
Premium on extinguishment of debt	—				—				(26,561		)
Debt issuance costs	(25,461		)		(9,296		)		(15,063		)
Public offering costs	(2,652		)		(510		)		(1,182		)
Proceeds from public offerings	305,773				370,344				2,051,503
Proceeds from exercise of unit options	140				—				—
Proceeds from exercise of stock options	—				358				498
Repurchased shares for tax withholdings	(14,460		)		—				—
Dividends to stockholders	(37,313		)		—				—
Other postemployment benefit changes	(74		)		—				—
Distributions to non-controlling interest	(98,345		)		(41,367		)		(9,574		)
Net cash provided by financing activities	2,040,608				689,529				2,624,621
Net increase (decrease) in cash and cash equivalents	102,070				(1,554,128		)		1,646,459
Cash and cash equivalents at beginning of period	112,446				1,666,574				20,115
Cash and cash equivalents at end of period	$	214,516			$	112,446			$	1,666,574
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest	$	113,932			$	57,668			$	38,177
Cash paid for income taxes	$	689			$	—			$	192
Supplemental disclosure of non-cash transactions:
Change in accrued capital expenditures	$	273,833			$	160,906			$	413
Capitalized stock-based compensation	$	10,034			$	8,641			$	7,079
Common stock issued for Ajax	$	340,000			$	—			$	—
Common stock issued for Brigham	$	—			$	809,173			$	—
Common stock issued for business combination(1)	$	7,136,037			$	—			$	—
Asset retirement obligations acquired	$	111,197			$	2,432			$	3,696

(1)	Includes $7,070,120 Common stock issued for business combination, $14,088 for stock options assumed and $51,829 for restricted stock units assumed.

See accompanying notes to consolidated financial statements.

F-8

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

1. DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION

Organization and Description of the Business

Diamondback Energy, Inc. (“Diamondback” or the “Company”) is an independent oil and 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. Diamondback was incorporated in Delaware on December 30, 2011.

On June 17, 2014, Diamondback entered into a contribution agreement with Viper Energy Partners LP (the “Partnership”), Viper Energy Partners GP LLC (the “General Partner”) and Viper Energy Partners LLC to transfer Diamondback’s ownership interest in Viper Energy Partners LLC to the Partnership in exchange for 70,450,000 common units. Diamondback also owns and controls the General Partner, which holds a non-economic general partner interest in the Partnership. On June 23, 2014, the Partnership completed its initial public offering (the “Viper Offering”) of 5,750,000 common units, and the Company’s common units represented an approximate 92% limited partner interest in the Partnership. On September 19, 2014, the Partnership completed an underwritten public offering of 3,500,000 common units. At the completion of this offering, the Company owned approximately 88% of the common units of the Partnership. See Note 4–Viper Energy Partners LP for additional information regarding the Partnership.

The wholly-owned subsidiaries of Diamondback, as of December 31, 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 and Rattler Midstream GP LLC, a Delaware limited liability company. The consolidated subsidiaries include the wholly-owned subsidiaries as well as Viper Energy Partners LP, a Delaware limited partnership (the “Partnership”), the Partnership’s wholly-owned subsidiary Viper Energy Partners LLC, a Delaware limited liability company (the “Operating Company”), Rattler Midstream LP (formerly known as Rattler Midstream Partners LP), a Delaware limited liability company, Rattler Midstream Operating LLC (formerly known as Rattler Midstream LLC), a Delaware limited liability company, and Rattler Midstream Operating LLC’s wholly-owned subsidiary Tall City Towers LLC, a Delaware limited liability company.

Basis of Presentation

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

The Partnership is consolidated in the financial statements of the Company. As of December 31, 2018, the Company owned approximately 59% of the total units outstanding of the Partnership and the Company’s wholly owned subsidiary, Viper Energy Partners GP LLC, is the General Partner of the Partnership.

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, but are not limited to, 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, equity-based compensation, fair value estimates of commodity derivatives and estimates of income taxes.

F-9

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Cash and Cash Equivalents

The Company considers all highly liquid investments purchased with a maturity of three months or less and money market funds to be cash equivalents. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments.

Restricted Cash

In 2014, a subsidiary of the Company entered into an agreement to purchase certain overriding royalty interests and deposited $0.5 million in escrow. The subsidiary subsequently terminated the agreement and requested a return of the deposit. The seller challenged the termination and the escrow agent tendered the deposit to the court subject to a judicial determination of the proper payment of the funds. The parties reached a settlement of this matter in April 2017 and the funds were distributed in accordance with the terms of the settlement. Pending such distribution, these funds were classified as restricted cash.

Accounts Receivable

Accounts receivable consist of receivables from joint interest owners on properties the Company operates and from sales of oil and natural gas production delivered to purchasers. The purchasers remit payment for production directly to the Company. Most payments for production are received within three months after the production date.

Accounts receivable are stated at amounts due from joint interest owners or purchasers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. At December 31, 2018, the Company recorded an allowance for doubtful accounts of $2.0 million related to joint interest receivables. No allowance was deemed necessary at December 31, 2017.

Derivative Instruments

The Company is required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. 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 change in fair value on derivative instruments for each period in the consolidated statements of operations.

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, restricted cash, receivables, payables, derivatives and senior notes. The carrying amount of cash and cash equivalents, receivables and payables approximates fair value because of the short-term nature of the instruments. The fair value of the revolving credit facility approximates its carrying value based on the borrowing rates currently available to the Company for bank loans with similar terms and maturities. The fair value of the senior notes are determined using quoted market prices. Derivatives are recorded at fair value (see Note 16–Fair Value Measurements).

F-10

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Prepaid Expenses and Other

Prepaid expenses and other consist of the following:

	Year Ended December 31,
	2018				2017
Prepaid insurance	$	4,303			$	1,273
Prepaid fees and licenses	2,944				2,250
Income tax receivable	37,858				—
Other	5,242				1,380
Total prepaid expenses and other	$	50,347			$	4,903

Oil and Natural Gas Properties

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. 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. Any income from services provided by subsidiaries to working interest owners of properties in which the Company also owns an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties proportionate to the Company’s investment in the subsidiary (see Note 8–Equity Method Investments). Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves. The average depletion rate per barrel equivalent unit of production was $12.62, $11.11 and $11.23 for the years ended December 31, 2018, 2017 and 2016, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties was $594.8 million, $321.9 million and $176.4 million for the years ended December 31, 2018, 2017 and 2016, respectively.

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, 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. During the year ended December 31, 2016, the Company recorded an impairment on proved oil and natural gas properties of $245.5 million. No impairments on proved oil and natural gas properties were recorded for the years ended December 31, 2018 and 2017.

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 Company assesses all items classified as unevaluated property on an annual basis for possible impairment. The Company assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.

F-11

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Real Estate Assets

Real estate assets are stated at cost, less accumulated depreciation and amortization. The Company considers the period of future benefit of each respective asset to determine the appropriate useful life and depreciation and amortization is calculated using the straight-line method over the assigned useful life.

Upon acquisition of real estate properties, the purchase price is allocated to tangible assets, consisting of land and building, and to identified intangible assets and liabilities, which may include the value of above market and below market leases and the value of in-place leases. The allocation of the purchase price is based upon the fair value of each component of the property. Although independent appraisals may be used to assist in the determination of fair value, in many cases these values will be based upon management’s assessment of each property, the selling prices of comparable properties and the discounted value of cash flows from the asset.

The fair values of above market and below market in-place leases will be recorded based on the present value (using an interest rate which reflects the risks associated with the leases acquired) of the difference between (i) the contractual amounts to be paid pursuant to the in-place leases and (ii) an estimate of fair market lease rates for the corresponding in-place leases measured over a period equal to the non-cancelable term of the lease including any bargain renewal periods. The above market and below market lease values will be capitalized as intangible lease assets or liabilities. Above market lease values will be amortized as an adjustment of rental income over the remaining term of the respective leases. Below market lease values will be amortized as an adjustment of rental income over the remaining term of the respective leases, including any bargain renewal periods. If a lease were to be terminated prior to its stated expiration, all unamortized amounts of above market and below market in-place lease values relating to that lease would be recorded as an adjustment to rental income.

The fair values of in-place leases will include estimated direct costs associated with obtaining a new tenant, and opportunity costs associated with lost rentals which are avoided by acquiring an in-place lease. Direct costs associated with obtaining a new tenant may include commissions, tenant improvements, and other direct costs and are estimated, in part, by management’s consideration of current market costs to execute a similar lease.

These direct costs will be included in intangible lease assets on the balance sheet and will be amortized to expense over the remaining term of the respective leases. The value of opportunity costs will be calculated using the contractual amounts to be paid pursuant to the in-place leases over a market absorption period for a similar lease. These intangibles will be included in intangible lease assets on the balance sheet and will be amortized to expense over the remaining term of the respective leases. If a lease were to be terminated prior to its stated expiration, all unamortized amounts of in-place lease assets relating to that lease would be expensed.

Other Property, Equipment and Land

Other property and equipment is recorded at cost. The Company expenses maintenance and repairs in the period incurred. Upon retirements or disposition of assets, the cost and related accumulated depreciation are removed from the consolidated balance sheet with the resulting gains or losses, if any, reflected in operations. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years. Depreciation expense for other property and equipment was $9.5 million, $1.4 million and $1.4 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Asset Retirement Obligations

The Company measures the future cost to retire its tangible long-lived assets and recognizes such cost as a liability for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset.

The Company records a liability relating to the retirement and removal of all assets used in their businesses. Asset retirement obligations represent the future abandonment costs of tangible assets, namely wells. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount or if there is a change in the estimated liability, the difference is recorded in oil and natural gas properties.

F-12

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Impairment of Long-Lived Assets

Other property and equipment used in operations are reviewed whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss is recognized only if the carrying amount of a long-lived asset is not recoverable from its estimated future undiscounted cash flows. An impairment loss is the difference between the carrying amount and fair value of the asset. The Company had no such impairment losses for the years ended December 31, 2018, 2017 and 2016, respectively.

Capitalized Interest

The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in progress to bring these unevaluated properties to their intended use. Capitalized interest cannot exceed gross interest expense. The Company capitalized interest of $32.8 million and $22.1 million for the years ended December 31, 2018 and 2017. The Company did not have any capitalized interest for the years ended December 31, 2016.

Inventories

Inventories are stated at the lower of cost or market and consist of tubular goods and equipment at December 31, 2018 and 2017. The Company’s tubular goods and equipment are primarily comprised of oil and natural gas drilling or repair items such as tubing, casing and pumping units. The inventory is primarily acquired for use in future drilling or repair operations and is carried at lower of cost or market. “Market”, in the context of inventory valuation, represents net realizable value, which is the amount that the Company is allowed to bill to the joint accounts under joint operating agreements to which the Company is a party. As of December 31, 2018, the Company estimated that all of its tubular goods and equipment will be utilized within one year.

Debt Issuance Costs

Other assets included capitalized costs related to the credit facility of $27.5 million and $16.7 million, net of accumulated amortization of $9.4 million and $7.0 million, as of December 31, 2018 and 2017, respectively. Long-term debt included capitalized costs related to the senior notes of $31.5 million and $15.2 million, net of accumulated amortization of $15.4 million and $2.0 million, as of December 31, 2018 and 2017, respectively. The costs associated with the senior notes are being netted against the senior notes balances and are being amortized over the term of the senior notes using the effective interest method. The costs associated with the Company’s credit facility that are included in other assets are being amortized over the term of the facility.

Other Accrued Liabilities

Other accrued liabilities consist of the following:

	December 31,
	2018				2017
	(In thousands)
Liability for drilling costs prepaid by joint interest partners	$	16,182			$	30,320
Interest payable	25,748				6,770
Lease operating expenses payable	59,455				27,850
Ad valorem taxes payable	49,160				3,306
Current portion of asset retirement obligations	60				1,163
Other	102,667				23,103
Total other accrued liabilities	$	253,272			$	92,512

F-13

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Revenue and Royalties Payable

For certain oil and natural gas properties, where the Company serves as operator, the Company receives production proceeds from the purchaser and further distributes such amounts to other revenue and royalty owners. Production proceeds that the Company has not yet distributed to other revenue and royalty owners are reflected as revenue and royalties payable in the accompanying consolidated balance sheets. The Company recognizes revenue for only its net revenue interest in oil and natural gas properties.

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 Operating 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

F-14

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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 December 31, 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.

Investments

Equity investments in which the Company exercises significant influence but does not control are accounted for using the equity method. Under the equity method, generally the Company’s share of investees’ earnings or loss is recognized in the statement of operations. The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company would recognize an impairment provision. There was no impairment for the Company’s equity investments for the years ended December 31, 2018, 2017 and 2016.

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 was 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 year ended December 31, 2018, the Partnership recorded a loss

F-15

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

of $0.6 million. The Partnership’s investment balance as of December 31, 2018 was $14.5 million, which is included in other assets in the accompanying consolidated balance sheets.

For additional information on the Company’s investments, see Note 8–Equity Method Investments.

Funds Held in Escrow

The funds held in escrow represent amounts in deposit to fund acquisitions. During the year ended December 31, 2018, the Company did not have any funds held in escrow. During the year ended December 31, 2017, there was $6.3 million in deposit to fund other acquisitions which closed in the first quarter of 2018.

Accounting for Equity-Based Compensation

The Company grants various types of stock-based awards including stock options and restricted stock units. The Partnership grants various unit-based awards including unit options and phantom units to employees, officers and directors of the General Partner and the Company who perform services for the Partnership. These plans and related accounting policies are defined and described more fully in Note 11–Equity-Based Compensation. Equity compensation awards are measured at fair value on the date of grant and are expensed, net of estimated forfeitures, over the required service period.

Concentrations

The Company is subject to risk resulting from the concentration of its crude oil and natural gas sales and receivables with several significant purchasers. For the year ended December 31, 2018, three purchasers each accounted for more than 10% of the Company’s revenue: Shell Trading (US) Company (26%); Koch Supply & Trading LP (15%); and Occidental Energy Marketing Inc (11%). For the year ended December 31, 2017, three purchasers each accounted for more than 10% of the Company’s revenue: Shell Trading (US) Company (31%); Koch Supply & Trading LP (19%); and Enterprise Crude Oil LLC (11%). For the year ended December 31, 2016, three purchasers each accounted for more than 10% of the Company’s revenue: Shell Trading (US) Company (45%); Koch Supply & Trading LP (15%); and Enterprise Crude Oil LLC (13%). The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Environmental Compliance and Remediation

Environmental compliance and remediation costs, including ongoing maintenance and monitoring, are expensed as incurred. Liabilities are accrued when environmental assessments and remediation are probable, and the costs can be reasonably estimated.

Income Taxes

Diamondback uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.

The Company is subject to margin tax in the state of Texas. During the years ended December 31, 2018, 2017 and 2016, the Company had no margin tax expense. The Company’s 2014, 2015, 2016, 2017 and 2018 federal income tax and state margin tax returns remain open to examination by tax authorities. As of December 31, 2018 we had an unrecognized tax benefit of $2.4 million. As of December 31, 2017, the Company had no unrecognized tax benefits that would have a material impact on the effective tax rate. The Company is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the years ended December 31, 2018, 2017 and 2016, there was no interest or penalties associated with uncertain tax positions recognized in the Company’s consolidated financial statements.

F-16

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Accumulated Other Comprehensive Income

The following table provides changes in the components of accumulated other comprehensive income, net of related income tax effects:

	(In thousands)
Balance as of December 1, 2018	$	—
Other comprehensive loss before reclassifications	(74		)
Change in accumulated other comprehensive income	(74		)
Balance as of December 31, 2018	$	(74	)

Recent 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 we expect 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 our 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 Company 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 applies 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 applies 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.

F-17

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Company enters into lease agreements to support its operations. These agreements are for leases on assets such as office space, vehicles and compressors. The Company has completed the process of reviewing and determining the contracts to which this new guidance applies. Upon adoption on January 1, 2019, the Company recognized approximately $13.6 million of right-of-use assets, of which the total amount relates to the Company’s operating leases.

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 adopted this standard effective January 1, 2019. The adoption of this update did 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 adopted this standard effective January 1, 2019. The adoption of this update did 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 2018-11, “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 adopted this standard effective January 1, 2019. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.

In December 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-20, “Leases (Topic 842) - Narrow-Scope Improvements for Lessors”. This update provides a practical expedient for lessors to elect not to evaluate whether sales taxes and other similar taxes are lessor costs. The update also requires a lessor to exclude from variable payments those costs paid directly by the lessee to third parties and include lessor costs paid by the lessor and reimbursed by the lessee. 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 adopted this standard effective January 1, 2019. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.

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 its consolidated financial statements since it 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,

F-18

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

2018, including interim periods within that fiscal year. The Company adopted this standard effective January 1, 2019. The adoption of this update did not 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 adopted this standard effective January 1, 2019. The adoption of this updated did not 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.

In November 2018, the Financial Accounting Standards Board issued Accounting Standards Update 2018-19, “Codification Improvements to Topic 326, Financial Instruments-Credit Losses”. This update clarifies that receivables arising from operating leases are not in scope of this topic, but rather Topic 842, Leases. 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 an impact on its financial statements since it does not have a history of credit losses.

3. ACQUISITIONS

2018 Activity

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.

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 of which approximately 0.5 million shares were placed in an indemnity escrow (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.

F-19

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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”).

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.

Energen Corporation Merger

On November 29, 2018, the Company completed its acquisition of Energen Corporation (“Energen”) in an all-stock transaction (the “ Merger”), which was accounted for as a business combination. The addition of Energen’s assets increased the Company’s assets to: (i) over 273,000 net Tier One acres in the Permian Basin, (ii) approximately 7,200 estimated total net horizontal Permian locations, and (iii) approximately 394,000 net acres across the Midland and Delaware Basins. Under the terms of the Merger, each share of Energen common stock was converted into 0.6442 of a share of the Company’s common stock. The Company issued approximately 62.8 million shares of its common stock valued at a price of $112.00 per share on the closing date, resulting in total consideration paid by the Company to the former Energen shareholders of approximately $7.1 billion.

In connection with the closing of the Merger, the Company repaid outstanding principal under Energen’s revolving credit facility and assumed all of Energen’s long-term debt. See Note 9—Debt for additional information.

Purchase Price Allocation

The Merger has been accounted for as a business combination, using the acquisition method. The following table represents the preliminary allocation of the total purchase price of Energen to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, valuation of pre-acquisition contingencies, final tax returns that provide the underlying tax basis of Energen’s assets and liabilities and final appraisals of assets acquired and liabilities assumed. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities may be revised as appropriate.

F-20

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

The following table sets forth the Company’s preliminary purchase price allocation:

	(In thousands)
Consideration:
Fair value of the Company's common stock issued	$	7,136,037
Total consideration	$	7,136,037
Fair value of liabilities assumed:
Current liabilities	$	349,254
Asset retirement obligation	104,907
Long-term debt	1,087,244
Noncurrent derivative instruments	17,308
Deferred income taxes	1,402,834
Other long-term liabilities	6,087
Amount attributable to liabilities assumed	$	2,967,634
Fair value of assets acquired:
Total current assets	305,086
Oil and natural gas properties	9,270,692
Midstream assets	262,752
Investment in real estate	10,700
Other property, equipment and land	58,388
Asset retirement obligation	104,907
Other postretirement assets	2,944
Noncurrent income tax receivable, net	75,713
Other long term assets	12,489
Amount attributable to assets acquired	$	10,103,671

The Company has included in its consolidated statements of operations revenues of $101.7 million and direct operating expenses of $17.1 million for the period from December 1, 2018 to December 31, 2018 due to the acquisition.

Pro Forma Financial Information

The following unaudited summary pro forma consolidated statement of operations data of Diamondback for the years ended December 31, 2018 and 2017 have been prepared to give effect to the Merger as if it had occurred on January 1, 2017. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for Energen’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the Company’s common stock issued to convert Energen’s outstanding shares of common stock and equity awards as of the closing date of the Merger, (ii) the depletion of Energen’s fair-valued proved oil and natural gas properties and (iii) the estimated tax impacts of the pro forma adjustments.

Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company of approximately $36.8 million for the year ended December 31, 2018 and acquisition-related costs incurred by Energen of $59.0 million. The pro forma results of operations do not include any cost savings or other synergies that may result from the Merger or any estimated costs that have been or will be incurred by the Company to integrate the Energen assets. The pro forma financial data does not include the results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material.

F-21

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

The pro forma consolidated statement of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Merger taken place on January 1, 2017 and is not intended to be a projection of future results.

	Year Ended December 31,
	2018				2017
	(in thousands, except per share amounts)
Revenues	$	3,531,609			$	2,195,726
Income from operations	1,559,141				900,435
Net income	1,319,967				875,382
Basic earnings per common share	7.54				5.26
Diluted earnings per common share	7.53				5.24

2017 Activity

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 has included in its consolidated statements of operations revenues of $81.4 million and direct operating expenses of $23.5 million for the period from February 28, 2017 to December 31, 2017 due to the acquisition.

Pro Forma Financial Information

The following unaudited summary pro forma consolidated statement of operations data of Diamondback for the years ended December 31, 2017 and 2016 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 the financial results that would have been attained had the acquisitions occurred on January 1, 2016.

F-22

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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.

	Year Ended December 31,
	2017				2016
	(in thousands, except per share amounts)
Revenues	$	1,228,040			$	627,301
Income from operations	619,369				(12,812		)
Net income	472,649				(109,229		)
Basic earnings per common share	4.85				(1.45		)
Diluted earnings per common share	4.84				(1.45		)

2016 Activity

On September 1, 2016, the Company acquired from an unrelated third party leasehold interests and related assets in the Southern Delaware Basin for an aggregate purchase price of $558.5 million. This transaction included approximately 26,797 gross (19,262 net) acres primarily in Reeves and Ward counties. The Company financed this acquisition with net proceeds from the July 2016 equity offering discussed in Note 10—Capital Stock and Earnings Per Share and cash on hand.

4. VIPER ENERGY PARTNERS LP

The Partnership is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Select Global Market under the symbol “VNOM”. The Partnership was formed by Diamondback on February 27, 2014, to, among other things, own, acquire and exploit oil and natural gas properties in North America. The Partnership is currently focused on oil and natural gas properties in the Permian Basin. Viper Energy Partners GP LLC, a consolidated subsidiary of Diamondback, serves as the general partner of, and holds a general partner interest in, the Partnership. As of December 31, 2018, the Company owned approximately 59% of the Partnership’s total units outstanding.

Prior to the completion on June 23, 2014 of the Viper Offering, Diamondback owned all of the general and limited partner interests in the Partnership. The Viper Offering consisted of 5,750,000 common units representing approximately 8% of the limited partner interests in the Partnership at a price to the public of $26.00 per common unit. In connection with the Viper Offering, Diamondback contributed all of the membership interests in Viper Energy Partners LLC to the Partnership in exchange for 70,450,000 common units. The contribution of Viper Energy Partners LLC to the Partnership was accounted for as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests.

During the year ended December 31, 2018, Diamondback received distributions of $155.1 million in respect of its interests in the Partnership and the Operating Company.

In August 2016, the Partnership completed an underwritten public offering of 8,050,000 common units, which included 1,050,000 common units issued pursuant to an option to purchase additional common units granted to the underwriter. In this offering, Diamondback purchased 2,000,000 common units from the underwriter at $15.60 per unit, which is the price per common unit paid by the underwriter to the Partnership. Following the August 2016 public offering, Diamondback had an approximate 83% limited partner interest in the Partnership. The Partnership received net proceeds from this offering of approximately $125.0 million, after deducting underwriting discounts and commissions and estimated offering expenses, which it used to fund an acquisition and repaid outstanding borrowings under its revolving credit facility.

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.

F-23

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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, Diamondback 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. Following this offering, the Company had an approximate 64% limited partner interest in the Partnership. 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 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, the Company owned approximately 59% of the Partnership’s total 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.

As a result of these public offerings and the Partnership’s issuance of unit-based compensation, the Company’s ownership percentage in the Partnership was reduced. During the year ended December 31, 2018, the Company recorded a $160.1 million decrease to Non-controlling interest in the Partnership with an increase to Additional paid-in capital, which represents the difference between the Company’s share of the underlying net book value in the Partnership before and after the respective Partnership common unit transactions, on the Company’s consolidated balance sheet.

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

F-24

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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 year ended December 31, 2018 and 2017, the General Partner allocated $2.5 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 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 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 year ended December 31, 2018, the Partnership accrued state income tax expense of $0.2 million 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 13—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 Bank, National Association, (“Wells Fargo”) as administrative agent sole book runner and lead arranger. See Note 9—Debt for a description of this credit facility.

5. REAL ESTATE ASSETS

In conjunction with Diamondback’s acquisition of Fasken Towers Tall Towers, the Company allocated the $109.7 million purchase price between real estate assets and intangible lease assets related to in-place and above-market leases. In addition, the Company owns a $1.3 million office building. The following schedules present the cost and related accumulated depreciation or amortization (as applicable) of Diamondback’s real estate assets including intangible lease assets:

	Estimated Useful Lives		December 31, 2018
	(Years)		(in thousands)
Buildings	30		$	92,349
Tenant improvements	15		4,160
Land	N/A		947
Land improvements	15		484
Total real estate assets			97,940
Less: accumulated depreciation			(3,970		)
Total investment in land and buildings, net			$	93,970

F-25

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

	Weighted Average Useful Lives		December 31, 2018
	(Months)		(in thousands)
In-place lease intangibles	45		$	10,866
Less: accumulated amortization			(3,076		)
In-place lease intangibles, net			7,790
Above-market lease intangibles	45		3,623
Less: accumulated amortization			(459		)
Above-market lease intangibles, net			3,164
Total intangible lease assets, net			$	10,954

6. PROPERTY AND EQUIPMENT

Property and equipment includes the following:

	December 31,
	2018				2017
	(in thousands)
Oil and natural gas properties:
Subject to depletion	$	12,629,205			$	5,126,829
Not subject to depletion	9,669,977				4,105,865
Gross oil and natural gas properties	22,299,182				9,232,694
Accumulated depletion	(1,599,111		)		(1,009,893		)
Accumulated impairment	(1,143,498		)		(1,143,498		)
Oil and natural gas properties, net	19,556,573				7,079,303
Midstream assets	700,295				191,519
Other property, equipment and land	146,963				80,776
Accumulated depreciation	(31,856		)		(7,981		)
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment	$	20,371,975			$	7,343,617
Balance of costs not subject to depletion:
Incurred in 2018	$	6,223,817
Incurred in 2017	2,500,003
Incurred in 2016	696,751
Incurred in 2015	182,194
Incurred in 2014	67,212
Total not subject to depletion	$	9,669,977

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 $28.7 million $22.0 million and $17.2 million for the years ended December 31, 2018, 2017 and 2016, 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

F-26

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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, 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.

As a result of the significant decline in prices during 2016, the Company recorded a non-cash ceiling test impairment for the year ended December 31, 2016 of $245.5 million, which is included in accumulated depletion. No impairments on proved oil and natural gas properties was recorded for the years ended December 31, 2018 and 2017. For 2016, the impairment charges affected the Company’s reported net income but did not reduce its cash flow. In addition to commodity prices, the Company’s production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine its actual ceiling test calculation and impairment analysis in future periods.

At December 31, 2018, there was $68.3 million in exploration costs and development costs and $54.9 million in capitalized interest that are not subject to depletion. At December 31, 2017, there were $26.0 million exploration costs and development costs and $22.1 million capitalized interest that are not subject to depletion.

7. ASSET RETIREMENT OBLIGATIONS

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

	Year Ended December 31,
	2018				2017				2016
	(in thousands)
Asset retirement obligations, beginning of period	$	21,285			$	17,422			$	12,711
Additional liabilities incurred	2,843				1,526				637
Liabilities acquired	111,197				2,432				3,696
Liabilities settled	(1,788		)		(1,555		)		(711		)
Accretion expense	2,132				1,391				1,064
Revisions in estimated liabilities	572				69				25
Asset retirement obligations, end of period	136,241				21,285				17,422
Less current portion	60				1,163				1,288
Asset retirement obligations - long-term	$	136,181			$	20,122			$	16,134

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.

8. EQUITY METHOD INVESTMENTS

In October 2014, the Company obtained a 25% interest in HMW Fluid Management 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. During the year ended December 31, 2017, the Company invested $0.2 million in HMW LLC and recorded income of $0.7 million, which was the Company’s share of HMW Fluid Management LLC’s net income, bringing its total investment to $7.2 million at December 31, 2017. 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 undivided interest in the salt water disposal assets owned by HMW LLC as of January 1, 2018. 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.

9. DEBT

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

F-27

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

	December 31,
	2018				2017
	(in thousands)
4.625% Notes due 2021(1)	400,000				—
7.320% Medium-term Notes, Series A, due 2022(1)	20,000				—
4.750 % Senior Notes due 2024	1,250,000				500,000
5.375 % Senior Notes due 2025	800,000				500,000
7.350% Medium-term Notes, Series A, due 2027(1)	10,000				—
7.125% Medium-term Notes, Series B, due 2028(1)	100,000				—
Unamortized debt issuance costs	(26,645		)		(13,153		)
Unamortized premium costs	10,483				—
Revolving credit facility	1,489,500				397,000
Partnership revolving credit facility	411,000				93,500
Total long-term debt	$	4,464,338			$	1,477,347

(1)	At the effective time of the Merger, Energen became a wholly owned subsidiary of the Company and remained the issuer of these notes (the “Energen Notes”).

Diamondback Notes

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 “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 the Company’s existing and future restricted subsidiaries that guarantee its 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 the Partnership, the General Partner, Viper Energy Partners LLC or Rattler Midstream Operating 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”), which together with existing Senior Notes are referred to as the 2024 Senior 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 used 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 at a price equal to 100% of the principal amount of

F-28

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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, the Company 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.

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 “existing 2025 Senior Notes”). The existing 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 existing 2025 Senior Notes, provided, however, that the existing 2025 Senior Notes are not guaranteed by the Partnership, the General Partner, Viper Energy Partners LLC or Rattler Midstream Operating 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”), which together with the existing 2025 Senior Notes are referred to as the 2025 Senior 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 Senior Notes were issued under an indenture, dated as of December 20, 2016, among the Company, the guarantors party thereto and Wells Fargo Bank, as the trustee (the “2025 Indenture”). 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 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 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, the Company 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, the Company 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.

F-29

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Energen Notes

At the effective time of the Merger, Energen became the Company’s wholly owned subsidiary and remained the issuer of an aggregate principal amount of $530.0 million of the Energen Notes, issued under an indenture dated September 1, 1996 with The Bank of New York as Trustee (the “Energen Indenture”). The Energen Notes consist of: (1) $400.0 million aggregate principal amount of 4.625% senior notes due on September 1, 2021, (2) $100.0 million of 7.125% notes due on February 15, 2028, (3) $20.0 million of 7.32% notes due on July 28, 2022, and (4) $10.0 million of 7.35% notes due on July 28, 2027.

The Energen Notes are the senior unsecured obligations of Energen and, post-merger, Energen, as a wholly owned subsidiary of the Company, continues to be the sole issuer and obligor under the Energen Notes. The Energen Notes rank equally in right of payment with all other senior unsecured indebtedness of Energen, including any unsecured guaranties by Energen of the Company’s indebtedness and are effectively subordinated to Energen’s senior secured indebtedness, including Energen’s secured guaranty of all borrowings and other obligations under the Company’s revolving credit facility, to the extent of the value of the collateral securing such indebtedness.

The Energen Indenture contains certain covenants that, subject to certain exceptions and qualifications, limit Energen’s ability to incur or suffer to exist liens, to enter into sale and leaseback transactions, to consolidate with or merge into any other entity, and to convey, transfer or lease its properties and assets substantially as an entirety to any person or entity. The Energen Indenture not include a restriction on the payment of dividends.

On November 29, 2018, Energen guaranteed the Company’s indebtedness under its credit facility and granted a lien on certain of its assets to secure such indebtedness, and on December 21, 2018, Energen’s subsidiaries guaranteed the Company’s indebtedness under its credit agreement and granted liens on certain of their assets to secure such indebtedness. As a result of such guarantees, under the terms of the 2024 Indenture and the 2025 Indenture, Energen also guaranteed the 2024 Senior Notes and the 2025 Senior Notes.

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, 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 each may request up to two interim redeterminations of the borrowing base during any 12-month period. As of December 31, 2018, the borrowing base was set at $2.65 billion, the Company had elected a commitment amount of $2.0 billion and the Company had $1.5 billion of outstanding borrowings under the revolving credit facility.

Diamondback O&G LLC is the borrower under the credit agreement. As of December 31, 2018, the credit agreement is guaranteed by the Company, Diamondback E&P LLC, Rattler Midstream Operating LLC (formerly known as Rattler Midstream LLC) and Energen and its subsidiaries 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

F-30

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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 December 31, 2018 and 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 $555.0 million, subject to scheduled semi-annual and other elective 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 December 31, 2018, the borrowing base was set at $555.0 million, and the Partnership had $411.0 million of outstanding borrowings and $144.0 million available for future borrowings under its revolving credit facility.

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

F-31

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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.

As of December 31, 2018 and 2017, the Partnership 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 Partnership’s 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%. As of December 31, 2018, CEMOF had not funded any amounts.

Interest expense

The following amounts have been incurred and charged to interest expense for the years ended December 31, 2018, 2017 and 2016:

	Year Ended December 31,
	2018				2017				2016
	(in thousands)
Interest expense	$	110,252			$	60,671			$	39,642
Less capitalized interest	(32,812		)		(22,097		)		—
Other fees and expenses	10,403				2,160				1,426
Total interest expense	$	87,843			$	40,734			$	41,068

F-32

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

10. CAPITAL STOCK AND EARNINGS PER SHARE

Diamondback did not complete any equity offerings during the years ended December 31, 2018 and 2017. Diamondback completed the following equity offerings during the year ended December 31, 2016:

Date	Number of Shares of Common Stock Sold	Number of Shares of Common Stock Issued to Underwriters		Price per Share Sold to Underwriters			Proceeds Received by the Company
January 2016	4,600,000	600,000		$	55.33		$	254,518
July 2016	6,325,000	825,000		$	87.24		$	551,777
December 2016	12,075,000	1,575,000		$	95.3025		$	1,150,828

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.

F-33

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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

	Year Ended December 31,
	2018				2017				2016
	(in thousands, except per share amount)
Net income (loss) attributable to common stock	$	845,672			$	482,261			$	(165,034	)
Weighted average common shares outstanding
Basic weighted average common units outstanding	104,622				97,458				75,077
Effect of dilutive securities:
Potential common shares issuable	307				230				—
Diluted weighted average common shares outstanding	104,929				97,688				75,077
Basic net income attributable to common stock	$	8.09			$	4.95			$	(2.20	)
Diluted net income attributable to common stock	$	8.06			$	4.94			$	(2.20	)

The Company had the following shares that were excluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive for the periods presented but could potentially dilute basic earnings per share in future periods:

	Year Ended December 31,
	2018			2017			2016
	(in thousands)
Restricted stock units	14			46			244

11. EQUITY-BASED COMPENSATION

On October 10, 2012, the Board of Directors approved the Diamondback Energy, Inc. 2012 Equity Incentive Plan (the “2012 Plan”), which is intended to provide eligible employees with equity-based incentives. The 2012 Plan provides for the granting of incentive stock options, nonstatutory stock options, restricted awards (restricted stock and restricted stock units), performance awards, and stock appreciation rights, or any combination of the foregoing. A total of 2,276,548 shares of the Company’s common stock has been reserved for issuance pursuant to this plan.

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

	Year Ended December 31,
	2018				2017				2016
	(In thousands)
General and administrative expenses	$	26,764			$	25,537			$	26,453
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	10,034				8,641				7,079

On June 17, 2014, in connection with the Viper Offering, the Board of Directors of the General Partner adopted the Viper Energy Partners LP Long Term Incentive Plan (“Viper LTIP”), effective June 17, 2014, for employees, officers, consultants and directors of the General Partner and any of its affiliates, including Diamondback, who perform services for the Partnership. The Viper LTIP provides for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards. A total of 8,967,545 common units has been reserved for issuance pursuant to the Viper LTIP. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The Viper LTIP is administered by the Board of Directors of the General Partner or a committee thereof.

F-34

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Restricted Stock Units

Under the Equity Plan, approved by the Board of Directors, the Company is authorized to issue restricted stock and restricted stock units to eligible employees. The Company estimates the fair values of restricted stock awards and units as the closing price of the Company’s common stock on the grant date of the award, which is expensed over the applicable vesting period.

The following table presents the Company’s restricted stock units activity under the Equity Plan during the year ended December 31, 2018:

	Restricted Stock Awards & Units			Weighted Average Grant-Date Fair Value
Unvested at December 31, 2017	243,577			$	90.88
Granted(1)	292,842			$	120.30
Vested	(199,827	)		$	92.50
Forfeited	(12,368	)		$	102.41
Unvested at December 31, 2018	324,224			$	116.01

(1)	Includes 107,472 replacement awards granted in connection with the closing of the Energen merger on November 29, 2018.

The aggregate fair value of restricted stock units that vested during the year ended December 31, 2018, 2017 and 2016 was $18.5 million, $14.8 million and $12.5 million, respectively. As of December 31, 2018, the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $21.2 million. Such cost is expected to be recognized over a weighted-average period of 1.5 years.

Performance-Based Restricted Stock Units

To provide long-term incentives for the executive officers to deliver competitive returns to the Company’s stockholders, the Company has granted performance-based restricted stock units to eligible employees. The ultimate number of shares awarded from these conditional restricted stock units is based upon measurement of total stockholder return of the Company’s common stock (“TSR”) as compared to a designated peer group during a three-year performance period.

In February 2016, eligible employees received performance restricted stock unit awards totaling 174,325 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, 2016 to December 31, 2017 and vested at December 31, 2017. Eligible employees received additional performance restricted stock unit awards totaling 87,163 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, 2016 to December 31, 2018 and vested at December 31, 2018.

In February 2017, eligible employees received performance restricted stock unit awards totaling 37,440 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, 2017 to December 31, 2018 and vested at December 31, 2018. Eligible employees received additional performance restricted stock unit awards totaling 74,880 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, 2017 to December 31, 2019 and cliff vest at December 31, 2019.

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.

F-35

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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

	2018				2017								2016
	Three-Year Performance Period				Two-Year Performance Period				Three-Year Performance Period				Two-Year Performance Period				Three-Year Performance Period
Grant-date fair value	$	170.45			$	162.13			$	168.73			$	103.41			$	102.35
Risk-free rate	1.99		%		1.27		%		1.59		%		0.86		%		1.10		%
Company volatility	35.90		%		39.32		%		41.14		%		41.91		%		42.16		%

The following table presents the Company’s performance restricted stock unit activity under the Equity Plan for the year ended December 31, 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	(291,860	)		$	81.21
Unvested at December 31, 2018(1)	196,203			$	169.76

(1)	A maximum of 392,406 units could be awarded based upon the Company’s final TSR ranking.

As of December 31, 2018, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $18.5 million. Such cost is expected to be recognized over a weighted-average period of 1.0 years.

Stock Appreciation Rights

In connection with the Energen merger, each outstanding stock appreciation right in respect of Energen common stock that was outstanding immediately prior to the effective time of the merger was converted into a fully vested stock appreciation right in respect of (i) that number of whole shares of Diamondback common stock (rounded down to the nearest whole share) equal to the product of (A) the total number of shares of Energen common stock subject to such stock appreciation right immediately prior to the effective time of the merger multiplied by (B) the exchange ratio, (ii) at an exercise price per share of Diamondback common stock (rounded up to the nearest whole cent) equal to the quotient of (A) the exercise price per share of Energen common stock of such stock appreciation right immediately prior to the effective time of the merger divided by (B) the exchange ratio. These awards have a three-year requisite service period.

A summary of stock appreciation rights activity as of December 31, 2018, and transactions during the month ended December 31, 2018 are presented below:

	Shares			Weighted Average Exercise Price
Outstanding at November 29,2018	—			$	—
Granted	57,721			22.12
Outstanding at December 31, 2018	57,721			$	22.12

Stock Options

In connection with the Energen Merger, each option to purchase shares of Energen common stock that was outstanding immediately prior to the effective time of the merger was converted into a fully vested option to purchase (i) that number of whole shares of Diamondback common stock (rounded down to the nearest whole share) equal to the product of (A) the total number of shares of Energen common stock subject to such option immediately prior to the effective time of the merger multiplied

F-36

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

by (B) the exchange ratio, (ii) at an exercise price per share of Diamondback common stock (rounded up to the nearest whole cent) equal to the quotient of (A) the exercise price per share of Energen common stock of such option immediately prior to the effective time divided by (B) the exchange ratio. The exercise price of stock options granted may not be less than the market value of the stock at the date of grant.

The Company estimates the fair values of stock options granted using a Black-Scholes option valuation model, which requires the Company to make several assumptions. The expected term of options granted was determined based on the contractual term of the awards at effective time of the merger. The risk-free interest rate is based on the U.S. treasury yield curve rate for the expected term of the option at the date of grant. All such amounts represent the weighted-average amounts for each year.

				Weighted Average
				Exercise				Remaining		Intrinsic
	Options			Price				Term		Value
								(in years)		(in thousands)
Outstanding at November 29, 2018	—			$	—
Granted(1)	332,387			$	95.04
Outstanding at December 31, 2018	332,387			$	95.04			2.82		$	14,088
Vested and Expected to vest at December 31, 2018	332,387			$	95.04			2.82		$	14,088
Exercisable at December 31, 2018	332,387			$	95.04			2.82		$	14,088

(1)Conversion of stock options assumed in connection with the Energen Merger.

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 year ended December 31, 2018:

	Phantom Units			Weighted Average Grant-Date Fair Value
Unvested at December 31, 2017	105,439			$	17.10
Granted	127,402			$	25.54
Vested	(102,811	)		$	19.23
Forfeited	(4,977	)		$	29.71
Unvested at December 31, 2018	125,053			$	23.44

The aggregate fair value of phantom units that vested during the year ended December 31, 2018 was $2.0 million. As of December 31, 2018, the unrecognized compensation cost related to unvested phantom units was $1.6 million. Such cost is expected to be recognized over a weighted-average period of 0.98 years.

Partnership Unit Options

In accordance with the Viper LTIP, the exercise price of unit options granted may not be less than the market value of the common units at the date of grant. The units issued under the Viper LTIP will consist of new common units of the Partnership. On June 17, 2014, the Board of Directors of the General Partner granted 2,500,000 unit options to the executive officers of the General Partner. The unit options vested approximately 33% ratably on each of the first three anniversaries of the date of grant or earlier upon a change of control (as defined in the Viper LTIP). All outstanding unit options were amended effective November 29, 2016 to provide that vested unit options would become exercisable upon the earlier to occur of (i) the “Exercise Window Period” beginning on the third anniversary of the date of grant and ending on December 31, 2017, or (ii) the “Change of Control Exercise Period” beginning ten days before and ending on the date a change of control occurs (the earlier occurring of such

F-37

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

events, the “Exercise Period”). At any time within the Exercise Period, if a participant attempted to exercise a vested unit option and the fair market value per unit as of such date was less than the exercise price per option unit, the vested unit option would not be exercisable. At the end of the Exercise Period, any vested unit option that was not exercisable or that had not been exercised would automatically terminate and become null and void.

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

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

The following table presents the unit option activity under the Viper LTIP for the year ended December 31, 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 December 31, 2018	—			$	—			0.00		$	—

The aggregate intrinsic value of unit options that were exercised during the year ended December 31, 2018 were $0.2 million.

12. ENERGEN EMPLOYEE BENEFIT PLANS

Plan Terminations: Energen terminated its qualified defined benefit pension plan on January 31, 2015 and distributed benefits in December 2015. In February 2018, Energen received notice that the Pension Benefit Guaranty Corporation had completed its audit of the termination of the pension plan and of the distribution of plan assets noting no exceptions.

Energen’s non-qualified supplemental retirement plans were terminated effective December 31, 2014. Distributions under the plans were completed during the first quarter of 2016. The Company will not make any additional benefit payments with respect to the termination of the non-qualified supplemental retirement plans.

F-38

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Benefit Obligations: The following tables set forth the funded status of Energen’s postretirement health care and life insurance benefit plans and their reconciliation with the related amounts in the Company’s consolidated financial statements:

	One Month Ended December 31, 2018
	(in thousands)
Change in Benefit Obligation
Balance as of November 29, 2018	$	5,373
Service cost	1
Interest cost	19
Actuarial gain	(35		)
Plan amendments	—
Curtailment gain	—
Benefits paid	(7		)
Balance at December 31, 2018	$	5,351
Change in Plans' Assets
Fair value of plan assets at November 29, 2018	$	8,317
Actual return (loss) on plan assets	(90		)
Benefits paid	(7		)
Fair value of plan assets at December 31, 2018	$	8,220
Funded status of plans	$	2,869

	One Month Ended December 31, 2018
	(in thousands)
Amounts recognized on consolidated balance sheets:
Noncurrent assets recognized	$	2,869
Amounts recognized to accumulated other comprehensive income:
Prior service credit, net of taxes	$	—
Net actuarial loss, net of taxes	74
Total accumulated other comprehensive income	$	74

F-39

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

The components of net periodic benefit cost were as follows:

	One Month Ended December 31, 2018
	(in thousands)
Postretirement Benefit Plans
Components of net periodic benefit cost:
Service cost	$	1
Interest cost	19
Expected long-term return on assets	(19		)
Prior service cost amortization	—
Actuarial gain amortization	—
Settlement charge	—
Curtailment gain	—
Net periodic (income) expense	$	1

Other changes in plan assets and projected benefit obligations recognized in other comprehensive income were as follows:

	One Month Ended December 31, 2018
	(in thousands)
Postretirement Benefit Plans
Net actuarial (gain) loss experienced during the year	$	74
Net actuarial loss recognized as expense	—
Prior service cost recognized as income	—
Prior service credit during the year	—
Prior service cost amortization	—
Total recognized in other comprehensive income	$	74

The weighted average rate assumptions to determine net periodic benefit costs were as follows:

	One Month Ended December 31, 2018
Postretirement Benefit Plans
Discount rate	4.55	%
Expected long-term return on plan assets	4.55	%

The weighted average assumptions used to determine the postretirement benefit obligations at the measurement date were as follows:

	One Month Ended December 31, 2018
Discount rate	4.55	%

Investment Strategy: For Energen’s postretirement benefit plan assets, Energen employed a total return investment approach whereby a mix of fixed income investments and equities are used to meet future plan obligations on a long-term basis

F-40

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

with a prudent level of risk. Risk tolerance is established through consideration of plan liabilities, plan funded status, corporate financial condition and market conditions.

Energen sought to maintain an appropriate level of diversification to minimize the risk of large losses in a single asset class. Accordingly, plan assets for the postretirement health care and life insurance benefit plan do not have a concentration of assets in a single entity, industry, commodity or class of investment find.

	Target		As of December 31, 2018
Asset category:
Equity securities	21	%	20	%
Debt securities	74	%	76	%
Other	5	%	4	%
Total	100	%	100	%

Plan assets included in the funded status postretirement benefit plans were as follows:

	December 31, 2018
(in thousands)	Level 1			Level 2			Total
United States equities	$	146		$	—		$	146
Global equities	1,461			—			1,461
Fixed income	6,256			—			6,256
Other	357			—			357
Total	$	8,220		$	—		$	8,220

13. RELATED PARTY TRANSACTIONS

Immediately upon the completion of the Company’s initial public offering on October 17, 2012, Wexford beneficially owned approximately 44% of the Company’s outstanding common stock. As of December 31, 2016, Wexford beneficially owned less than 1% of the Company’s outstanding common stock. The Chairman of the Board of Directors of both the Company and the General Partner was a partner at Wexford until his retirement from Wexford effective December 31, 2016. Another partner at Wexford serves as a member of the Board of Directors of the General Partner. Beginning January 1, 2017, Wexford and entities affiliated with Wexford are no longer considered related parties of the Company and any expenses after December 31, 2016 are no longer classified as related party expenses.

Related Party Revenue and Expenses

During the year ended December 31, 2016, the Company paid $3.3 million in lease operating expenses and $2.2 million in general and administrative expenses to related parties. During the year ended December 31, 2016, the Company received $0.2 million in other income from related parties.

Advisory Services Agreement - The Company

The Company entered into an advisory services agreement (the “Advisory Services Agreement”) with Wexford, dated as of October 11, 2012, under which Wexford provides the Company with general financial and strategic advisory services related to the business in return for an annual fee of $0.5 million, plus reasonable out-of-pocket expenses. The Advisory Services Agreement was terminated on November 12, 2018 with an effective date of December 31, 2018. The Company paid $0.5 million during the year ended December 31, 2016 under the Advisory Services Agreement.

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 Advisory Services Agreement was

F-41

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

terminated on November 12, 2018 with an effective date of December 31, 2018. For the years ended December 31, 2018, 2017 and 2016, the Partnership did not pay any amounts under the Advisory Services Agreement.

Midland Leases

Effective May 15, 2011, the Company occupied corporate office space in the Fasken building in Midland, Texas under a lease with an initial term of five years. On November 10, 2014, the lease was amended to extend the term of the lease for an additional 10-year period and to increase the monthly base rent to $94,000 beginning in June 2016, with an increase of approximately 2% annually. On January 31, 2018, Tall City Towers LLC, a subsidiary of the Company, completed its acquisition of the Fasken Center Office Building.

Field Office Lease

The Company leased field office space in Midland, Texas from an unrelated third party from March 1, 2011. On March 1, 2014, the building was purchased by WT Commercial Portfolio, LLC, which is controlled by an affiliate of Wexford. The term of the lease expired on February 28, 2018. The monthly base rent was $11,000 and increased 3% annually on March 1 of each year. During the third quarter of 2014, the Company entered into a sublease with Bison, in which Bison leased the field office space on the same terms as the Company’s lease for the remainder of the lease term. The Company paid rent of $0.2 million during the year ended December 31, 2016. The Company received payments of $0.2 million from Bison in respect of this sublease during the year ended December 31, 2016. During the second quarter of 2017, the sublease between the Company and Bison as well as the original lease between the Company and WT Commercial Portfolio, LLC were terminated.

Lease Bonus - The Partnership

During the year ended December 31, 2018, the Company paid the Partnership $2.5 million in lease bonus payments to extend the term of 13 leases, reflecting an average bonus of $4,149 per acre and $0.6 million in lease bonus payments for one new lease, reflecting an average bonus of $18,002 per acre. During the year ended December 31, 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. During the year ended December 31, 2016, the Company paid the Partnership $0.3 million in lease bonus payments to extend the term of six leases, reflecting an average bonus of $1,371 per acre.

14. INCOME TAXES

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The Company is subject to corporate income taxes and the Texas margin tax. The Company and its subsidiaries, other than the Partnership and the Operating Company, file a federal corporate income tax return on a consolidated basis. As discussed further below, the Partnership is a taxable entity for federal income tax purposes effective May 10, 2018, and as such files a federal corporate income tax return including the activity of its investment in the Operating Company. The Partnership’s provision for income taxes is included in the Company’s consolidated income tax provision and, to the extent applicable, in net income attributable to the non-controlling interest.

The Tax Cuts and Jobs Act, a historic reform of the U.S. federal income tax statutes, was enacted on December 22, 2017. Among other significant features, the Tax Cut and Jobs Act reduces the maximum US federal corporate income tax rate from 35% to 21%, preserves long-standing upstream oil and gas tax provisions such as immediate deduction of intangible drilling costs, allows for immediate expensing of capital expenditures for tangible personal property for a period of time, modifies the provisions related to the limitations on deductions for executive compensation of publicly traded corporations, and enacts new limitations regarding the deductibility of interest expense.

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.

To account for the effects of the Tax Cut and Jobs Act, the Company remeasured its deferred tax assets and liabilities based on the federal income and state income tax rates at which they are now expected to reverse, which is generally a federal income tax rate of 21%. The enacted rate change resulted in a non-cash decrease of approximately $67.9 million to the Company’s income tax provision for the period ended December 31, 2017 and a corresponding reduction to the Company’s net noncurrent

F-42

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

deferred tax liability balance as of December 31, 2017. At December 31, 2018, the Company completed its accounting for all of the enactment-date income tax effects of the Tax Cuts and Jobs Act and has not made any adjustments to the provisional amounts recorded December 31, 2017.

The components of the Company’s consolidated provision for income taxes for the years ended December 31, 2018, 2017 and 2016 are as follows:

	Year Ended December 31,
	2018				2017				2016
	(In thousands)
Current income tax provision (benefit):
Federal	$	4			$	—			$	—
State	(999		)		999				192
Total current income tax provision	(995		)		999				192
Deferred income tax provision (benefit):
Federal	161,354				(21,720		)		(579		)
State	8,003				1,153				579
Total deferred income tax provision (benefit)	169,357				(20,567		)		—
Total provision for (benefit from) income taxes	$	168,362			$	(19,568	)		$	192

A reconciliation of the statutory federal income tax amount to the recorded expense is as follows:

	Year Ended December 31,
	2018				2017				2016
	(In thousands)
Income tax expense (benefit) at the federal statutory rate(1)	$	233,784			$	174,016			$	(57,694	)
Impact of nontaxable noncontrolling interest	(5,107		)		(12,073		)		—
Income tax benefit relating to change in statutory tax rate	—				(67,938		)		—
State income tax expense (benefit), net of federal tax effect	7,769				3,413				770
Non-deductible compensation	4,887				13,492				3,990
Change in valuation allowance	150				(127,485		)		53,336
Deferred taxes related to change in the Partnership's tax status	(72,787		)		—				—
Other, net	(334		)		(2,993		)		(210		)
Provision for (benefit from) income taxes	$	168,362			$	(19,568	)		$	192

(1)	The federal statutory rates for the years ended December 31, 2018, 2017 and 2016 were 21%, 35% and 35%, respectively.

F-43

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

The components of the Company’s deferred tax assets and liabilities as of December 31, 2018 and 2017 are as follows:

	December 31,
	2018				2017
	(In thousands)
Deferred tax assets
Net operating loss and other carryforwards	154,408				74,997
Derivative instruments	—				22,918
Stock based compensation	7,021				942
The Partnership's investment in the Operating Company	94,468				—
Other	8,634				2,464
Deferred tax assets	264,531				101,321
Valuation allowance	(13,932		)		(104		)
Deferred tax assets, net of valuation allowance	250,599				101,217
Deferred tax liabilities
Oil and natural gas properties and equipment	1,825,237				202,997
Midstream assets	66,728				6,268
Derivative instruments	46,496				—
Total deferred tax liabilities	1,938,461				209,265
Net deferred tax liabilities	$	1,687,862			$	108,048

The Company had net deferred tax liabilities of approximately $1,687.9 million and $108.0 million at December 31, 2018 and 2017, respectively. On November 29, 2018, the Company completed its acquisition of Energen. For federal income tax purposes, the acquisition was a tax-free merger whereby the Company’s tax basis in Energen assets and liabilities was unaffected by the acquisition. As of December 31, 2018, the Company recorded a deferred tax liability of $1,402.8 million associated with the acquired assets, which includes deferred tax assets related to tax attributes acquired from Energen. The acquired tax attributes include federal net operating loss and credit carryforwards of approximately $13.5 million which are subject to an annual limitation under Internal Revenue Code Section 382. The Company expects that these tax attributes will be fully utilized prior to expiration. In addition, acquired tax attributes include state net operating loss carryforwards of approximately $13.6 million for which a valuation allowance has been provided as discussed further below, and $75.7 million of minimum tax credit carryforward which the Company anticipates will be fully refundable over the 2018 through 2021 tax years. The Company’s minimum tax credits, including those acquired from Energen, are classified as $38.2 million current and $38.2 million noncurrent income tax receivables on the balance sheet.

The Company incurred a tax net operating loss ("NOL") in the current year due principally to the ability to expense certain intangible drilling and development costs under current law. There is no tax refund available to the Company, nor is there any current income tax payable. At December 31, 2018, the Company had approximately $395.1 million of federal NOLs expiring in 2032 through 2037 and $172.7 million of federal NOLs with an indefinite carryforward life, including NOLs acquired from Energen. The Company principally operates in the state of Texas and is subject to Texas Margin Tax, which currently does not include an NOL carryover provision. The Company believes that Section 382 of the Internal Revenue Code of 1986, as amended, which relates to tax attribute limitations upon the 50% or greater change of ownership of an entity during any three-year look back period, will not have an adverse effect on future NOL usage.

As of December 31, 2018, the Company has a valuation allowance of $13.9 million for certain state NOL carryforwards, including $13.6 million acquired from Energen, which the Company does not believe are realizable as it does not anticipate future operations in those states. Management’s assessment at each balance sheet date included consideration of all available positive and negative evidence including the anticipated timing of reversal of deferred tax liabilities. Management believes that the balance of the Company’s NOLs are realizable to the extent of future taxable income primarily related to the excess of book carrying value of properties over their respective tax bases. As a result of management’s assessment, in the quarter ended December 31, 2017, the Company had removed its valuation allowance against its federal NOLs and other federal deferred tax assets in order to state its deferred assets and liabilities at the amount more likely than not to be realized. As of December 31, 2018, management determined that it is more likely than not that the Company will realize its remaining deferred tax assets.

F-44

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

As discussed further in Note 4—Viper Energy Partners LP, 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 December 31, 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.

At December 31, 2018, the Company’s net deferred tax liabilities include a deferred tax asset of approximately $94.5 million related to the Partnership’s investment in the Operating Company, approximately $72.8 million of which was recorded as a result of the Partnership’s change in tax status. Under federal income tax provisions applicable to the Partnership’s change in tax status, the Partnership’s basis for federal income tax purposes in its interest in the Operating Company consists primarily of the sum of the Partnership’s unitholders’ tax bases in their interests in the Partnership on the date of the tax status change. Under federal income tax reporting rules applicable to publicly traded partnerships (“PTPs”), partner information, including partner tax basis information, is required to be provided to the Partnership, but not in sufficient time for the Partnership to finalize its determination of the resultant tax basis in the Operating Company. The deferred tax asset reflected above represents the Partnership’s best estimate of the difference between its tax basis and its basis for financial accounting purposes in the Operating Company. The estimate is subject to revision when the Partnership finalizes its federal income tax computations for 2018. The Partnership has federal net operating loss carryforwards of approximately $8.3 million which may be carried forward indefinitely to offset future taxable income.

The following table sets forth changes in the Company’s unrecognized tax benefits:

	December 31, 2018
	(in thousands)
Balance at beginning of year	—
Increase resulting from tax positions acquired	7,111
Increase resulting from prior period tax positions	4
Increase resulting from current period tax positions	—
Balance at end of year	7,115
Less: Effects of temporary items	(4,666	)
Total that, if recognized, would impact the effective income tax rate as of the end of the year	2,449

The Company’s federal and state income tax returns for 2012 through the current tax year remain open and subject to examination by the IRS and major state taxing jurisdictions. Energen is currently under IRS examination of its federal consolidated income tax returns for 2014 and 2016. Accordingly, it is reasonably possible that significant changes to the reserve for uncertain tax positions may occur as a result of various audits and the expiration of the statute of limitations. Although the timing and outcome of tax examinations is highly uncertain, the Company does not expect the change in unrecognized tax benefit within the next 12 months would have a material impact to the financial statements.

15. DERIVATIVES

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

The Company has used 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 and fixed price basis contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. The Company

F-45

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

has fixed price basis swaps for the spread between the WTI Magellan East Houston oil price and the WTI Cushing oil price and for the spread between the Henry Hub natural gas price and the Waha Hub natural gas 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 ICE Brent pricing, and with natural gas derivative settlements based on New York Mercantile Exchange Henry Hub pricing and Waha Hub pricing and liquids derivative settlements based on Mt. Belvieu pricing.

By using derivative instruments to economically 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 December 31, 2018, the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed:

	2019						2020
	Volume (Bbls/MMBtu)		Fixed Price Swap (per Bbl/MMBtu)				Volume (Bbls/MMBtu)		Fixed Price Swap (per Bbl/MMBtu)
Oil Swaps - WTI Cushing	10,638,000		$	61.07			0		$	—
Oil Swaps - WTI Magellan East Houston	1,270,000		$	72.39			0		$	—
Oil Swaps - BRENT	2,005,000		$	68.02			0		$	—
Oil Basis Swaps - WTI Cushing	17,012,000		$	(5.56	)		15,120,000		$	(1.21	)
Natural Gas Swaps - Henry Hub	25,550,000		$	3.06			0		$	—
Natural Gas Basis Swaps - Waha Hub	18,250,000		$	(1.60	)		0		$	—
Natural Gas Liquid Swaps - Mont Belvieu	2,760,000		$	27.30			0		$	—

	January 2019 - December 2019
Oil Three-Way Collars	WTI Cushing				Brent				WTI Magellan East Houston
Volume (Bbls)	7,570,000				2,000,000				994,000
Short put price (per Bbl)	$	38.10			$	55.00			$	56.82
Floor price (per Bbl)	$	48.10			$	65.00			$	66.82
Ceiling price (per Bbl)	$	63.70			$	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.

F-46

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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 December 31, 2018 and 2017.

	December 31,
	2018				2017
	(in thousands)
Gross amounts of assets presented in the Consolidated Balance Sheet	$	230,527			$	531
Net amounts of assets presented in the Consolidated Balance Sheet	230,527				531
Gross amounts of liabilities presented in the Consolidated Balance Sheet	15,192				106,670
Net amounts of liabilities presented in the Consolidated Balance Sheet	$	15,192			$	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:

	December 31,
	2018				2017
	(in thousands)
Current assets: derivative instruments	$	230,527			$	531
Noncurrent assets: derivative instruments	—				—
Total assets	$	230,527			$	531
Current liabilities: derivative instruments	$	—			$	100,367
Noncurrent liabilities: derivative instruments	15,192				6,303
Total liabilities	$	15,192			$	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:

	Year Ended December 31,
	2018				2017				2016
	(in thousands)
Change in fair value of open non-hedge derivative instruments	$	221,732			$	(84,240	)		$	(26,522	)
Gain (loss) on settlement of non-hedge derivative instruments	(120,433		)		6,728				1,177
Gain (loss) on derivative instruments	$	101,299			$	(77,512	)		$	(25,345	)

16. 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.

F-47

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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. 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 December 31, 2018 and 2017:

	December 31, 2018										December 31, 2017
	Level 1			Level 2			Level 3				Level 1			Level 2			Level 3
	(in thousands)
Assets:
Investment	$	14,525		$	—		$	—			$	—		$	—		$	—
Fixed price swaps	$	—		$	215,335		$	—			$	—		$	—		$	—
Liabilities:
Fixed price swaps	$	—		$	—		$	—			$	—		$	(106,139	)	$	—

F-48

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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:

	December 31, 2018								December 31, 2017
	Carrying								Carrying
	Amount				Fair Value				Amount				Fair Value
	(in thousands)
Debt:
Revolving credit facility	$	1,489,500			$	1,489,500			$	397,000			$	397,000
4.625% Notes due 2021(1)	400,000				393,240				—				—
7.320% Medium-term Notes, Series A, due 2022(1)	20,000				20,780				—				—
4.750% Senior Notes due 2024	1,250,000				1,203,900				500,000				501,855
5.375% Senior Notes due 2025	800,000				782,000				500,000				515,000
7.350% Medium-term Notes, Series A, due 2027(1)	10,000				10,479				—				—
7.125% Medium-term Notes, Series B, due 2028(1)	100,000				102,329				—				—
Partnership revolving credit facility	411,000				411,000				93,500				93,500

(1) The Company assumed these notes (“Energen Notes”) in connection with the closing of the Energen Merger.

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 and the Energen Notes was determined using the December 31, 2018 quoted market price, a Level 1 classification in the fair value hierarchy.

17. 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.

Lease Commitments

The following is a schedule of minimum future lease payments with commitments that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 2018:

Year Ending December 31,	Drilling Rig Commitments				Sand Supply Agreement				Office and Equipment Leases
	(in thousands)
2019	$	18,976			9,000				$	9,019
2020	414				9,000				3,827
2021	—				9,000				1,452
2022	—				9,000				583
2023	—				2,250				—
Thereafter	—				—				—
Total	$	19,390			$	38,250			$	14,881

The Company leases office space in Oklahoma City, Oklahoma from an unrelated third party. Amounts prior to January 1, 2018, include rent expense related to the Company’s corporate office located in the Fasken Center in Midland, Texas. On January 31, 2018, the Company completed its acquisition of the Fasken Center office buildings.

F-49

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

The following table presents rent expense for the years ended December 31, 2018, 2017 and 2016.

	Year ended December 31,
	2018				2017				2016
	(in thousands)
Rent Expense	$	751			$	2,412			$	1,961

Drilling contracts

As of December 31, 2018, the Company had entered into drilling rig contracts with various third parties in the ordinary course of business to ensure rig availability to complete the Company’s drilling projects. These commitments are not recorded in the accompanying consolidated balance sheets. Future commitments as of December 31, 2018 total approximately $19.4 million.

Agreement with Trafigura Trading LLC

The Company has entered into a firm commitment oil purchase agreement with Trafigura Trading LLC (“Trafigura”), in which it agreed to sell and deliver an average of 25,000 barrels per day of Midland Sweet Crude Oil (WTI) to Trafigura during the term of the agreement. Under this agreement, which has a seven-year term beginning on August 1, 2018, the price per barrel of oil paid to the Company by Trafigura is based on the average of the published settlement quotations for NYMEX CMA, as adjusted for different delivery methods and periods. If during the term of the agreement the Company fails to deliver the required quantities of oil for any month other than for specified force majeure events, the Company has agreed to pay Trafigura a deficiency payment equal to any unfavorable difference between the contract price and the spot price, multiplied by the deficiency volume.

Agreement with Shell Trading (US) Company

The Company was a party to a five-year oil purchase agreement with Shell Trading (US) Company that expired on September 30, 2018. In December 2018, the Company entered into a new oil purchase agreement with Shell Trading (US) Company in which Shell Trading (US) Company agreed to transport crude petroleum it purchases from the Company over the Epic Crude Pipeline, with which the Company has an agreement for the transportation of a maximum quantity of 50,000 barrels of crude petroleum per day. The Company’s agreement with Shell Trading (US) Company provides for different purchase obligations during the pre-commencement and service commencement periods for the Epic Crude Pipeline, and provides for a three-year term beginning on the service commencement date for the Epic Crude Pipeline. Shell Trading (US) Company has the option to extend its purchase obligations for up to two one-year terms. The Company’s delivery obligations during the pre-commencement terms range from 30,000 to 40,000 barrels per day and, during the full service term, its maximum delivery obligation is 50,000 barrels per day, determined based on the amount of crude petroleum the Company is obligated to transport on the EPIC Crude Pipeline under its transportation agreement with such pipeline. During different pre-commencement periods, Shell Trading (US) Company has agreed to pay the Company the price per barrel of oil based on the arithmetic average of the daily settlement price for “Light Sweet Crude Oil” Prompt Month future contracts reported by the NYMEX over the one-month period, subject to agreed adjustments, or a specified price. During the full service term, the price per barrel of oil payable by Shell Trading (US) Company to the Company is subject to negotiation.

Agreement with Vitol Inc.

The Company has also entered into an oil purchase agreement with Vitol Inc. (“Vitol”). The agreement provides for different delivery obligations before and after the Gray Oak Pipeline is in full service, ranging from 23,750 barrels per day during the period from November 1, 2018 to September 30, 2019, to 50,000 barrels per day (up to a maximum of 100,000 barrels per day) once the Gray Oak Pipeline is in full service, determined based on the amount of crude petroleum the Company is obligated to transport on the Gray Oak Pipeline under its transportation agreement with such pipeline. The agreement with Vitol provides for a seven-year term commencing on the date when the Gray Oak Pipeline is in full service. The agreement contemplates variable prices depending on the delivery periods specified in the agreement. The agreement also provides for a five-year term commencing on the date the EPIC Crude Pipeline is ready to perform transportation services from the EPIC Midway Terminal, during which the Company agreed to sell crude petroleum to Vitol opportunistically at negotiated prices. If the Company fails to deliver any required quantities of oil for any month other than for specified force majeure events, it has agreed to pay Vitol a deficiency payment equal to any unfavorable difference between the contract price and the price paid by Vitol to third parties to replace the deficiency quantity, multiplied by the deficiency quantity, subject to certain other adjustments.

F-50

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Defined contribution plan

The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at their date of hire. The plan allows eligible employees to contribute up to 100% of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions of up to 6% of an employee’s compensation and may make additional discretionary contributions for eligible employees. Employer contributions vest immediately. For the years ended December 31, 2018, 2017 and 2016 the Company paid $2.1 million, $1.8 million and $1.2 million, respectively, in contributions to the plan.

18. SUBSEQUENT EVENTS

Commodity Contracts

Subsequent to December 31, 2018, the Company entered into new fixed price 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.

F-51

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

The following tables present the derivative contracts entered into by the Company subsequent to December 31, 2018. When aggregating multiple contracts, the weighted average contract price is disclosed.

	Volume (Bbls/MMBtu)		Fixed Price Swap (per Bbl/MMBtu)
January 2019 - December 2019
Oil Swaps - WTI Magellan East Houston	368,000		$	59.15
Oil Swaps - BRENT	275,000		$	61.90
Oil Basis Swaps - WTI Cushing	182,000		$	(4.15	)
Oil Basis Swaps - WTI Midland	364,000		$	(2.68	)
Natural Gas Swaps - Waha Hub	6,680,000		$	(1.47	)

	January 2019 - June 2019				January 2020 - June 2020
Oil Three-Way Collars	Brent				Brent
Volume (Bbls)	368,000				732,000
Short put price (per Bbl)	$	50.00			$	50.00
Floor price (per Bbl)	$	60.00			$	60.00
Ceiling price (per Bbl)	$	69.43			$	73.90

On February 1, 2019, Rattler LLC obtained a 10% equity interest in the EPIC Crude Pipeline Project, which, once operational, will transport crude oil and NGL across Texas for delivery into the Corpus Christi market. As of February 19, 2019, Rattler LLC has invested $34.1 million in the EPIC project and recorded no income. The EPIC project is anticipated to be operational in the second half of 2019.

On February 15, 2019, Rattler LLC obtained a 10% equity interest in the Gray Oak Pipeline Project, which, once operational, will transport crude oil from the Permian Basin to Corpus Christi on the Texas Gulf Coast. As of February 19, 2019, Rattler LLC has invested $81.3 million in the Gray Oak project and recorded no income. The Gray Oak project is anticipated to be operational in the second half of 2019.

19. GUARANTOR FINANCIAL STATEMENTS

As of December 31, 2018, Diamondback E&P LLC, Diamondback O&G LLC and Energen Corporation and its subsidiaries (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, the Partnership, the General Partner, Viper Energy Partners LLC and Rattler Midstream Operating LLC were designated as Non-Guarantor Subsidiaries. The following presents condensed consolidated financial information for the Company (which for purposes of this Note 19 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.

F-52

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Condensed Consolidated Balance Sheet
December 31, 2018
(In thousands)
									Non–
					Guarantor				Guarantor
	Parent				Subsidiaries				Subsidiaries				Eliminations				Consolidated
Assets
Current assets:
Cash and cash equivalents	$	83,791			$	108,049			$	22,676			$	—			$	214,516
Accounts receivable, net	—				353,238				38,823				—				392,061
Accounts receivable - related party	—				—				3,489				(3,489		)		—
Intercompany receivable	4,468,813				200,795				—				(4,669,608		)		—
Inventories	—				37,570				—				—				37,570
Other current assets	2,583				278,034				257				—				280,874
Total current assets	4,555,187				977,686				65,245				(4,673,097		)		925,021
Property and equipment:
Oil and natural gas properties, at cost, full cost method of accounting	—				20,585,766				1,716,713				(3,297		)		22,299,182
Midstream assets	—				700,295				—				—				700,295
Other property, equipment and land	—				141,275				5,688				—				146,963
Accumulated depletion, depreciation, amortization and impairment	—				(2,513,893		)		(248,296		)		(12,276		)		(2,774,465		)
Net property and equipment	—				18,913,443				1,474,105				(15,573		)		20,371,975
Investment in subsidiaries	11,575,513				112,434				—				(11,687,947		)		—
Investment in real estate, net	—				115,625				—				—				115,625
Deferred tax asset	(213		)		—				96,883				—				96,670
Other assets	344				68,221				17,831				—				86,396
Total assets	$	16,130,831			$	20,187,409			$	1,654,064			$	(16,376,617	)		$	21,595,687
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	—			$	127,979			$	—			$	—			$	127,979
Intercompany payable	—				4,673,097				—				(4,673,097		)		—
Other current liabilities	14,292				871,319				6,022				—				891,633
Total current liabilities	14,292				5,672,395				6,022				(4,673,097		)		1,019,612
Long-term debt	2,035,554				2,017,784				411,000				—				4,464,338
Derivative instruments	—				15,192				—				—				15,192
Asset retirement obligations	—				136,181				—				—				136,181
Deferred income taxes	381,698				1,402,834				—				—				1,784,532
Other long-term liabilities	—				9,570				—				—				9,570
Total liabilities	2,431,544				9,253,956				417,022				(4,673,097		)		7,429,425
Commitments and contingencies
Stockholders’ equity	13,699,287				10,933,453				542,102				(11,475,555		)		13,699,287
Non-controlling interest	—				—				694,940				(227,965		)		466,975
Total equity	13,699,287				10,933,453				1,237,042				(11,703,520		)		14,166,262
Total liabilities and equity	$	16,130,831			$	20,187,409			$	1,654,064			$	(16,376,617	)		$	21,595,687

F-53

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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

F-54

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Condensed Consolidated Statement of Operations
Year Ended December 31, 2018
(In thousands)
										Non–
						Guarantor				Guarantor
	Parent					Subsidiaries				Subsidiaries				Eliminations				Consolidated
Revenues:
Oil sales	$	—				$	1,631,703			$	—			$	246,922			$	1,878,625
Natural gas sales	—					48,070				—				12,976				61,046
Natural gas liquid sales	—					167,346				—				22,763				190,109
Royalty income	—					—				282,661				(282,661		)		—
Lease bonus	—					—				6,029				(3,109		)		2,920
Midstream services	—					34,254				—				—				34,254
Other operating income	—					9,172				130				—				9,302
Total revenues	—					1,890,545				288,820				(3,109		)		2,176,256
Costs and expenses:
Lease operating expenses	—					204,975				—				—				204,975
Production and ad valorem taxes	—					113,613				19,048				—				132,661
Gathering and transportation	—					26,113				—				—				26,113
Midstream services	—					71,878				—				—				71,878
Depreciation, depletion and amortization	—					547,592				58,830				16,617				623,039
General and administrative expenses	28,490					30,569				7,955				(2,460		)		64,554
Merger & integration	18,476					18,355				—				—				36,831
Asset retirement obligation accretion	—					2,132				—				—				2,132
Other operating expense	—					3,285				—				—				3,285
Total costs and expenses	46,966					1,018,512				85,833				14,157				1,165,468
Income (loss) from operations	(46,966		)			872,033				202,987				(17,266		)		1,010,788
Other income (expense)
Interest expense, net	(43,482		)			(29,945		)		(13,849		)		—				(87,276		)
Other income (expense), net	1,463					88,069				1,924				(2,460		)		88,996
Loss on derivative instruments, net	—					101,299				—				—				101,299
Gain on revaluation of investment	—			—		—				(550		)		—				(550		)
Total other income (expense), net	(42,019		)			159,423				(12,475		)		(2,460		)		102,469
Income (loss) before income taxes	(88,985		)			1,031,456				190,512				(19,726		)		1,113,257
Provision for (benefit from) income taxes	240,727					—				(72,365		)		—				168,362
Net income (loss)	(329,712		)			1,031,456				262,877				(19,726		)		944,895
Net income attributable to non-controlling interest	—					—				118,919				(19,696		)		99,223
Net income (loss) attributable to Diamondback Energy, Inc.	$	(329,712	)			$	1,031,456			$	143,958			$	(30	)		$	845,672

F-55

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Condensed Consolidated Statement of Operations
Year Ended December 31, 2017
(In thousands)
									Non–
					Guarantor				Guarantor
	Parent				Subsidiaries				Subsidiaries				Eliminations				Consolidated
Revenues:
Oil sales	$	—			$	903,842			$	—			$	140,175			$	1,044,017
Natural gas sales	—				42,899				—				9,311				52,210
Natural gas liquid sales	—				79,371				—				10,677				90,048
Royalty income	—				—				160,163				(160,163		)		—
Lease bonus	—				—				11,870				(106		)		11,764
Midstream services	—				7,072				—				—				7,072
Total revenues	—				1,033,184				172,033				(106		)		1,205,111
Costs and expenses:
Lease operating expenses	—				126,524				—				—				126,524
Production and ad valorem taxes	—				62,897				10,608				—				73,505
Gathering and transportation	—				12,045				789				—				12,834
Midstream services	—				10,409				—				—				10,409
Depreciation, depletion and amortization	—				281,989				40,519				4,251				326,759
General and administrative expenses	26,776				18,057				6,296				(2,460		)		48,669
Asset retirement obligation accretion	—				1,391				—				—				1,391
Total costs and expenses	26,776				513,312				58,212				1,791				600,091
Income (loss) from operations	(26,776		)		519,872				113,821				(1,897		)		605,020
Other income (expense)
Interest expense, net	(29,925		)		(7,465		)		(3,164		)		—				(40,554		)
Other income (expense), net	1,142				10,732				821				(2,460		)		10,235
Loss on derivative instruments, net	—				(77,512		)		—				—				(77,512		)
Total other expense, net	(28,783		)		(74,245		)		(2,343		)		(2,460		)		(107,831		)
Income (loss) before income taxes	(55,559		)		445,627				111,478				(4,357		)		497,189
Benefit from income taxes	(19,568		)		—				—				—				(19,568		)
Net income (loss)	(35,991		)		445,627				111,478				(4,357		)		516,757
Net income attributable to non-controlling interest	—				—				—				34,496				34,496
Net income (loss) attributable to Diamondback Energy, Inc.	$	(35,991	)		$	445,627			$	111,478			$	(38,853	)		$	482,261

F-56

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Condensed Consolidated Statement of Operations
Year Ended December 31, 2016
(In thousands)
									Non–
					Guarantor				Guarantor
	Parent				Subsidiaries				Subsidiaries				Eliminations				Consolidated
Revenues:
Oil sales	$	—			$	399,007			$	—			$	71,521			$	470,528
Natural gas sales	—				19,399				—				3,107				22,506
Natural gas liquid sales	—				29,864				—				4,209				34,073
Royalty income	—				—				78,837				(78,837		)		—
Lease bonus income	—				—				309				(309		)		—
Total revenues	—				448,270				79,146				(309		)		527,107
Costs and expenses:
Lease operating expenses	—				82,428				—				—				82,428
Production and ad valorem taxes	—				28,912				5,544				—				34,456
Gathering and transportation	—				11,189				415				2				11,606
Depreciation, depletion and amortization	—				151,376				29,820				(3,181		)		178,015
Impairment of oil and natural gas properties	—				198,067				47,469				—				245,536
General and administrative expenses	25,959				11,451				5,209				—				42,619
Asset retirement obligation accretion expense	—				1,064				—				—				1,064
Total costs and expenses	25,959				484,487				88,457				(3,179		)		595,724
Income (loss) from operations	(25,959		)		(36,217		)		(9,311		)		2,870				(68,617		)
Other income (expense)
Interest expense, net	(35,318		)		(2,911		)		(2,455		)		—				(40,684		)
Other income, net	437				2,010				867				(250		)		3,064
Loss on derivative instruments, net	—				(25,345		)		—				—				(25,345		)
Loss on extinguishment of debt	(33,134		)		—				—				—				(33,134		)
Total other expense, net	(68,015		)		(26,246		)		(1,588		)		(250		)		(96,099		)
Income (loss) before income taxes	(93,974		)		(62,463		)		(10,899		)		2,620				(164,716		)
Provision for income taxes	192				—				—				—				192
Net income (loss)	$	(94,166	)		$	(62,463	)		$	(10,899	)		$	2,620			$	(164,908	)
Net income attributable to non-controlling interest	$	—			$	—			$	—			$	126			$	126
Net income (loss) attributable to Diamondback Energy, Inc.	$	(94,166	)		$	(62,463	)		$	(10,899	)		$	2,494			$	(165,034	)

F-57

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Condensed Consolidated Statement of Cash Flows
Year Ended December 31, 2018
(In thousands)
									Non–
					Guarantor				Guarantor
	Parent				Subsidiaries				Subsidiaries				Eliminations				Consolidated
Net cash provided by operating activities	$	(57,960	)		$	1,377,972			$	244,493			$	—			$	1,564,505
Cash flows from investing activities:
Additions to oil and natural gas properties	—				(1,460,509		)		—				—				(1,460,509		)
Additions to midstream assets	—				(204,222		)		—				—				(204,222		)
Purchase of other property, equipment and land	—				(2,153		)		(4,687		)		—				(6,840		)
Acquisition of leasehold interests	—				(1,370,951		)		—				—				(1,370,951		)
Acquisition of mineral interests	—				169,828				(610,131		)		—				(440,303		)
Proceeds from sale of assets	—				79,533				565				—				80,098
Funds held in escrow	—				10,989				—				—				10,989
Purchase of other investments	—				(8		)		—				—				(8		)
Equity investments	—				(612		)		—				—				(612		)
Intercompany transfers	(366,634		)		366,634				—				—				—
Investment in real estate	—				(110,685		)		—				—				(110,685		)
Net cash used in investing activities	(366,634		)		(2,522,156		)		(614,253		)		—				(3,503,043		)
Cash flows from financing activities:
Proceeds from borrowing under credit facility	—				1,960,000				691,500				—				2,651,500
Repayment under credit facility	—				(867,500		)		(374,000		)		—				(1,241,500		)
Repayment of Energen credit facility	—				(559,000		)		—				—				(559,000		)
Proceeds from senior notes	1,062,000				—				—				—				1,062,000
Debt issuance costs	(13,926		)		(10,496		)		(1,039		)		—				(25,461		)
Public offering costs	—				—				(2,652		)		—				(2,652		)
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	155,138				—				—				(155,138		)		—
Unit options exercised	—				—				140				—				140
Repurchased for tax withholdings	(14,460		)		—				—				—				(14,460		)
Dividends to stockholders	(37,313		)		—				—				—				(37,313		)
Other postemployment benefit changes	—				(74		)		—				—				(74		)
Distributions to non-controlling interest	—				—				(253,483		)		155,138				(98,345		)
Intercompany transfers	(696,128		)		695,128				1,000				—				—
Net cash provided by financing activities	454,311				1,218,058				368,239				—				2,040,608
Net increase (decrease) in cash and cash equivalents	29,717				73,874				(1,521		)		—				102,070
Cash and cash equivalents at beginning of period	54,074				34,175				24,197				—				112,446
Cash and cash equivalents at end of period	$	83,791			$	108,049			$	22,676			$	—			$	214,516

F-58

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Condensed Consolidated Statement of Cash Flows
Year Ended December 31, 2017
(In thousands)
									Non–
					Guarantor				Guarantor
	Parent				Subsidiaries				Subsidiaries				Eliminations				Consolidated
Net cash provided by (used in) operating activities	$	(29,470	)		$	778,876			$	139,219			$	—			$	888,625
Cash flows from investing activities:
Additions to oil and natural gas properties	—				(792,599		)		—				—				(792,599		)
Additions to midstream assets	—				(68,139		)		—				—				(68,139		)
Purchase of other property, equipment and land	—				(22,779		)		—				—				(22,779		)
Acquisition of leasehold interests	—				(1,960,591		)		—				—				(1,960,591		)
Acquisition of mineral interests	—				(63,371		)		(344,079		)		—				(407,450		)
Acquisition of midstream assets	—				(50,279		)		—				—				(50,279		)
Proceeds from sale of assets	—				65,656				—				—				65,656
Funds held in escrow	—				104,087				—				—				104,087
Equity investments	—				(188		)		—				—				(188		)
Intercompany transfers	(1,631,078		)		1,631,078				—				—				—
Net cash used in investing activities	(1,631,078		)		(1,157,125		)		(344,079		)		—				(3,132,282		)
Cash flows from financing activities:
Proceeds from borrowing under credit facility	—				475,000				278,500				—				753,500
Repayment under credit facility	—				(78,000		)		(305,500		)		—				(383,500		)
Purchase of subsidiary units by parent	(10,068		)		—				—				10,068				—
Debt issuance costs	(8,326		)		1,289				(2,259		)		—				(9,296		)
Public offering costs	(77		)		—				(433		)		—				(510		)
Proceeds from public offerings	—				—				380,412				(10,068		)		370,344
Distributions from subsidiary	89,509				—				—				(89,509		)		—
Exercise of stock options	358				—				—				—				358
Distributions to non-controlling interest	—				—				(130,876		)		89,509				(41,367		)
Net cash provided by financing activities	71,396				398,289				219,844				—				689,529
Net increase (decrease) in cash and cash equivalents	(1,589,152		)		20,040				14,984				—				(1,554,128		)
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	$	54,074			$	34,175			$	24,197			$	—			$	112,446

F-59

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Condensed Consolidated Statement of Cash Flows
Year Ended December 31, 2016
(In thousands)
									Non–
					Guarantor				Guarantor
	Parent				Subsidiaries				Subsidiaries				Eliminations				Consolidated
Net cash provided by (used in) operating activities	$	(39,894	)		$	303,347			$	68,627			$	—			$	332,080
Cash flows from investing activities:
Additions to oil and natural gas properties	—				(363,087		)		—				—				(363,087		)
Additions to midstream assets	—				(1,188		)		—				—				(1,188		)
Purchase of other property, equipment and land	—				(9,891		)		—				—				(9,891		)
Acquisition of leasehold interests	—				(611,280		)		—				—				(611,280		)
Acquisition of mineral interests	—				—				(205,721		)		—				(205,721		)
Proceeds from sale of assets	—				4,661				—				—				4,661
Funds held in escrow	—				(121,391		)		—				—				(121,391		)
Equity investments	—				(2,345		)		—				—				(2,345		)
Intercompany transfers	(796,053		)		796,053				—				—				—
Net cash used in investing activities	(796,053		)		(308,468		)		(205,721		)		—				(1,310,242		)
Cash flows from financing activities:
Proceeds from borrowing under credit facility	—				—				164,000				—				164,000
Repayment under credit facility	—				(11,000		)		(78,000		)		—				(89,000		)
Proceeds from senior notes	1,000,000				—				—				—				1,000,000
Repayment of senior notes	(450,000		)		—				—				—				(450,000		)
Premium on extinguishment of debt	(26,561		)		—				—				—				(26,561		)
Debt issuance costs	(14,449		)		(172		)		(442		)		—				(15,063		)
Public offering costs	(636		)		—				(546		)		—				(1,182		)
Proceeds from public offerings	1,925,923				—				125,580				—				2,051,503
Distribution from subsidiary	55,250				—				—				(55,250		)		—
Exercise of stock options	498				—				—				—				498
Distribution to non-controlling interest	—				—				(64,824		)		55,250				(9,574		)
Intercompany transfers	(11,000		)		11,000				—				—				—
Net cash provided by (used in) financing activities	2,479,025				(172		)		145,768				—				2,624,621
Net increase (decrease) in cash and cash equivalents	1,643,078				(5,293		)		8,674				—				1,646,459
Cash and cash equivalents at beginning of period	148				19,428				539				—				20,115
Cash and cash equivalents at end of period	$	1,643,226			$	14,135			$	9,213			$	—			$	1,666,574

F-60

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

20. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)

The Company’s oil and natural gas reserves are attributable solely to properties within the United States.

Capitalized oil and natural gas costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows:

	December 31,
	2018				2017
	(In thousands)
Oil and natural gas properties:
Proved properties	$	12,629,205			$	5,126,829
Unproved properties	9,669,977				4,105,865
Total oil and natural gas properties	22,299,182				9,232,694
Accumulated depreciation, depletion, amortization	(1,599,111		)		(1,009,893		)
Accumulated impairment	(1,143,498		)		(1,143,498		)
Net oil and natural gas properties capitalized	$	19,556,573			$	7,079,303

Costs incurred in oil and natural gas activities

Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows:

	Year Ended December 31,
	2018				2017				2016
	(In thousands)
Acquisition costs:
Proved properties	$	5,551,400			$	452,661			$	72,044
Unproved properties	5,818,006				2,692,000				752,117
Development costs	493,084				145,362				47,575
Exploration costs	1,090,281				779,728				329,122
Capitalized asset retirement costs	113,717				2,682				4,030
Total	$	13,066,488			$	4,072,433			$	1,204,888

F-61

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Results of Operations from Oil and Natural Gas Producing Activities

The following schedule sets forth the revenues and expenses related to the production and sale of oil and natural gas. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our oil, natural gas and natural gas liquids operations.

	Year Ended December 31,
	2018				2017				2016
	(In thousands)
Oil, natural gas and natural gas liquid sales	$	2,129,780			$	1,186,275			$	527,107
Lease operating expenses	(204,975		)		(126,524		)		(82,428		)
Production and ad valorem taxes	(132,661		)		(73,505		)		(34,456		)
Gathering and transportation	(26,113		)		(12,834		)		(11,606		)
Depreciation, depletion, and amortization	(594,750		)		(321,870		)		(176,369		)
Impairment	—				—				(245,536		)
Asset retirement obligation accretion expense	(2,132		)		(1,391		)		(1,064		)
Income tax benefit (expense)	(241,149		)		19,568				(192		)
Results of operations	$	928,000			$	669,719			$	(24,544	)

Oil and Natural Gas Reserves

Proved oil and natural gas reserve estimates as of December 31, 2018, 2017 and 2016 were prepared by Ryder Scott Company, L.P., independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

F-62

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

The changes in estimated proved reserves are as follows:

	Oil (MBbls)			Natural Gas Liquids (MBbls)			Natural Gas (MMcf)
Proved Developed and Undeveloped Reserves:
As of January 1, 2016	105,979			26,004			149,503
Extensions and discoveries	55,069			13,962			64,758
Revisions of previous estimates	(12,483	)		(1,888	)		(34,519	)
Purchase of reserves in place	2,537			1,455			7,567
Divestitures	(366	)		—			(1,985	)
Production	(11,562	)		(2,399	)		(10,428	)
As of December 31, 2016	139,174			37,134			174,896
Extensions and discoveries	99,980			20,825			109,032
Revisions of previous estimates	(7,715	)		(1,466	)		(10,065	)
Purchase of reserves in place	24,322			2,633			34,640
Divestitures	(1,163	)		(461	)		(2,474	)
Production	(21,417	)		(4,056	)		(20,660	)
As of December 31, 2017	233,181			54,609			285,369
Extensions and discoveries	143,256			33,152			154,088
Revisions of previous estimates	3,689			11,138			3,642
Purchase of reserves in place	281,333			98,865			640,761
Divestitures	(156	)		(8	)		(543	)
Production	(34,367	)		(7,465	)		(34,668	)
As of December 31, 2018	626,936			190,291			1,048,649
Proved Developed Reserves:
January 1, 2016	60,569			15,418			96,871
December 31, 2016	79,457			22,080			105,399
December 31, 2017	141,246			35,412			190,740
December 31, 2018	403,051			125,509			705,084
Proved Undeveloped Reserves:
January 1, 2016	45,409			10,586			52,632
December 31, 2016	59,717			15,054			69,497
December 31, 2017	91,935			19,198			94,629
December 31, 2018	223,885			64,782			343,565

Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

During the year ended December 31, 2018, the Company’s extensions and discoveries of 202,089 MBOE resulted primarily from the drilling of 135 new wells and from 138 new proved undeveloped locations added in which the Company owns a working interest. Partnership royalty interests accounted for 10% of the extension volumes. The Company’s revisions of previous estimates were primarily the result of positive technical and performance revisions of 14,218 MBOE, upward revisions of 6,032 MBOE due to higher pricing and downward revisions of 4,815 MBOE from PUD reclassifications due to timing. Purchases of 486,992 MBOE were the result of 477,686 of working interest purchases, primarily attributable to Energen, and 9,306 MBOE of Partnership royalty purchases.

During the year ended December 31, 2017, the Company’s extensions and discoveries of 138,977 MBOE resulted primarily from the drilling of 102 new wells and from 87 new proved undeveloped locations added. Partnership royalty interests

F-63

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

accounted for 8% of the extension volumes. The Company’s revisions of previous estimates were primarily the result of 2,550 MBOE from reclassifying PUD locations due to anticipated timing, with the remaining 8,308 MBOE being technical revisions. Delaware Basin working interest purchases accounted for 87% of the total purchases and Partnership royalty interest purchases accounted for 10%, with working interest purchases contributing the remainder.

During the year ended December 31, 2016, the Company’s extensions and discoveries of 69,042 MBOE resulted primarily from the drilling of 59 new wells and from 51 new proved undeveloped locations added. The Company owns the mineral interests associated with 30 of the 59 new wells and 30 of the 51 proved undeveloped locations through the Partnership. The Company’s negative revisions of previous estimates were primarily the result of 5,978 MBOE of pricing revisions and 7,253 MBOE from reclassifying 17 locations from proved undeveloped due to pricing. Purchases of reserves in place of 3,993 MBOE were primarily the result of the purchase of producing wells included with the Reeves and Ward county acreage purchase and reserves associated with multiple purchases made by the Partnership.

At December 31, 2018, the Company’s estimated PUD reserves were approximately 345,928 MBOE, a 219,023 MBOE increase over the reserve estimate at December 31, 2017 of 126,905 MBOE. The following table includes the changes in PUD reserves for 2018:

	(MBOE)
Beginning proved undeveloped reserves at December 31, 2017	126,905
Undeveloped reserves transferred to developed	(71,435	)
Revisions	338
Net purchases	165,426
Extensions and discoveries	124,694
Ending proved undeveloped reserves at December 31, 2018	345,928

The increase in proved undeveloped reserves was primarily attributable to purchases of 165,426 MBOE mostly from the acquisition of Energen. Extensions contributed 111,020 MBOE from 138 gross (122 net) wells in which the Company has a working interest and 13,674 MBOE from 138 gross wells in which the Partnership owns royalty interests. Of the 138 gross working interest wells, 38 were in the Delaware Basin. Transfers of 71,435 MBOE were the result of drilling or participating in 89 gross (79 net) horizontal wells in which the Company has a working interest and 49 gross wells in which the Company has a royalty interest or mineral interest through the Partnership. The Company owns a working interest in 45 of the 49 gross Partnership wells. Upward revisions of 338 MBOE resulted from commodity price improvement and type curve performance.

As of December 31, 2018, all of the Company’s proved undeveloped reserves are planned to be developed within five years from the date they were initially recorded. During 2018, approximately $493.1 million in capital expenditures went toward the development of proved undeveloped reserves, which includes drilling, completion and other facility costs associated with developing proved undeveloped wells.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows is based on the unweighted average, first-day-of-the-month price. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.

F-64

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved oil and natural gas reserves as of December 31, 2018, 2017 and 2016.

	December 31,
	2018				2017				2016
	(In thousands)
Future cash inflows	$	43,578,469			$	12,921,897			$	6,275,705
Future development costs	(3,560,142		)		(1,123,979		)		(617,636		)
Future production costs	(7,727,257		)		(2,994,877		)		(1,392,852		)
Future production taxes	(2,934,521		)		(928,891		)		(459,244		)
Future income tax expenses	(3,913,024		)		(83,961		)		(75,595		)
Future net cash flows	25,443,525				7,790,189				3,730,378
10% discount to reflect timing of cash flows	(13,767,064		)		(4,033,130		)		(2,018,965		)
Standardized measure of discounted future net cash flows	$	11,676,461			$	3,757,059			$	1,711,413

In the table below the average first-day-of–the-month price for oil, natural gas and natural gas liquids is presented, all utilized in the computation of future cash inflows.

	December 31,
	2018				2017				2016
	Unweighted Arithmetic Average
	First-Day-of-the-Month Prices
Oil (per Bbl)	$	59.63			$	48.03			$	39.94
Natural gas (per Mcf)	$	1.47			$	2.06			$	1.36
Natural gas liquids (per Bbl)	$	24.43			$	20.79			$	12.91

Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows:

	Year Ended December 31,
	2018				2017				2016
	(In thousands)
Standardized measure of discounted future net cash flows at the beginning of the period	$	3,757,059			$	1,711,413			$	1,418,133
Sales of oil and natural gas, net of production costs	(1,786,106		)		(986,246		)		(411,558		)
Acquisition of reserves	5,520,438				439,396				43,142
Divestiture of reserves	(2,036		)		(11,072		)		(5,481		)
Extensions and discoveries, net of future development costs	3,287,043				1,791,686				779,359
Previously estimated development costs incurred during the period	534,768				190,121				85,696
Net changes in prices and production costs	1,805,428				577,781				(150,509		)
Changes in estimated future development costs	(81,062		)		(52,908		)		20,647
Revisions of previous quantity estimates	270,959				(98,857		)		(123,795		)
Accretion of discount	379,659				174,185				143,134
Net change in income taxes	(1,727,907		)		(9,074		)		(30,530		)
Net changes in timing of production and other	(281,782		)		30,634				(56,825		)
Standardized measure of discounted future net cash flows at the end of the period	$	11,676,461			$	3,757,059			$	1,711,413

F-65

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

21. QUARTERLY FINANCIAL DATA (Unaudited)

The Company’s unaudited quarterly financial data for 2018 and 2017 is summarized below.

	2018
	First Quarter				Second Quarter				Third Quarter				Fourth Quarter
Revenues	$	480,195			$	526,273			$	538,029			$	631,759
Income from operations	267,646				281,303				266,851				194,988
Income tax expense (benefit)	47,081				(6,607		)		42,276				85,612
Net income	178,154				301,164				159,417				306,160
Net income (loss) attributable to non-controlling interest	15,342				82,018				2,363				(500		)
Net income attributable to Diamondback Energy, Inc.	$	162,812			$	219,146			$	157,054			$	306,660
Earnings per common share
Basic	$	1.65			$	2.22			$	1.59			$	2.50
Diluted	$	1.65			$	2.22			$	1.59			$	2.50
	2017
	First Quarter				Second Quarter				Third Quarter				Fourth Quarter
Revenues	$	235,230			$	269,434			$	301,253			$	399,194
Income from operations	116,410				132,308				142,639				213,663
Income tax expense (benefit)	1,957				1,579				857				(23,961		)
Net income	141,074				164,128				81,948				129,607
Net income attributable to non-controlling interest	4,801				5,723				8,924				15,048
Net income attributable to Diamondback Energy, Inc.	$	136,273			$	158,405			$	73,024			$	114,559
Earnings per common share
Basic	$	1.46			$	1.61			$	0.74			$	1.17
Diluted	$	1.46			$	1.61			$	0.74			$	1.16

F-66