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 26, 2020
			/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 26, 2020
Steven E. West
/s/ Travis D. Stice		Chief Executive Officer and Director		February 26, 2020
Travis D. Stice		(Principal Executive Officer)
/s/ Michael P. Cross		Director		February 26, 2020
Michael P. Cross
/s/ David L. Houston		Director		February 26, 2020
David L. Houston
/s/ Mark L. Plaumann		Director		February 26, 2020
Mark L. Plaumann
/s/ Melanie M. Trent		Director		February 26, 2020
Melanie M. Trent
/s/ Kaes Van’t Hof		Chief Financial Officer and Executive Vice President—Business Development		February 26, 2020
Kaes Van’t Hof		(Principal Financial Officer)
/s/ Teresa L. Dick		Chief Accounting Officer, Executive Vice President and Assistant Secretary		February 26, 2020
Teresa L. Dick		(Principal 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, 2019 and 2018, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2019, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, 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, 2019, 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 26, 2020 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.

Critical audit matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Depletion expense, impairment evaluation and acquisition of oil and gas properties

As described in Note 2 to the financial statements, the Company accounts for its oil and gas properties using the full cost method of accounting which requires management to make estimates of proved reserve volumes and future revenues to record depletion expense and measure its oil and gas properties for potential impairment. Additionally, as described in Note 3 to the financial statements, the Company acquired significant oil and gas properties throughout the year. To estimate the volume of proved reserves and future revenues, management makes significant estimates and assumptions including forecasting the production decline rate of producing properties, forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties, and for acquisitions that included proved developed producing properties using an estimated fair value pricing model for the valuation of proved producing reserves. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required in the estimation of depletion expense and potential impairment measurements. We identified the estimation of proved reserves of oil and gas properties, due to its impact on depletion expense, impairment evaluation and acquisition valuation of oil and gas properties, as a critical audit matter.

F-1

The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that relatively minor changes in certain inputs and assumptions, which require a high degree of subjectivity, necessary to estimate the volume and future revenues of the Company’s proved reserves could have a significant impact on the measurement of depletion expense or impairment expense. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.

Our audit procedures related to the estimation of proved reserves included the following, among others.

◦

We tested the design and operating effectiveness of key controls relating to the preparation of the ceiling test calculation, management’s estimation of proved reserves for the purpose of estimating depletion expense and assessing the Company’s oil and gas properties for potential impairment, and management’s estimation of the fair value of acquired oil and gas properties. Specifically, these controls related to the use of historical information in the estimation of proved reserves derived from the Company’s accounting records and the management review controls on information provided to the reservoir engineering specialists and the management review controls on the final proved reserve report prepared by the Company’s specialists.

◦	We evaluated the level of knowledge, skill, and ability of the Company’s reservoir engineering specialists and their relationship to the Company, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists.

◦

For acquisitions of oil and gas properties during the year in which proved developed producing properties are significant and to the extent key, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, such as historical pricing differentials, working and net revenue interests and future capital expenditures and operating costs, we tested management’s process for determining the assumptions, including examining the underlying support. Specifically, our audit procedures involved testing management’s assumptions as follows:

◦	Analyzed the appropriateness of fair value pricing used in the acquisition reserve report to published product pricing on the acquisition closing date;

◦	Analyzed the appropriateness of the future operating cost and capital expenditure assumptions used in the acquisition reserve report to historical operating costs and capital expenditures of similarly located properties

◦	Evaluated the working and net revenue interests used in the acquisition reserve report by inspecting a sample of land and division order records;

◦	Analyzed, on a sample basis, the appropriateness of management’s estimated future production volumes and the production decline curves; and

◦	Utilized valuation specialists to compare the acreage value allocated, on a per acre basis, to undeveloped properties and to other recent acquisitions in the same or similar locations.

◦

To the extent key, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, such as historical pricing differentials, operating costs, estimated capital costs and working and net revenue interests, we tested management’s process for determining the assumptions, including examining the underlying support, on a sample basis. Specifically, our audit procedures involved testing management’s assumptions as follows:

◦	Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials;

◦	Evaluated the models used to estimate the operating costs at year-end compared to historical operating costs;

◦	Compared the models used to determine the future capital expenditures and compared estimated future capital expenditures used in the reserve report to amounts expended for recently drilled and completed wells with similar locations;

◦	Evaluated the working and net revenue interests used in the reserve report by inspecting a sample of land and division order records;

◦	Evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the operator’s intent to develop the proved undeveloped properties;

◦	Evaluated the estimated ultimate recovery of proved undeveloped properties to the estimated ultimate recovery of comparable proved developed producing properties; and

◦	Applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year reserve report.

F-2

/s/ GRANT THORNTON LLP

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

Oklahoma City, Oklahoma

February 26, 2020

F-3

Diamondback Energy, Inc. and Subsidiaries

Consolidated Balance Sheets

	December 31,
	2019				2018
	(In millions, except share amounts)
Assets
Current assets:
Cash and cash equivalents	$	123			$	215
Restricted cash	5				—
Accounts receivable:
Joint interest and other, net	186				96
Oil and natural gas sales	429				296
Inventories	37				37
Derivative instruments	46				231
Prepaid expenses and other	43				50
Total current assets	869				925
Property and equipment:
Oil and natural gas properties, full cost method of accounting ($9,207 million and $9,670 million excluded from amortization at December 31, 2019 and 2018, respectively)	25,782				22,299
Midstream assets	931				700
Other property, equipment and land	125				147
Accumulated depletion, depreciation, amortization and impairment	(5,003		)		(2,774		)
Net property and equipment	21,835				20,372
Equity method investments	479				1
Derivative instruments	7				—
Deferred tax asset	142				97
Investment in real estate, net	109				116
Other assets	90				85
Total assets	$	23,531			$	21,596
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	179			$	128
Accrued capital expenditures	475				495
Other accrued liabilities	304				253
Revenues and royalties payable	278				143
Derivative instruments	27				—
Total current liabilities	1,263				1,019
Long-term debt	5,371				4,464
Derivative instruments	—				15
Asset retirement obligations	94				136
Deferred income taxes	1,886				1,785
Other long-term liabilities	11				10
Total liabilities	$	8,625			$	7,429

F-4

Diamondback Energy, Inc. and Subsidiaries

Consolidated Balance Sheets - Continued

	December 31,
	2019				2018
	(In millions, except share amounts)
Commitments and contingencies (Note 18)
Stockholders’ equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 159,002,338 issued and outstanding at December 31, 2019; 200,000,000 shares authorized, 164,273,447 issued and outstanding at December 31, 2018	$	2			$	2
Additional paid-in capital	12,357				12,936
Retained earnings	890				762
Total Diamondback Energy, Inc. stockholders’ equity	13,249				13,700
Non-controlling interest	1,657				467
Total equity	14,906				14,167
Total liabilities and equity	$	23,531			$	21,596

See accompanying notes to consolidated financial statements.

F-5

Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

	Year Ended December 31,
	2019				2018				2017
	(In millions, except per share amounts, shares in thousands)
Revenues:
Oil sales	$	3,554			$	1,879			$	1,044
Natural gas sales	66				61				52
Natural gas liquid sales	267				190				90
Lease bonus	4				3				12
Midstream services	64				34				7
Other operating income	9				9				—
Total revenues	3,964				2,176				1,205
Costs and expenses:
Lease operating expenses	490				205				127
Production and ad valorem taxes	248				133				74
Gathering and transportation	88				26				13
Midstream services	91				72				10
Depreciation, depletion and amortization	1,447				623				327
Impairment of oil and natural gas properties	790				—				—
General and administrative expenses	104				65				48
Asset retirement obligation accretion	7				2				1
Merger and integration expense	—				36				—
Other operating expense	4				3				—
Total costs and expenses	3,269				1,165				600
Income from operations	695				1,011				605
Other income (expense):
Interest expense, net	(172		)		(87		)		(41		)
Other (expense) income, net	(2		)		89				11
(Loss) gain on derivative instruments, net	(108		)		101				(78		)
Gain (loss) on revaluation of investment	5				(1		)		—
Loss on extinguishment of debt	(56		)		—				—
Total other income (expense), net	(333		)		102				(108		)
Income before income taxes	362				1,113				497
Provision for (benefit from) income taxes	47				168				(20		)
Net income	315				945				517
Net income attributable to non-controlling interest	75				99				35
Net income attributable to Diamondback Energy, Inc.	$	240			$	846			$	482
Earnings per common share:
Basic	$	1.47			$	8.09			$	4.95
Diluted	$	1.47			$	8.06			$	4.94
Weighted average common shares outstanding:
Basic	163,493				104,622				97,458
Diluted	163,843				104,929				97,688
Dividends declared per share	$	0.9375			$	0.5000			$	—

See accompanying notes to consolidated financial statements.

F-6

Diamondback Energy, Inc. and Subsidiaries

Consolidated Statement of Stockholders’ Equity

	Common Stock						Additional Paid-in Capital				Retained Earnings (Accumulated Deficit)				Non-Controlling Interest
	Shares		Amount							Total
	($ in millions, shares in thousands)
Balance December 31, 2016	90,144		$	1			$	4,216			$	(520	)		$	321			$	4,018
Net proceeds from issuance of common units - Viper Energy Partners LP															370				370
Unit-based compensation															2				2
Common units issued for acquisition															3				3
Stock-based compensation							32												32
Distribution to non-controlling interest															(41		)		(41		)
Common shares issued for Brigham	7,686						809												809
Exercise of stock options and vesting of restricted stock units	337																		—
Change in ownership of consolidated subsidiaries, net							234								(363		)		(129		)
Net income											482				35				517
Balance at December 31, 2017	98,167		1				5,291				(38		)		327				5,581
Impact of adoption of ASU 2016-01, net of tax											(9		)		(7		)		(16		)
Net proceeds from issuance of common units - Viper Energy Partners LP															303				303
Unit-based compensation															3				3
Stock-based compensation							34												34
Common shares issued for business combination	63,126		1				7,069												7,070
Stock options assumed in business combination							14												14
Restricted stock units assumed in business combination							52												52
Repurchased shares for tax withholding	(140	)					(14		)										(14		)
Distribution to non-controlling interest															(98		)		(98		)
Common shares issued for Ajax	2,584						340												340
Dividend paid											(37		)						(37		)
Exercise of stock options and vesting of restricted stock units	536																		—
Change in ownership of consolidated subsidiaries, net							150								(160		)		(10		)
Net income											846				99				945
Balance December 31, 2018	164,273		2				12,936				762				467				14,167
Net proceeds from issuance of common units - Viper Energy Partners LP															341				341
Net proceeds from issuance of common units - Rattler Midstream LP															720				720
Unit-based compensation															7				7
Common units issued for acquisition			—				—								124				124
Stock-based compensation							57												57
Repurchased shares for tax withholding	(125	)					(13		)										(13		)
Repurchased shares for share buyback program	(6,385	)					$	(598	)										$	(598	)
Distribution to non-controlling interest															$	(122	)		$	(122	)

F-7

Diamondback Energy, Inc. and Subsidiaries

Consolidated Statement of Stockholders’ Equity - Continued

	Common Stock						Additional Paid-in Capital				Retained Earnings (Accumulated Deficit)				Non-Controlling Interest
	Shares		Amount							Total
	($ in millions, shares in thousands)
Dividend paid											(112		)						(112		)
Exercise of stock and unit options and awards of restricted stock	1,239						8												8
Change in ownership of consolidated subsidiaries, net							(33		)						45				12
Net income											240				75				315
Balance December 31, 2019	159,002		$	2			$	12,357			$	890			$	1,657			$	14,906

See accompanying notes to consolidated financial statements.

F-8

Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

	Year Ended December 31,
	2019				2018				2017
	(In millions)
Cash flows from operating activities:
Net income	$	315			$	945			$	517
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for (benefit from) deferred income taxes	47				168				(20		)
Impairment of oil and natural gas properties	790				—				—
Asset retirement obligation accretion	7				2				1
Depreciation, depletion and amortization	1,447				623				327
Amortization of debt issuance costs	9				12				4
Loss on early extinguishment of debt	56				—				—
Change in fair value of derivative instruments	188				(222		)		84
Loss (income) from equity investment	6				—				(1		)
(Gain) loss on revaluation of investment	(5		)		1				—
Equity-based compensation expense	48				27				26
(Gain) loss on sale of assets, net	(1		)		3				(1		)
Gain on sale of inventory	(1		)		—				—
Restricted cash	(5		)		—				—
Changes in operating assets and liabilities:
Accounts receivable	(187		)		13				(97		)
Inventories	(10		)		(14		)		(2		)
Prepaid expenses and other	29				25				(11		)
Accounts payable and accrued liabilities	(129		)		(7		)		37
Income tax payable	—				(1		)		1
Accrued interest	(5		)		(22		)		(21		)
Revenues and royalties payable	135				12				45
Net cash provided by operating activities	2,734				1,565				889
Cash flows from investing activities:
Drilling, completions and non-operated additions to oil and natural gas properties	(2,557		)		(1,359		)		(737		)
Infrastructure additions to oil and natural gas properties	(120		)		(102		)		(56		)
Additions to midstream assets	(244		)		(204		)		(68		)
Purchase of other property, equipment and land	(5		)		(7		)		(23		)
Acquisition of leasehold interests	(443		)		(1,371		)		(1,961		)
Acquisition of mineral interests	(333		)		(440		)		(407		)
Acquisition of midstream assets	—				—				(50		)
Proceeds from sale of assets	300				80				66
Investment in real estate	(1		)		(111		)		—
Funds held in escrow	—				11				104
Equity investments	(485		)		—				—
Net cash used in investing activities	(3,888		)		(3,503		)		(3,132		)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	2,350				2,652				754
Repayment under credit facility	(3,718		)		(1,242		)		(384		)
Repayment on Energen's credit facility	—				(559		)		—
Proceeds from senior notes	3,469				1,062				—
Repayment of senior notes	(1,250		)		—				—
Proceeds from joint venture	$	39			$	—			$	—

F-9

Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows - Continued

	Year Ended December 31,
	2019				2018				2017
	(In millions)
Premium on extinguishment of debt	$	(44	)		$	—			$	—
Debt issuance costs	(18		)		(25		)		(9		)
Public offering costs	(41		)		(3		)		(1		)
Proceeds from public offerings	1,106				305				370
Proceeds from exercise of stock options	9				—				—
Repurchased shares for tax withholdings	(13		)		(14		)		—
Repurchased as part of share buyback	(593		)		—				—
Dividends to stockholders	(112		)		(37		)		—
Distributions to non-controlling interest	(122		)		(98		)		(41		)
Net cash provided by financing activities	1,062				2,041				689
Net (decrease) increase in cash and cash equivalents	(92		)		103				(1,554		)
Cash and cash equivalents at beginning of period	215				112				1,666
Cash and cash equivalents at end of period	$	123			$	215			$	112
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest	$	237			$	114			$	58
Cash paid for income taxes	$	—			$	1			$	—
Supplemental disclosure of non-cash transactions:
Change in accrued capital expenditures	$	(20	)		$	274			$	161
Capitalized stock-based compensation	$	17			$	10			$	9
Common stock issued for Ajax	$	—			$	340			$	—
Common stock issued for Brigham	$	—			$	—			$	809
Common stock issued for business combination(1)	$	—			$	7,136			$	—
Asset retirement obligations acquired	$	4			$	111			$	2

(1)	Includes $7 billion of Common stock issued for business combination, $14 million for stock options assumed and $52 million for restricted stock units assumed.

See accompanying notes to consolidated financial statements.

F-10

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.

The wholly-owned subsidiaries of Diamondback, as of December 31, 2019, 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 (“Viper’s General Partner”), Rattler Midstream GP LLC, a Delaware limited liability company (Rattler’s General Partner), and Energen Corporation, an Alabama corporation (“Energen”). The consolidated subsidiaries include these wholly-owned subsidiaries as well as Viper Energy Partners LP, a Delaware limited partnership (“Viper”), Viper’s subsidiary Viper Energy Partners LLC, a Delaware limited liability company (“Viper LLC”), Rattler Midstream LP (formerly known as Rattler Midstream Partners LP), a Delaware limited partnership (“Rattler”), Rattler Midstream Operating LLC (formerly known as Rattler Midstream LLC), a Delaware limited liability company (“Rattler LLC”), Rattler LLC’s wholly-owned subsidiary Tall City Towers LLC, a Delaware limited liability company (“Tall City”), and Energen’s wholly-owned subsidiaries Energen Resources Corporation, an Alabama corporation (“Energen Resources”), and EGN Services, Inc., an Alabama corporation.

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.

Viper is consolidated in the financial statements of the Company. As of December 31, 2019, the Company owned approximately 58% of the total units outstanding of Viper and the Company’s wholly owned subsidiary, Viper Energy Partners GP LLC, is Viper’s General Partner.

Rattler is consolidated in the financial statements of the Company. As of December 31, 2019, the Company owned approximately 71% of the total units outstanding of Rattler. The Company’s wholly-owned subsidiary, Rattler Midstream GP LLC, is Rattler’s General Partner.

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-11

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

As of December 31, 2019, the Company had restricted cash of $5 million related to the Company’s obligations under its participation and development agreement with Obsidian Resources, L.L.C.

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, 2019 and 2018, the Company recorded an allowance for doubtful accounts of $2 million related to joint interest receivables.

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-12

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,
	2019				2018
	(In millions)
Prepaid insurance	$	6			$	4
Prepaid fees and licenses	4				3
Income tax receivable	19				38
Other	14				5
Total prepaid expenses and other	$	43			$	50

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 9–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 $13.54, $12.62 and $11.11 for the years ended December 31, 2019, 2018 and 2017, respectively. Depreciation, depletion and amortization expense for oil and natural gas properties was $1.4 billion, $595 million and $321 million for the years ended December 31, 2019, 2018 and 2017, 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. An impairment on proved oil and natural gas properties of $790 million was recorded for the year ended December 31, 2019. 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-13

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 15 years. Depreciation expense for other property and equipment was $16 million, $9 million and $1 million for the years ended December 31, 2019, 2018 and 2017, 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-14

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, 2019, 2018 and 2017, 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 $66 million, $32 million and $22 million for the years ended December 31, 2019, 2018 and 2017, respectively.

Inventories

Inventories are stated at the lower of cost or market and consist of tubular goods and equipment at December 31, 2019 and 2018. 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, 2019, 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 $36 million and $28 million, net of accumulated amortization of $15 million and $9 million, as of December 31, 2019 and 2018, respectively. Long-term debt included capitalized costs related to the senior notes of $24 million and $32 million, net of accumulated amortization of $14 million and $15 million, as of December 31, 2019 and 2018, 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,
	2019				2018
	(In millions)
Liability for drilling costs prepaid by joint interest partners	$	12			$	16
Interest payable	27				26
Lease operating expenses payable	119				59
Ad valorem taxes payable	68				49
Other	78				103
Total other accrued liabilities	$	304			$	253

F-15

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 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 water volumes have been delivered to the fracwater meter for a specified well pad and the wastewater volumes

F-16

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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 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 obligations 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 the Company 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. The Company 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 ASC 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 year ended December 31, 2019, 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, 2019, 2018 and 2017.

For additional information on the Company’s investments, see Note 9—Equity Method Investments.

F-17

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Accounting for Equity-Based Compensation

The Company has granted various types of stock-based awards including stock options and restricted stock units. Viper has granted various unit-based awards including unit options and phantom units to employees, officers and directors of Viper’s General Partner and the Company who perform services for Viper. Rattler has granted unit-based awards consisting of phantom units to employees, officers and directors of Rattler’s General Partner and the Company who perform services for Rattler. These plans and related accounting policies are defined and described more fully in Note 12—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, 2019, three purchasers each accounted for more than 10% of our revenue: Shell (27%); Plains (23%); and Vitol (15%). For the year ended December 31, 2018, three purchasers each accounted for more than 10% of the Company’s revenue: Shell (26%); Koch (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 (31%); Koch (19%); and Enterprise Crude Oil LLC (11%). 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, 2019, 2018 and 2017, the Company had no margin tax expense. The Company’s 2015, 2016, 2017, 2018 and 2019 federal income tax and state margin tax returns remain open to examination by tax authorities. As of December 31, 2019 and 2018, we had $2 million unrecognized tax benefits. 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, 2019, 2018 and 2017, there was no interest or penalties associated with uncertain tax positions recognized in the Company’s consolidated financial statements.

F-18

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Recent Accounting Pronouncements

The Company considers the applicability and impact of all ASUs. ASUs not listed below were assessed and determined to be either not applicable or clarifications of ASUs previously disclosed. The following table provides a brief description of recent accounting pronouncements and the Company’s analysis of the effects on its financial statements:

Standard	Description	Date of Adoption	Effect on Financial Statements or Other Significant Matters
Recently Adopted Pronouncements
ASU 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.	Q1 2020	The Company adopted this update effective January 1, 2020. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity since it does not have a history of credit losses.
ASU 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.	Q1 2020	The Company adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity since it does not have transfers between fair value levels.
ASU 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.	Q1 2020	The Company adopted this update prospectively effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.
ASU 2019-05, “Financial Instruments-Credit Losses (Topic 326)”	This update allows a fair value option to be elected for certain financial assets, other than held-to-maturity debt securities, that were previously required to be measured at amortized cost basis.	Q1 2020	The Company adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity since it does not have any cost method investments.
Pronouncements Not Yet Adopted
ASU 2019-12, “Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes”	This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance.	Q1 2021	This update is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Company does not believe that the adoption of this update will have an impact on its financial position, results of operations or liquidity.

3. ACQUISITIONS AND DIVESTITURES

2019 Activity

Divestiture of Certain Conventional and Non-Core Assets Acquired from Energen

On May 23, 2019, the Company completed its divestiture of 6,589 net acres of certain non-core Permian assets, which were acquired by the Company in its merger with Energen (as described below), for an aggregate sale price of $37 million. This divestiture did not result in a gain or loss because it did not have a significant effect on the Company’s reserve base or depreciation, depletion and amortization rate.

F-19

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

On July 1, 2019, the Company completed its divestiture of 103,750 net acres of certain conventional and non-core Permian assets, which were acquired by the Company in the merger with Energen (as described below), for an aggregate sale price of $285 million. This divestiture did not result in a gain or loss because it did not have a significant effect on the Company’s reserve base or depreciation, depletion and amortization rate.

2019 Drop-Down Transaction

On July 29, 2019, the Company entered into a definitive purchase agreement to divest certain mineral and royalty interests to Viper for approximately 18.3 million of Viper’s newly-issued Class B units, approximately 18.3 million newly-issued units of Viper LLC with a fair value of $497 million and $190 million in cash, after giving effect to closing adjustments for net title benefits (the “Drop-Down”). The mineral and royalty interests divested in the Drop-Down represent approximately 5,490 net royalty acres across the Midland and Delaware Basins, of which over 95% are operated by the Company, and have an average net royalty interest of approximately 3.2% (the “Drop-Down Assets”). The Drop-Down closed on October 1, 2019 and was effective as of July 1, 2019. Viper funded the cash portion of the purchase price of the Drop-Down Assets through a combination of cash on hand and borrowings under Viper LLC’s revolving credit facility.

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 $110 million.

Ajax Resources, LLC

On October 31, 2018, the Company completed its acquisition of leasehold interests and related assets of Ajax Resources, LLC, which included approximately 25,493 net leasehold acres in the Northern Midland Basin, for $900 million in cash and approximately 2.6 million shares of the Company’s common stock (the “Ajax acquisition”). This transaction was effective as of July 1, 2018. The cash portion of this transaction was funded through a combination of cash on hand, proceeds from the sale of mineral interests to Viper (described below under the caption “2018 Drop-Down Transaction”), 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 10—Debt for information relating to this offering.

2018 Drop-down Transaction

On August 15, 2018, the Company completed a transaction to sell to Viper 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 million.

ExL Petroleum Management, LLC and EnergyQuest II LLC

On October 31, 2018, the Company completed its acquisitions of 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 $313 million in cash. These transactions were effective as of August 1, 2018 and were funded through a combination of cash on hand, proceeds from the sale of assets to Viper (described immediately above) and borrowing under the Company’s revolving credit facility.

Energen Corporation Merger

On November 29, 2018, the Company completed its acquisition of Energen in an all-stock transaction (the “ Merger”), which was accounted for as a business combination. Upon completion of the Merger, 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

F-20

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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 10—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 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 resulting in no goodwill or bargain purchase gain.

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

	(In millions)
Consideration:
Fair value of the Company's common stock issued	$	7,136
Total consideration	$	7,136
Fair value of liabilities assumed:
Current liabilities	$	388
Asset retirement obligation	105
Long-term debt	1,099
Noncurrent derivative instruments	17
Deferred income taxes	1,425
Other long-term liabilities	7
Amount attributable to liabilities assumed	$	3,041
Fair value of assets acquired:
Total current assets	$	298
Oil and natural gas properties	9,361
Midstream assets	253
Investment in real estate	11
Other property, equipment and land	58
Asset retirement obligation	105
Other postretirement assets	3
Noncurrent income tax receivable, net	76
Other long term assets	12
Amount attributable to assets acquired	$	10,177

The Company has included in its consolidated statements of operations revenues of $102 million and direct operating expenses of $17 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

F-21

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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 $37 million for the year ended December 31, 2018 and acquisition-related costs incurred by Energen of $59 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.

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 millions, except per share amounts)
Revenues	$	3,532			$	2,196
Income from operations	1,559				900
Net income	1,320				875
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 $1.7 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 $48 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 millions)
Proved oil and natural gas properties	$	386
Unevaluated oil and natural gas properties	2,123
Midstream assets	47
Prepaid capital costs	4
Oil inventory	1
Revenues and royalties payable	(10		)
Asset retirement obligations	(2		)
Total fair value of net assets	$	2,549

The Company has included in its consolidated statements of operations revenues of $81 million and direct operating expenses of $24 million for the period from February 28, 2017 to December 31, 2017 due to the acquisition.

F-22

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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.

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 millions, except per share amounts)
Revenues	$	1,228			$	627
Income (loss) from operations	619				(13		)
Net income (loss)	473				(109		)
Basic earnings per common share	$	4.85			$	(1.45	)
Diluted earnings per common share	$	4.84			$	(1.45	)

4. VIPER ENERGY PARTNERS LP

Viper is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “VNOM”. Viper was formed by Diamondback on February 27, 2014, to, among other things, own, acquire and exploit oil and natural gas properties in North America. Viper 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, Viper. As of December 31, 2019, the Company owned approximately 58% of Viper’s total units outstanding.

During the year ended December 31, 2019, Diamondback received distributions of $133 million in respect of its interests in Viper and Viper LLC.

Viper completed the following equity offerings during the years ended December 31, 2019, 2018 and 2017:

Date	Number of Units of Common Units Sold		Number of Units of Common Units Issued to Underwriters		Proceeds Received by Viper			Amount Repaid on Viper LLC’s Credit Facility
					(in millions)
January 2017	9,775,000		1,275,000		$	148		$	121
July 2017(1)	16,100,000		2,100,000		$	232		$	153
July 2018	10,080,000		1,080,000		$	303		$	362
March 2019	10,925,000		1,425,000		$	341		$	314

(1)	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.

As a result of Viper’s public offerings, Viper’s issuance of units for acquisitions and Viper’s issuance of unit-based compensation, the Company’s ownership percentage in Viper was reduced. During the year ended December 31, 2019, the Company recorded a $45 million decrease to non-controlling interest in Viper with an increase to additional paid-in capital, which represents the difference between the Company’s share of the underlying net book value in Viper before and after the respective Partnership common unit transactions, on the Company’s consolidated balance sheet.

F-23

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Recapitalization, Tax Status Election and Related Transactions by Viper

In March 2018, Viper announced that the Board of Directors of the General Partner had unanimously approved a change of Viper’s federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election. In connection with making this election, on May 9, 2018 Viper (i) amended and restated its First Amended and Restated Partnership Agreement, (ii) amended and restated the First Amended and Restated Limited Liability Company Agreement of 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 Viper the 73,150,000 common units the Company owned in exchange for (i) 73,150,000 of Viper’s newly-issued Class B units and (ii) 73,150,000 newly-issued units of the Operating Company pursuant to the terms of a Recapitalization Agreement dated March 28, 2018, as amended as of May 9, 2018 (the “Recapitalization Agreement”). Immediately following that exchange, Viper continued to be the managing member of the Operating Company, with sole control of its operations, and owned approximately 36% of the outstanding units issued by the Operating Company, and the Company owned the remaining approximately 64% of the outstanding units issued by the Operating Company. Upon completion of Viper’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 Viper’s Class B units owned by the Company are exchangeable from time to time for Viper’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 Viper’s income tax status became effective. On that date, pursuant to the terms of the Recapitalization Agreement, (i) the General Partner made a cash capital contribution of $1 million to Viper in respect of its general partner interest and (ii) the Company made a cash capital contribution of $1 million to Viper 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 Viper and a cash amount of $10,000 representing a proportionate return of the $1 million invested capital in respect of the Class B units. The General Partner continues to serve as Viper’s general partner and the Company continues to control Viper. After the effectiveness of the tax status election and the completion of related transactions, Viper’s minerals business continues to be conducted through the Operating Company, which continues to be taxed as a partnership for federal and state income tax purposes. This structure is anticipated to provide significant benefits to Viper’s business, including operational effectiveness, acquisition and disposition transactional planning flexibility and income tax efficiency. For additional information regarding the tax status election and related transactions, please refer to Viper’s Definitive Information Statement on Schedule 14C filed with the SEC on April 17, 2018 and Viper’s Current Report on Form 8-K filed with the SEC on May 15, 2018.

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 “Viper Partnership Agreement”), requires Viper to reimburse Viper’s General Partner for all direct and indirect expenses incurred or paid on Viper’s behalf and all other expenses allocable to Viper or otherwise incurred by Viper’s General Partner in connection with operating Viper’s business. The Viper Partnership Agreement does not set a limit on the amount of expenses for which Viper’s 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 Viper or on its behalf and expenses allocated to Viper’s General Partner by its affiliates. Viper’s General Partner is entitled to determine the expenses that are allocable to Viper. For each of the year ended December 31, 2019 and 2018, Viper’s General Partner allocated $3 million and $2 million, respectively, to Viper.

Tax Sharing

In connection with the closing of the Viper Offering, Viper entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to which Viper agreed to reimburse Diamondback for its share of state and local income and other taxes for which Viper’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 Viper 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 Viper may be a member for this purpose, to owe less or no tax. In such a situation, Viper agreed to reimburse Diamondback for the tax Viper would have owed had the tax attributes not been available or used for Viper’s benefit, even

F-24

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

though Diamondback had no cash tax expense for that period. For the year ended December 31, 2019, Viper did not accrue any state income tax expense. For the year ended December 31, 2018, Viper accrued a minimal amount for its share of Texas margin tax for which Viper’s results are included in a combined tax return filed by Diamondback.

Viper LLC’s Revolving Credit Facility

Viper 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 10—Debt for a description of this credit facility.

5. RATTLER MIDSTREAM LP

Rattler is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “RTLR”. Rattler was formed by Diamondback in July 2018 to own, operate, develop and acquire midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. Rattler’s General Partner, a wholly-owned subsidiary of Diamondback, serves as the general partner of Rattler. As of December 31, 2019, Diamondback owned approximately 71% of Rattler’s total units outstanding.

Prior to the completion of Rattler’s initial public offering (the “Rattler Offering”) in May of 2019, Diamondback owned all of the general and limited partner interests in Rattler. The Rattler Offering consisted of 43,700,000 common units representing approximately 29% of the limited partner interests in Rattler at a price to the public of $17.50 per common unit, which included 5,700,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters on the same terms which closed on May 30, 2019. Rattler received net proceeds of approximately $720 million from the sale of these common units, after deducting offering expenses and underwriting discounts and commissions.

In connection with the completion of the Rattler Offering, Rattler (i) issued 107,815,152 Class B Units representing an aggregate 71% voting limited partner interest in Rattler in exchange for a $1 million cash contribution from Diamondback, (ii) issued a general partner interest in Rattler to Rattler’s General Partner, in exchange for a $1 million cash contribution from Rattler’s General Partner, and (iii) caused Rattler LLC to make a distribution of approximately $727 million to Diamondback. Diamondback, as the holder of the Class B units, and Rattler’s General Partner, as the holder of the general partner interest, are entitled to receive cash preferred distributions equal to 8% per annum on the outstanding amount of their respective $1 million capital contributions, payable quarterly.

Diamondback has also entered into the following agreements with Rattler:

Rattler’s Partnership Agreement

In connection with the closing of the Rattler Offering, Rattler’s General Partner and Energen Resources entered into the first amended and restated agreement of limited partnership of Rattler, dated May 28, 2019 (the “Rattler Partnership Agreement”). The Rattler Partnership Agreement requires Rattler to reimburse Rattler’s General Partner for all direct and indirect expenses incurred or paid on Rattler’s behalf and all other expenses allocable to Rattler or otherwise incurred by Rattler’s General Partner in connection with operating Rattler’s business. The Rattler Partnership Agreement does not set a limit on the amount of expenses for which its 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 Rattler or on its behalf and expenses allocated to Rattler’s General Partner by its affiliates. Rattler’s General Partner is entitled to determine the expenses that are allocable to Rattler. For the year ended December 31, 2019, Rattler’s General Partner allocated $364,342 of such expenses to Rattler.

Rattler’s Services and Secondment Agreement

In connection with the closing of the Rattler Offering, Rattler entered into a services and secondment agreement with Diamondback, Diamondback E&P LLC, Rattler’s General Partner and Rattler LLC, dated as of May 28, 2019 (the “Services and Secondment Agreement”). Pursuant to the Services and Secondment Agreement, Diamondback and its subsidiaries second certain operational, construction, design and management employees and contractors of Diamondback to Rattler’s General Partner, Rattler and its subsidiaries, providing management, maintenance and operational functions with respect to Rattler’s assets. The Services and Secondment Agreement requires Rattler’s General Partner and Rattler to reimburse Diamondback for the cost of the seconded employees and contractors, including their wages and benefits. For the year ended December 31, 2019, Rattler’s General Partner and Rattler paid Diamondback $5 million under the Services and Secondment Agreement.

F-25

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Rattler’s Tax Sharing Agreement

In connection with the closing of the Rattler Offering, Rattler LLC entered into a tax sharing agreement with Diamondback pursuant to which Rattler LLC will reimburse Diamondback for its share of state and local income and other taxes borne by Diamondback as a result of Rattler LLC’s results being included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on May 28, 2019. The amount of any such reimbursement is limited to the tax that Rattler LLC would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its combined or consolidated group, of which Rattler LLC may be a member for this purpose, to owe less or no tax. In such a situation, Rattler LLC agreed to reimburse Diamondback for the tax Rattler LLC would have owed had the attributes not been available or used for Rattler LLC’s benefit, even though Diamondback had no cash expense for that period.

For the year ended December 31, 2019, Rattler accrued state income tax expense of $188,808 for its share of Texas margin tax for which Rattler’s share of Rattler LLC’s results are included in a combined tax return filed by Diamondback.

Rattler LLC’s Revolving Credit Facility

Rattler LLC has entered into a secured revolving credit facility with Wells Fargo Bank, National Association, as administrative agent, sole book runner and lead arranger. See Note 10—Debt for a description of this credit facility.

6. REAL ESTATE ASSETS

In conjunction with Diamondback’s acquisition of Fasken Towers Tall Towers, the Company allocated the $110 million purchase price between real estate assets and intangible lease assets related to in-place and above-market leases. In addition, the Company owns $10 million in office buildings. 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,
		2019				2018
	(Years)		(in millions)
Buildings	20-30		$	102			$	103
Tenant improvements	15		5				4
Land	N/A		2				1
Land improvements	15		1				1
Total real estate assets			110				109
Less: accumulated depreciation			(9		)		(4		)
Total investment in land and buildings, net			$	101			$	105

	Weighted Average Useful Lives		December 31,
		2019				2018
	(Months)		(in millions)
In-place lease intangibles	45		$	11			$	11
Less: accumulated amortization			(6		)		(3		)
In-place lease intangibles, net			5				8
Above-market lease intangibles	45		4				4
Less: accumulated amortization			(1		)		(1		)
Above-market lease intangibles, net			3				3
Total intangible lease assets, net			$	8			$	11

F-26

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

7. PROPERTY AND EQUIPMENT

Property and equipment includes the following:

	December 31,
	2019				2018
	(in millions)
Oil and natural gas properties:
Subject to depletion	$	16,575			$	12,629
Not subject to depletion	9,207				9,670
Gross oil and natural gas properties	25,782				22,299
Accumulated depletion	(2,995		)		(1,599		)
Accumulated impairment	(1,934		)		(1,144		)
Oil and natural gas properties, net	20,853				19,556
Midstream assets	931				700
Other property, equipment and land	125				147
Accumulated depreciation	(74		)		(31		)
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment	$	21,835			$	20,372
Balance of costs not subject to depletion:
Incurred in 2019	$	604
Incurred in 2018	5,654
Incurred in 2017	2,329
Incurred in 2016	620
Total not subject to depletion	$	9,207

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 $49 million, $29 million and $22 million for the years ended December 31, 2019, 2018 and 2017, respectively. Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within three to five years. Acquisition costs not currently being amortized are primarily related to unproved acreage that the Company plans to prove up through drilling. The Company has no plans to let any acreage expire. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas.

Under this method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions, 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.

F-27

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

As a result of the decline in commodity prices during 2019, the Company recorded a non-cash ceiling test impairment for the year ended December 31, 2019 of $790 million which was included in accumulated depletion. The impairment charge 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. No impairment on proved oil and natural gas properties was recorded for the year ended December 31, 2018.

At December 31, 2019, there was $228 million in exploration costs and development costs and $118 million in capitalized interest that are not subject to depletion. At December 31, 2018, there were $68 million exploration costs and development costs and $55 million capitalized interest that are not subject to depletion.

8. 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,
	2019				2018				2017
	(in millions)
Asset retirement obligations, beginning of period	$	136			$	21			$	17
Additional liabilities incurred	8				3				2
Liabilities acquired	4				111				2
Liabilities settled	(61		)		(2		)		(1		)
Accretion expense	7				2				1
Revisions in estimated liabilities	—				1				—
Asset retirement obligations, end of period	94				136				21
Less current portion	—				—				1
Asset retirement obligations - long-term	$	94			$	136			$	20

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.

9. EQUITY METHOD INVESTMENTS

At December 31, 2019 and 2018, Rattler had the following investments:

	Net Ownership Interest			December 31, 2019				December 31, 2018
				(In millions)
EPIC Crude Holdings, LP	10	%		$	110			$	—
Gray Oak Pipeline, LLC	10	%		115				1
Wink to Webster Pipeline LLC	4	%		34				—
OMOG JV LLC	60	%		219				—
Amarillo Rattler, LLC	50	%		1				—
				$	479			$	1

F-28

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

The following summarizes the income (loss) of equity method investees for the periods presented:

	Year Ended December 31,
	2019				2018				2017
	(In millions)
EPIC Crude Holdings, LP	$	(6	)		$	—			$	—
Gray Oak Pipeline, LLC	1				—				—
Wink to Webster Pipeline LLC	(1		)		—				—
OMOG JV LLC	—				—				—
HMW LLC	—				—				1
	$	(6	)		$	—			$	1

In October 2014, the Company acquired a 25% interest in HMW Fluid Management LLC (“HMW LLC”), which was formed to develop, own and operate an integrated water management system to gather, store, process, treat, distribute and dispose of water to exploration and production companies operating in Midland, Martin and Andrews Counties, Texas.

On June 30, 2018, HMW LLC’s operating agreement was amended. As a result of the amendment, Rattler no longer recognizes an equity investment in HMW LLC but instead consolidates its undivided interest in the produced water disposal (“PWD”) assets owned by HMW LLC. In exchange for Rattler’s 25% investment, Rattler received a 50% undivided ownership interest in two of the four PWD wells and associated assets previously owned by HMW LLC. Rattler’s basis in the assets is equivalent to its basis in the equity investment in HMW LLC.

On February 1, 2019, Rattler LLC acquired a 10% equity interest in EPIC Crude Holdings, LP (“EPIC”), which is building a pipeline (the “EPIC project”) that, once fully operational, will transport crude and NGL across Texas for delivery into the Corpus Christi market. The EPIC project began initial operations during the third quarter of 2019.

On February 15, 2019, Rattler LLC acquired a 10% equity interest in Gray Oak Pipeline, LLC (“Gray Oak”), which is building a pipeline (the “Gray Oak project”) that, once operational, will transport crude from the Permian to Corpus Christi on the Texas Gulf Coast. The Gray Oak project began initial operations during the fourth quarter of 2019.

On March 29, 2019, Rattler LLC executed a short-term promissory note to Gray Oak. The note allows for borrowing by Gray Oak of up to $123 million at 2.52% interest rate with a maturity date of March 31, 2022. During the year ended December 31, 2019, there were $23 million in borrowings and repayments under this note. The short-term promissory note was repaid on May 31, 2019.

On June 4, 2019, Rattler entered into an equity contribution agreement with respect to Gray Oak. The equity contribution agreement requires Rattler to contribute equity or make loans to Gray Oak so that Gray Oak can, to the extent necessary, cure payment defaults under Gray Oak’s credit agreement and, in certain instances, repay Gray Oak’s credit agreement in full. Rattler’s obligations under the equity contribution agreement are limited to its proportionate ownership interest in Gray Oak, and such obligations are guaranteed by Rattler LLC, Tall City, Rattler OMOG LLC and Rattler Ajax Processing LLC.

On July 30, 2019, Rattler LLC joined Wink to Webster Pipeline LLC as a 4% member, together with affiliates of ExxonMobil, Plains All American Pipeline, Delek US, MPLX LP and Lotus Midstream. The joint venture is developing a crude oil pipeline with origin points at Wink and Midland in the Permian Basin for delivery to multiple Houston area locations (the “Wink to Webster project”). The Wink to Webster project is expected to begin service in the first half of 2021.

On October 1, 2019, Rattler LLC acquired a 60% equity interest in OMOG JV LLC (“OMOG”). On November 7, 2019, OMOG acquired 100% of Reliance Gathering, LLC which operates a crude oil gathering system in the Permian, and was renamed as Oryx Midland Oil Gathering LLC following the acquisition. While Rattler’s equity interest is 60%, the investment is accounted for as an equity method investment as Rattler does not control operating activities and substantive participating rights exist with the controlling minority investor.

On December 20, 2019, Rattler LLC acquired a 50% equity interest in Amarillo Rattler LLC, which currently owns and operates the Yellow Rose gas gathering and processing system with estimated total processing capacity of 40,000 Mcf/d and over 84 miles of gathering and regional transportation pipelines in Dawson, Martin and Andrews Counties, Texas. This joint

F-29

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

venture also intends to construct and operate a new 60,000 Mcf/d cryogenic natural gas processing plant in Martin County, Texas. While Rattler’s equity interest is 50%, the investment is accounted for as an equity method investment as Rattler does not control operating activities and substantive participating rights exist with the controlling investor.

No impairments were recorded for Rattler’s equity method investments for the year ended December 31, 2019 or 2018.

At December 31, 2019, there was $1 million of capitalized interest that was related to equity method investments that have not yet begun operations.

10. DEBT

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

	December 31,
	2019				2018
	(in millions)
4.625% Notes due 2021	$	399			$	400
7.320% Medium-term Notes, Series A, due 2022	21				20
2.875% Senior Notes due 2024	1,000				—
4.750% Senior Notes due 2024	—				1,250
5.375% Senior Notes due 2025	800				800
3.250% Senior Notes due 2026	800				—
7.350% Medium-term Notes, Series A, due 2027	11				10
7.125% Medium-term Notes, Series B, due 2028	108				100
3.500% Senior Notes due 2029	1,200				—
DrillCo Agreement	39				—
Unamortized debt issuance costs	(19		)		(27		)
Unamortized discount costs	(31		)		—
Unamortized premium costs	9				10
Revolving credit facility	13				1,490
Viper revolving credit facility	97				411
Viper 5.375% Senior Notes due 2027	500				—
Rattler revolving credit facility	424				—
Total long-term debt	$	5,371			$	4,464

Diamondback Notes

4.750% Senior Notes

On October 28, 2016, the Company issued $500 million in aggregate principal amount of 4.750% senior notes due 2024 (“4.750% senior notes”), under an indenture among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee. On September 25, 2018, the Company issued $750 million aggregate principal amount of new 4.750% senior notes as additional notes under, and subject to the terms of, the same indenture governing the 4.750% senior notes. The Company received approximately $741 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 4.750% senior notes. The Company used a portion of the net proceeds from the issuance of the new 4.750% senior notes to repay a portion of the outstanding borrowings its revolving credit facility and the balance for general corporate purposes, including funding a portion of the cash consideration for the acquisition of certain assets from Ajax Resources, LLC..

On December 20, 2019, the Company redeemed all of the outstanding 4.750% senior notes. The redemption payment (the “Redemption Payment”) included $1.25 billion of outstanding principal at a redemption price of 103.563% of the principal amount of the 4.750% senior notes, plus accrued and unpaid interest on the outstanding principal amount to the Redemption

F-30

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Date. On December 5, 2019, the indenture governing the 4.750% senior notes was fully satisfied and discharged and the guarantors were released from their guarantees of the 4.750% senior notes. The Company funded the Redemption Payment with a portion of the net proceeds from the issuance of the December 2019 Notes.

The 4.750% senior notes bore 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 would have matured on November 1, 2024. All of our restricted subsidiaries that guaranteed our revolving credit facility guaranteed the 4.750% senior notes; provided, however, that the 4.750% senior notes were not guaranteed by Viper, Viper’s General Partner, Viper LLC, Rattler, Rattler’s General Partner or Rattler LLC.

2025 Senior Notes

On December 20, 2016, the Company issued $500 million in aggregate principal amount of 5.375% senior notes due 2025 (the “existing 2025 notes”), under an indenture among us, the subsidiary guarantors party thereto and Wells Fargo, as the trustee (the “2025 indenture”). On January 29, 2018, the Company issued $300 million aggregate principal amount of new 5.375% senior notes due 2025 as additional notes under the 2025 indenture (the “new 2025 notes” and, together with the existing 2025 notes, the 2025 senior notes). The Company received approximately $308 million in net proceeds, after deducting the initial purchaser’s discount and the Company’s 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 bear interest at a rate of 5.375% per annum, payable semi-annually, in arrears on May 31 and November 30 of each year and will mature on May 31, 2025. All of the Company’s existing and future restricted subsidiaries that guarantee its revolving credit facility guarantee the 2025 senior notes. Currently, the 2025 senior notes are not guaranteed by any of the Company’s subsidiaries other than Diamondback O&G LLC and will not be guaranteed by any of the Company’s future 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.

December 2019 Notes Offering

On December 5, 2019, the Company issued $1.0 billion in aggregate principal amount of 2.875% senior notes due 2024 (the “2024 notes”), $800 million in aggregate principal amount of 3.250% senior notes due 2026 (the “2026 notes”), and $1.2 billion aggregate principal amount of 3.500% senior notes due 2029, (the “2029 notes” and, together with the 2024 notes and the 2026 notes, the “December 2019 Notes”). The 2024 notes will mature on December 1, 2024, the 2026 notes will mature on December 1, 2026 and the 2029 notes will mature on December 1, 2029. Interest will accrue and be payable semi-annually, in arrears on June 1 and December 1 of each year, commencing on June 1, 2020. The December 2019 Notes are fully and unconditionally guaranteed by Diamondback O&G LLC and are not guaranteed by any of the Company’s other subsidiaries.

The December 2019 Notes were issued under an indenture, dated as of December 5, 2019, among the Company and Wells Fargo, as the trustee, as supplemented by the first supplemental indenture dated as of December 5, 2019 (the “December 2019 Notes Indenture”).

The Company may redeem (i) the 2024 Notes in whole or in part at any time prior to November 1, 2024 (one month prior to the maturity date of the 2024 Notes), (ii) the 2026 Notes in whole or in part at any time prior to October 1, 2026 (two months prior to the maturity date of the 2026 Notes) and (iii) the 2029 Notes in whole or in part at any time prior to September 1, 2029 (three months prior to the maturity date of the 2029 Notes) (each such date, a “par call date”), in each case at the

F-31

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

redemption price set forth in the indenture governing the December 2019 Notes. If the December 2019 Notes are redeemed on or after their respective par call dates, in each case, such December 2019 Notes will be redeemed at a redemption price equal to 100% of the principal amount of the December 2019 Notes to be redeemed plus interest accrued thereon to but not including the redemption date.

Upon the occurrence of a Change of Control Triggering Event (as defined in the indenture governing the December 2019 Notes), holders may require the Company to purchase some or all of their December 2019 Notes for cash at a price equal to 101% of the principal amount of the December 2019 Notes being purchased, plus accrued and unpaid interest, if any, to the date of purchase.

The indenture governing the December 2019 Notes contains customary terms and covenants, including limitations on the Company’s ability and the ability of certain of its subsidiaries to incur liens securing funded indebtedness and on the Company’s ability to consolidate, merge or sell, convey, transfer or lease all or substantially all of its assets.

Second Amended and Restated Credit Facility

The Company and Diamondback O&G LLC, as borrower, entered into the second amended and restated credit agreement, dated November 1, 2013, as amended, with a syndicate of banks, including Wells Fargo, as administrative agent, and its affiliate Wells Fargo Securities, LLC, as sole book runner and lead arranger. On June 28, 2019, the credit agreement was amended pursuant to an eleventh amendment, which implemented certain changes to the credit facility for the period on and after the date on which our unsecured debt achieves an investment grade rating from two rating agencies and certain other conditions in the credit agreement are satisfied (the “investment grade changeover date”). On November 20, 2019, Diamondback O&G LLC caused Diamondback O&G LLC to deliver a notice as borrower under the revolving credit facility to trigger the “investment grade changeover date.” As of December 31, 2019, the maximum credit amount available under the credit agreement is $2.0 billion. As of December 31, 2019, the Company had approximately $13 million of outstanding borrowings under its revolving credit facility and $1.99 billion available for future borrowings under the revolving credit facility.

Diamondback O&G LLC is the borrower under the credit agreement, and, as of December 31, 2019, the credit agreement is guaranteed by Diamondback Energy, Inc. None of the Company’s other subsidiaries are guarantors under the revolving credit facility. On December 5, 2019, Diamondback O&G LLC delivered a letter notifying the administrative agent under the credit agreement that as of such date, each of the guarantors, other than Diamondback Energy, Inc., ceased to be a guarantor under the credit agreement.

The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by us that is equal to the 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 with range from 0.125% to 1.0% per annum and from 1.125% to 2.0% per annum in the case of LIBOR, in each case, depending on the pricing level, which in turn depends on the rating agencies’ rating of our unsecured debt. We are obligated to pay a quarterly commitment fee ranging from 0.125% to 0.350% per year on the unused portion of the commitment, based on the pricing level, which in turn depends on the rating agencies’ rating of our unsecured debt.

Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage). Loan principal is required to be repaid (a) to the extent the loan amount exceeds the commitment due to any termination or reduction of the aggregate maximum credit amount and (b) at the maturity date of November 1, 2022.

The credit agreement contains a financial covenant that requires us to maintain a Total Net Debt to Capitalization Ratio (as defined in the credit agreement) of no more than 65%. Our non-guarantor restricted subsidiaries may incur debt for borrowed money in an aggregate principal amount up to 15% of consolidated net tangible assets (as defined in the credit agreement) and we and our restricted subsidiaries may incur liens if the aggregate amount of debt secured by such liens does not exceed 15% of consolidated net tangible assets.

As of December 31, 2019 and 2018, the Company was in compliance with all financial covenants under the revolving credit facility, as then in effect. The lenders may accelerate all of the indebtedness under the revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.

F-32

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 million in notes (the “Energen Notes”), issued under an indenture dated September 1, 1996 with The Bank of New York as Trustee (the “Energen Indenture”). As of December 31, 2019, the Energen Notes consist of: (1) $399 million aggregate principal amount of 4.625% senior notes due on September 1, 2021, (2) $108 million of 7.125% notes due on February 15, 2028, (3) $21 million of 7.32% notes due on July 28, 2022, and (4) $11 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, 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 if any, and are effectively subordinated to Energen’s senior secured indebtedness, if any, to the extent of the value of the collateral securing such indebtedness. Neither we nor any of our subsidiaries guarantee the Energen Notes.

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 and the 2025 Indenture, Energen is also a guarantor of the 2025 Senior Notes.

Viper’s Facility - Wells Fargo Bank

On July 20, 2018, Viper LLC, as borrower, entered into an amended and restated credit agreement with Viper, as guarantor, Wells Fargo, as administrative agent, and the other lenders. The credit agreement, as amended (the “Viper credit agreement”), provides for a revolving credit facility in the maximum credit amount of $2 billion and a borrowing base based on Viper LLC’s oil and natural gas reserves and other factors (the “borrowing base”) of $775 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 November 1st. In addition, Viper LLC and Wells Fargo each may request up to three interim redeterminations of the borrowing base during any 12-month period. In connection with Viper’s fall redetermination in November 2019, the borrowing base under the Viper credit agreement was increased to $775 million. As of December 31, 2019, the borrowing base was set at $775 million, and Viper LLC had $97 million of outstanding borrowings and $678 million available for future borrowings under the Viper credit agreement.

The outstanding borrowings under the Viper credit agreement bear interest at a per annum rate elected by Viper LLC 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. Viper LLC 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 Viper and Viper LLC.

F-33

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

The Viper credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates, purchases of margin stock 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 Viper credit agreement	Not greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined the Viper 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 $1.0 billion 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. The covenant limiting dividends and distributions includes an exception allowing Viper LLC to make distributions if no default, event of default or borrowing base deficiency exists.

As of December 31, 2019 and 2018, Viper and Viper LLC were in compliance with all financial covenants under the Viper credit agreement, as then in effect. The lenders may accelerate all of the indebtedness under the Viper credit agreement upon the occurrence and during the continuance of any event of default. The Viper credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control.

Viper’s Notes

On October 16, 2019, Viper completed an offering in which it issued its 5.375% Senior Notes due 2027 in aggregate principal amount of $500 million (the “Viper Notes”). Viper received gross proceeds of $500 million from the such offering, which it loaned to Viper LLC. Viper LLC paid the expenses of the offering, resulting in net proceeds of the offering of $490 million, which Viper LLC used to pay down borrowings under the Viper credit agreement.

The Viper Notes were issued under an indenture, dated as of October 16, 2019, among Viper, as issuer, Viper LLC, as guarantor and Wells Fargo, as trustee (the “Viper Indenture”). Pursuant to the Viper Indenture and the Viper Notes, interest on the Viper Notes accrues at a rate of 5.375% per annum on the outstanding principal amount thereof, payable semi-annually on May 1 and November 1 of each year, commencing on May 1, 2020. The Viper Notes will mature on November 1, 2027.

Viper LLC guarantees the Viper Notes pursuant to the Viper Indenture. Neither the Company nor any of its other subsidiaries guarantee the Viper Notes.

The Viper Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit Viper’s ability and the ability of its restricted subsidiaries to incur or guarantee additional indebtedness or issue certain redeemable or preferred equity, make certain investments, declare or pay dividends or make distributions on equity interests or redeem, repurchase or retire equity interests or subordinated indebtedness, transfer or sell assets, agree to payment restrictions affecting its restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens and designate certain of its subsidiaries as unrestricted subsidiaries. These covenants are subject to numerous exceptions, some of which are material. Certain of these covenants are subject to termination upon the occurrence of certain events.

Rattler’s Credit Agreement

In connection with the Rattler Offering, Rattler, as parent, and Rattler LLC, as borrower, entered into a credit agreement, dated May 28, 2019, with Wells Fargo Bank, as administrative agent, and a syndicate of banks, as lenders party thereto (the “Rattler credit agreement”).

The Rattler credit agreement provides for a revolving credit facility in the maximum credit amount of $600 million. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be paid at the maturity date of May 28, 2024. The Rattler credit agreement is guaranteed by Rattler, Tall City, Rattler OMOG LLC and Rattler Ajax Processing LLC. As of December 31, 2019, Rattler LLC had $424 million of outstanding borrowings and $176 million available for future borrowings under the Rattler credit agreement.

F-34

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

The outstanding borrowings under the Rattler credit agreement bear interest at a per annum rate elected by Rattler LLC that is based on the prime rate or LIBOR, in each case plus an applicable margin. The applicable margin ranges from 0.250% to 1.250% per annum for prime-based loans and 1.250% to 2.250% per annum for LIBOR loans, in each case depending on the Consolidated Total Leverage Ratio (as defined in the Rattler credit agreement). Rattler LLC is obligated to pay a quarterly commitment fee ranging from 0.250% to 0.375% per annum on the unused portion of the commitment, which fee is also dependent on the Consolidated Total Leverage Ratio.

The Rattler credit agreement contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, distributions and other restricted payments, transactions with affiliates, and entering into certain swap agreements, in each case of Rattler, Rattler LLC and their restricted subsidiaries. The covenants are subject to exceptions set forth in the Rattler credit agreement, including an exception allowing Rattler LLC or Rattler to issue unsecured debt securities and an exception allowing payment of distributions if no default exists.

The Rattler credit agreement also contains financial maintenance covenants that require the maintenance of the financial ratios described below:

Financial Covenant		Required Ratio
Consolidated Total Leverage Ratio commencing with the fiscal quarter ending September 30, 2019		Not greater than 5.00 to 1.00 (or not greater than 5.50 to 1.00 for 3 fiscal quarters following certain acquisitions), but if the Consolidated Senior Secured Leverage Ratio (as defined in the Rattler credit agreement) is applicable, then not greater than 5.25 to 1.00)
Consolidated Senior Secured Leverage Ratio commencing with the last day of any fiscal quarter in which the Financial Covenant Election (as defined in the Rattler credit agreement) is made		Not greater than 3.50 to 1.00
Consolidated Interest Coverage Ratio (as defined in the Rattler credit agreement) commencing with the fiscal quarter ending September 30, 2019		Not less than 2.50 to 1.00

For purposes of calculating the financial maintenance covenants prior to the fiscal quarter ending June 30, 2020, EBITDA (as defined in the Rattler credit agreement) will be annualized based on the actual EBITDA for the preceding fiscal quarters starting with the fiscal quarter ending September 30, 2019.

As of December 31, 2019, Rattler and Rattler LLC were in compliance with all financial covenants under the Rattler credit agreement. The lenders may accelerate all of the indebtedness under the Rattler credit agreement upon the occurrence and during the continuance of any event of default. The Rattler credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change in control.

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 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, 2019, CEMOF had funded approximately $36 million. As of December 31, 2019, eleven joint wells have been drilled and completed.

F-35

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Interest expense

The following amounts have been incurred and charged to interest expense for the years ended December 31, 2019, 2018 and 2017:

	Year Ended December 31,
	2019				2018				2017
	(in millions)
Interest expense	$	235			$	110			$	61
Less capitalized interest	(66		)		(32		)		(22		)
Other fees and expenses	4				10				2
Total interest expense	$	173			$	88			$	41

11. CAPITAL STOCK AND EARNINGS PER SHARE

The Company did not complete any equity offerings during the years ended December 31, 2019, 2018 and 2017.

Viper Equity Offerings

For information regarding Viper’s completed equity offerings during the years ended December 31, 2019, 2018 and 2017, refer to Note 4—Viper Energy Partners LP.

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 Viper are included in the consolidated earnings per share computation based on the consolidated group’s holdings of the subsidiary.

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

	Year Ended December 31,
	2019				2018				2017
	(In millions, except per share amounts, shares in thousands)
Net income attributable to common stock	$	240			$	846			$	482
Weighted average common shares outstanding:
Basic weighted average common units outstanding	163,493				104,622				97,458
Effect of dilutive securities:
Potential common shares issuable	350				307				230
Diluted weighted average common shares outstanding	163,843				104,929				97,688
Basic net income attributable to common stock	$	1.47			$	8.09			$	4.95
Diluted net income attributable to common stock	$	1.47			$	8.06			$	4.94

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,
	2019			2018			2017
	(in thousands)
Restricted stock units	284			14			46

F-36

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

12. 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 1,313,588 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,
	2019				2018				2017
	(In millions)
General and administrative expenses	$	48			$	27			$	25
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	$	17			$	10			$	9

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, 2019:

	Restricted Stock Awards & Units			Weighted Average Grant-Date Fair Value
Unvested at December 31, 2018	324,224			$	116.01
Granted	697,679			$	99.36
Vested	(425,608	)		$	105.09
Forfeited	(90,428	)		$	106.55
Unvested at December 31, 2019	505,867			$	96.01

The aggregate fair value of restricted stock units that vested during the years ended December 31, 2019, 2018 and 2017 was $45 million, $19 million and $15 million, respectively. As of December 31, 2019, the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $38 million. Such cost is expected to be recognized over a weighted-average period of 2.2 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 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 vested at December 31, 2019.

F-37

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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.

In March 2019, eligible employees received performance restricted stock unit awards totaling 199,723 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, 2019 to December 31, 2021 and cliff vest at December 31, 2021. In March 2019, eligible employees received performance restricted stock unit awards totaling 32,958 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, 2019 to December 31, 2021 and vest in five equal installments beginning on March 1, 2025.

The fair value of each performance restricted stock unit is estimated at the date of grant using a Monte Carlo simulation, which results in an expected percentage of units to be earned during the performance period.

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

	2019				2018				2017
	Three-Year Performance Period				Three-Year Performance Period				Two-Year Performance Period				Three-Year Performance Period
Grant-date fair value	$	137.22			$	170.45			$	162.13			$	168.73
Grant-date fair value (5-year vesting)	$	132.48
Risk-free rate	2.55		%		1.99		%		1.27		%		1.59		%
Company volatility	35.00		%		35.90		%		39.32		%		41.14		%

The following table presents the Company’s performance restricted stock unit activity under the Equity Plan for the year ended December 31, 2019:

	Performance Restricted Stock Units			Weighted Average Grant-Date Fair Value
Unvested at December 31, 2018	196,203			$	169.76
Granted	356,227			$	131.30
Vested	(176,976	)		$	93.32
Forfeited	(103,635	)		$	155.23
Unvested at December 31, 2019(1)	271,819			$	147.07

(1)	A maximum of 543,638 units could be awarded based upon the Company’s final TSR ranking.

As of December 31, 2019, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $24 million. Such cost is expected to be recognized over a weighted-average period of 2.6 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.

F-38

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

The following table presents a summary of stock appreciation rights activity during the year ended December 31, 2019:

	Shares			Weighted Average Exercise Price
Outstanding at December 31, 2018	57,721			$	22.12
Exercised	(11,399	)		$	70.69
Expired	(3,775	)		$	96.91
Outstanding at December 31, 2019	42,547			$	90.89

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 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 millions)
Outstanding at December 31, 2018	332,387			$	95.04
Exercised	(116,044	)		$	82.29
Outstanding at December 31, 2019	216,343			$	89.90			1.67		$	—
Vested and Expected to vest at December 31, 2019	216,343			$	89.90			1.67		$	—
Exercisable at December 31, 2019	216,343			$	89.90			1.67		$	—

Viper Long-Term Incentive Plan

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 Viper. 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 8,892,918 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.

Under the Viper LTIP, the Board of Directors of Viper’s General Partner is authorized to issue phantom units to eligible employees. Viper estimates the fair value of phantom units as the closing price of Viper’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 Viper for each phantom unit.

F-39

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

The following table presents the phantom unit activity under the Viper LTIP for the year ended December 31, 2019:

	Phantom Units			Weighted Average Grant-Date Fair Value
Unvested at December 31, 2018	125,053			$	23.44
Granted	56,582			$	30.33
Vested	(85,359	)		$	23.96
Forfeited	(1,028	)		$	42.50
Unvested at December 31, 2019	95,248			$	26.87

The aggregate fair value of phantom units that vested during the year ended December 31, 2019 was $2 million. As of December 31, 2019, the unrecognized compensation cost related to unvested phantom units was $1 million. Such cost is expected to be recognized over a weighted-average period of 1.0 years.

Rattler Long-Term Incentive Plan

On May 22, 2019, the board of directors of Rattler’s General Partner adopted the Rattler Midstream LP Long Term Incentive Plan (“Rattler LTIP”), for employees, consultants and directors of Rattler’s General Partner and any of its affiliates, including Diamondback, who perform services for Rattler. The Rattler 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.

Under the Rattler LTIP, the board of directors of Rattler’s General Partner is authorized to issue phantom units to eligible employees and non-employee directors. Rattler estimates the fair value of phantom units as the closing price of Rattler’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 to one common unit of Rattler for each phantom unit. The recipients are also entitled to distribution equivalent rights, which represent the right to receive a cash payment equal to the value of the distributions paid on one phantom unit between the grant date and the vesting date.

The following table presents the phantom unit activity under the Rattler LTIP for the year ended December 31, 2019:

	Phantom Units			Weighted Average Grant-Date Fair Value
Unvested at May 28, 2019	—			$	—
Granted	2,284,038			$	19.14
Forfeited	(57,143	)		$	19.21
Unvested at December 31, 2019	2,226,895			$	19.14

As of December 31, 2019, the unrecognized compensation cost related to unvested phantom units was $37 million. Such cost is expected to be recognized over a weighted-average period of 2.4 years.

13. RELATED PARTY TRANSACTIONS

Advisory Services Agreement - Viper

In connection with the closing of the Viper Offering, Viper and Viper’s General Partner entered into an advisory services agreement (the “Viper Advisory Services Agreement”) with Wexford, dated as of June 23, 2014, under which Wexford provided Viper and Viper’s General Partner with general financial and strategic advisory services related to the business in return for an annual fee of $500,000, plus reasonable out-of-pocket expenses. The Advisory Services Agreement was terminated on November 12, 2018 and Viper’s payment obligation ended in June 2019. During 2019, Viper did not pay any amounts under the Advisory Services Agreement. For the year ended December 31, 2018, Viper did not pay any amounts under the Advisory Services Agreement.

F-40

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Lease Bonus - Viper

During the year ended December 31, 2019, the Company paid Viper $277,977 in lease bonus payments to extend the term of six leases and $182,646 in lease bonus payments for four new leases. During the year ended December 31, 2018, the Company paid Viper $3 million in lease bonus payments to extend the term of 13 leases and less than $1 million in lease bonus payments for one new lease. During the year ended December 31, 2017, the Company paid Viper $105,690 in lease bonus payments to extend the term of two leases.

Please see Note 4—Viper Energy Partners LP for additional information regarding relationships between the Company and Viper.

Rattler Offering

Please see Note 5—Rattler Midstream LP for information regarding relationships between the Company and Rattler.

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 Viper, Viper LLC, Rattler and Rattler LLC, file a federal corporate income tax return on a consolidated basis. As discussed further below, Viper 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 Viper LLC. Subsequent to Rattler’s election to be treated as a corporation for federal income tax purposes effective May 24, 2019, Rattler is also a taxable entity and as such files a federal corporate income tax return including the activity of its investment in Rattler LLC. Viper’s and Rattler’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. 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 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 $68 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 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 did not made any adjustments to the provisional amounts recorded December 31, 2017.

The Company’s effective income tax rates were 13.0% and 15.1% for the years ended December 31, 2019 and 2018, respectively. Total income tax expense for the year ended December 31, 2019 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to the revision of estimated deferred taxes recognized as a result of Viper’s change in tax status, and state income taxes net of federal benefit. Total income tax expense for the year ended December 31, 2018 differed from amounts computed by applying the United States federal statutory rate to pre-tax income for the period primarily due to the impact of deferred taxes recognized as a result of Viper’s change in tax status, net income attributable to the noncontrolling interest, and state income taxes net of federal benefit.

F-41

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

The components of the Company’s consolidated provision for income taxes from continuing operations for the years ended December 31, 2019, 2018 and 2017 are as follows:

	Year Ended December 31,
	2019				2018				2017
	(In millions)
Current income tax provision (benefit):
Federal	$	—			$	—			$	—
State	—				—				—
Total current income tax provision (benefit)	—				—				—
Deferred income tax provision (benefit):
Federal	40				160				(21		)
State	7				8				1
Total deferred income tax provision (benefit)	47				168				(20		)
Total provision for (benefit from) income taxes	$	47			$	168			$	(20	)

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

	Year Ended December 31,
	2019				2018				2017
	(In millions)
Income tax expense at the federal statutory rate(1)	$	76			$	234			$	174
Impact of nontaxable noncontrolling interest	—				(5		)		(12		)
Income tax benefit relating to change in statutory tax rate	—				—				(68		)
State income tax expense, net of federal tax effect	6				8				3
Non-deductible compensation	4				5				13
Change in valuation allowance	—				—				(127		)
Deferred taxes related to change in Viper LP's tax status	(42		)		(73		)		—
Other, net	3				(1		)		(3		)
Provision for (benefit from) income taxes	$	47			$	168			$	(20	)

(1)	The federal statutory rates for the years ended December 31, 2019, 2018 and 2017 were 21%, 21% and 35%, respectively.

F-42

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, 2019 and 2018 are as follows:

	December 31,
	2019				2018
	(In millions)
Deferred tax assets:
Net operating loss and other carryforwards	$	453			$	155
Stock based compensation	7				7
Viper LP's investment in Viper LLC	134				94
Other	11				9
Deferred tax assets	605				265
Valuation allowance	(7		)		(14		)
Deferred tax assets, net of valuation allowance	598				251
Deferred tax liabilities:
Oil and natural gas properties and equipment	2,275				1,825
Midstream investments	50				67
Derivative instruments	6				47
Rattler LP's investment in Rattler LLC	8				—
Other	3				—
Total deferred tax liabilities	2,342				1,939
Net deferred tax liabilities	$	1,744			$	1,688

The Company had net deferred tax liabilities of approximately $1.7 billion at December 31, 2019 and 2018. 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 $1.4 billion associated with the acquired assets, which includes deferred tax assets related to tax attributes acquired from Energen. As of December 31, 2019, the Company has completed its purchase price allocation for the acquisition, including an increase of $23 million to the deferred tax liability as a result of adjustments to fair value of the acquired assets.

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 as a result of its loss, nor is there any current federal income tax payable. At December 31, 2019, the Company had approximately $400 million of federal NOLs expiring in 2032 through 2037 and $1.3 billion 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’s federal tax attributes acquired from Energen are subject to an annual limitation under 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. The Company believes that the application of Section 382 will not have an adverse effect on future usage of the Company’s NOLs and credits, including federal tax attributes acquired from Energen. The Company’s minimum tax credits, including those acquired from Energen, are classified as $19 million current and $19 million noncurrent income tax receivables on the balance sheet.

As of December 31, 2019, the Company has a valuation allowance of $7 million primarily related to certain state NOL carryforwards 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 of December 31, 2019, management determined that it is more likely than not that the Company will realize its remaining deferred tax assets.

As discussed further in Note 4—Viper Energy Partners LP, on March 29, 2018, Viper announced that the Board of Directors of its General Partner had unanimously approved a change of Viper’s federal income tax status from that of a pass-

F-43

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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 Viper’s tax status were not taxable to the Company. Subsequent to Viper’s change in tax status, Viper’s provision for income taxes for the periods ended December 31, 2018 and 2019 are based on its estimated annual effective tax rate plus discrete items. As such, Viper’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, 2019, the Company’s net deferred tax liabilities include a deferred tax asset of approximately $134 million related to Viper’s investment in Viper LLC, approximately $115 million of which was recorded as a result of Viper’s change in tax status. Under federal income tax provisions applicable to Viper’s change in tax status, Viper’s basis for federal income tax purposes in its interest in Viper LLC consisted primarily of the sum of Viper’s unitholders’ tax bases in their interests in Viper on the date of the tax status change. Viper prepared its best estimate of the tax basis in Viper LLC for purposes of Viper’s income tax provision for the period of the change, but information necessary for Viper to finalize its determination was not available until unitholders’ tax basis information was fully reported and Viper finalized its federal income tax computations for 2018. Based on such finalized information as of the third quarter 2019, Viper revised its estimate of the difference between its tax basis and its basis for financial accounting purposes in Viper LLC on the date of the tax status change, resulting in deferred income tax benefit of $42 million included in the Company’s consolidated income tax provision for the year ended December 31, 2019. As of December 31, 2019, Viper has federal net operating loss carryforwards of approximately $38 million which may be carried forward indefinitely to offset future taxable income.

As discussed further in Note 5—Rattler Midstream LP, on May 28, 2019, Rattler completed its initial public offering. Even though Rattler is organized as a limited partnership under state law, Rattler is subject to U.S. federal and state income tax at corporate rates, subsequent to the effective date of Rattler’s election to be treated as a corporation for U.S. federal income tax purposes. As such, Rattler’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, 2019, the Company’s net deferred tax liabilities include a deferred tax liability of approximately $8 million related to Rattler’s investment in Rattler LLC. Subsequent to the deemed formation of Rattler LLC as a partnership for federal income tax purposes upon Rattler’s IPO, deferred taxes are no longer provided on the underlying assets and liabilities of Rattler LLC but are provided on the difference between Rattler’s basis for financial accounting purposes and basis for federal income tax purposes in its investment in Rattler LLC. Rattler incurred an NOL in the current year due principally to Rattler LLC’s tax deductions for accelerated depreciation, which exceeded its other items of taxable income. At December 31, 2019, Rattler has federal net operating loss carryforwards of approximately $1 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,
	2019				2018
	(in millions)
Balance at beginning of year	$	7			$	—
Increase resulting from tax positions acquired	—				7
Increase resulting from prior period tax positions	—				—
Increase resulting from current period tax positions	—				—
Balance at end of year	7				7
Less: Effects of temporary items	(5		)		(5		)
Total that, if recognized, would impact the effective income tax rate as of the end of the year	$	2			$	2

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.

F-44

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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, 2019 and 2018, there were no penalties and less than $1 million and $0 million of interest, respectively, associated with uncertain tax positions recognized in the Company’s consolidated 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.”

Commodity Contracts

The Company has used fixed price swap contracts, fixed price basis swap contracts, double-up swap contracts and three-way costless collars with corresponding put, short put and call options to reduce price volatility associated with certain of its oil and natural gas sales. With respect to the Company’s fixed price swap contracts and fixed price basis swap contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap or basis price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap or basis price. The Company has fixed price basis swaps for the spread between the WTI 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. The Company also utilizes double-up swap contracts for a portion of its natural gas sales. These contracts include a traditional fixed price swap in addition to a call option at the same quantity and price, providing the counterparty the option to double the volume in the swap contract should the monthly settlement price exceed the fixed price contracted upon.

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 the New York Mercantile Exchange Henry Hub 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.

F-45

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

As of December 31, 2019, the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed:

	2020						2021
	Volume (Bbls/MMBtu)		Fixed Price Swap (per Bbl/MMBtu)				Volume (Bbls/MMBtu)		Fixed Price Swap (per Bbl/MMBtu)
Oil Swaps - WTI Cushing	4,754,000		$	57.78			0		$	—
Oil Swaps - WTI Magellan East Houston	2,196,000		$	62.80			0		$	—
Oil Swaps - BRENT	4,569,000		$	61.84			0		$	—
Oil Basis Swaps - WTI Cushing	13,860,000		$	(1.20	)		0		$	—
Oil Rolling Hedge - WTI Cushing	6,700,000		$	0.44			0		$	—
Natural Gas Swaps - Henry Hub	10,050,000		$	2.55			0		$	—
Natural Gas Swaps - Waha Hub	16,750,000		$	1.67			0		$	—
Natural Gas Basis Swaps - Waha Hub	23,450,000		$	(1.19	)		54,750,000		$	(0.70	)

	2020
Oil Three-Way Collars	WTI Cushing				Brent				WTI Magellan East Houston
Volume (Bbls)	6,842,200				11,803,500				5,124,000
Short put price (per Bbl)	$	44.20			$	50.00			$	50.00
Floor price (per Bbl)	$	54.20			$	60.00			$	60.00
Ceiling price (per Bbl)	$	65.42			$	70.86			$	68.61

Gas Swap Double-Up - Waha Hub	2020
Volume (Mcf)	10,050,000
Swap price (per Mcf)	$	1.70
Option price	$	1.70

Interest Rate Swaps and Treasury Locks

The Company has used interest rate swaps and treasury locks to reduce the Company’s exposure to variable rate interest payments associated with the Company’s revolving credit facility. The interest rate swaps and treasury locks have not been designated as hedging instruments and as a result, the Company recognizes all changes in fair value immediately in earnings. Effective November 2019, the Company terminated all of its interest rate swaps and treasury locks which resulted in a gain of $43 million, net of fees.

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, 2019 and 2018:

	December 31,
	2019				2018
	(in millions)
Gross amounts of assets presented in the Consolidated Balance Sheet	$	71			$	233
Amounts netted in the Consolidated Balance Sheet	(18		)		(2		)
Net amounts of assets presented in the Consolidated Balance Sheet	$	53			$	231
Gross amounts of liabilities presented in the Consolidated Balance Sheet	$	45			$	15
Amounts netted in the Consolidated Balance Sheet	(18		)		—
Net amounts of liabilities presented in the Consolidated Balance Sheet	$	27			$	15

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,
	2019				2018
	(in millions)
Current assets: derivative instruments	$	46			$	231
Noncurrent assets: derivative instruments	7				—
Total assets	$	53			$	231
Current liabilities: derivative instruments	$	27			$	—
Noncurrent liabilities: derivative instruments	—				15
Total liabilities	$	27			$	15

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,
	2019				2018				2017
	(in thousands)
Change in fair value of open non-hedge derivative instruments:	$	(188	)		$	222			$	(84	)
Gain (loss) on settlement of non-hedge derivative instruments:	80				(121		)		6
Gain (loss) on derivative instruments	$	(108	)		$	101			$	(78	)

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.

F-47

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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

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

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

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

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

The Company estimates asset retirement obligations pursuant to the provisions of the Financial Accounting Standards Board issued Accounting Standards Codification Topic 410, “Asset Retirement and Environmental Obligations”. The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with the future plugging and abandonment of wells and related facilities. Given the unobservable nature of the inputs, including plugging costs and useful lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 8—Asset Retirement Obligations for further discussion of the Company’s asset retirement obligations.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments and Viper’s cost method investment. The fair value of Viper’s investment is determined using quoted market prices. These valuations are Level 1 inputs. 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, 2019 and 2018:

	December 31, 2019										December 31, 2018
	Level 1			Level 2			Level 3				Level 1			Level 2			Level 3
	(in millions)
Assets:
Investment	$	19		$	—		$	—			$	14		$	—		$	—
Fixed price swaps	$	—		$	26		$	—			$	—		$	216		$	—
Liabilities:
Fixed price swaps	$	—		$	—		$	—			$	—		$	—		$	—

F-48

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

The following table summarizes the changes in fair value of Viper’s cost method investment during the periods presented:

	(in millions)
Value at December 31, 2018	$	14
Gain on investment	5
Value at December 31, 2019	$	19
Value at December 31, 2017	$	34
Impact of adoption of Accounting Standards Update 2016-01	(19		)
Loss on investment	(1		)
Value at December 31, 2018	$	14

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, 2019								December 31, 2018
	Carrying								Carrying
	Amount				Fair Value				Amount				Fair Value
	(in thousands)
Debt:
Revolving credit facility	$	13			$	13			$	1,490			$	1,490
4.625% Notes due 2021	399				411				400				393
7.320% Medium-term Notes, Series A, due 2022	21				22				20				21
2.875% Senior Notes due 2024(1)	992				1,012				—				—
4.750% Senior Notes due 2024(1)	—				—				1,236				1,204
5.375% Senior Notes due 2025(1)	799				840				799				782
3.250% Senior Notes due 2026(1)	792				812				—				—
7.350% Medium-term Notes, Series A, due 2027	11				12				10				11
7.125% Medium-term Notes, Series B, due 2028	108				116				100				102
3.500% Senior Notes due 2029(1)	1,186				1,226				—				—
Viper revolving credit facility	97				97				411				411
Viper's 5.375% Senior Notes due 2027	490				521				—				—
Rattler revolving credit facility	424				424				—				—
DrillCo Agreement	$	39			$	39			$	—			$	—

(1)	The carrying value includes associated deferred loan costs and any discount.

The fair value of the revolving credit facility, the Viper credit agreement and the Rattler credit agreement 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, 2019 quoted market price, a Level 1 classification in the fair value hierarchy.

17. LEASES

The Company leases certain drilling rigs, facilities, compression and other equipment.

As discussed in Note 2—Summary of Significant Accounting Policies, the Company adopted ASU 2016-02, ASU 2018-11 and ASU 2019-01 on January 1, 2019 using the optional transition method of adoption. The Company elected a package of practical expedients that together allows an entity to not reassess (i) whether a contract is or contains a lease, (ii) lease classification and (iii) initial direct costs. In addition, the Company elected the following practical expedients: (i) to not reassess

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

certain land easements; (ii) to not apply the recognition requirements under the standard to short-term leases; (iii) to not reassess lease terms on leases entered into prior to the effective date of adoption; and (iv) lessor accounting policy election to exclude lessor costs paid directly by the lessee.

For leases where the Company is the lessee, the Company recorded a total of $13 million in right-of-use assets and corresponding new lease liabilities in other on its Condensed Consolidated Balance Sheet representing the present value of its future operating lease payments. Adoption of the standards did not require an adjustment to the opening balance of retained earnings. The discount rate used to determine present value was based on the rate of interest that the Company estimated it would have to pay to borrow (on a collateralized-basis over a similar term) an amount equal to the lease payments in a similar economic environment as of January 1, 2019. The Company is required to reassess the discount rate for any new and modified lease contracts as of the lease effective date.

The right-of-use assets and lease liabilities recognized upon adoption of ASU 2016-02 were based on the lease classifications, lease commitment amounts and terms recognized under the prior lease accounting guidance. Leases with an initial term of twelve months or less are considered short-term leases and are not recorded on the balance sheet.

The following table summarizes operating lease costs for the year ended December 31, 2019:

	Year Ended December 31, 2019
	(in millions)
Operating lease costs	$	26

For the year ended December 31, 2019, cash paid for operating lease liabilities, and reported in cash flows provided by operating activities on the Company's Statement of Condensed Consolidated Cash Flows, was $26 million. During the year ended December 31, 2019, the Company recorded an additional $17 million of right-of-use assets in exchange for new lease liabilities.

The operating lease right-of-use assets were reported in other assets and the current and noncurrent portions of the operating lease liabilities were reported in other accrued liabilities and other long-term liabilities, respectively, on the Condensed Consolidated Balance Sheet. As of December 31, 2019, the operating right-of-use assets were $15 million and operating lease liabilities were $15 million, of which $8 million was classified as current. As of December 31, 2019, the weighted average remaining lease term was 2.1 years and the weighted average discount rate was 8.2%.

Schedule of Operating Lease Liability Maturities. The following table summarizes undiscounted cash flows owed by the Company to lessors pursuant to contractual agreements in effect as of December 31, 2019:

	As of December 31, 2019
	(in millions)
2020	$	9
2021	5
2022	2
2023	—
2024	—
Thereafter	—
Total lease payments	16
Less: interest	1
Present value of lease liabilities	$	15

For leases in which the Company is the lessor, the Company (i) retained classification of our historical leases as we are not required to reassess classification upon adoption of the new standard, (ii) expensed indirect leasing costs in connection with new or extended tenant leases, the recognition of which would have been deferred under prior accounting guidance and (iii) aggregated revenue from our lease components and non-lease components (comprised of tenant expense reimbursements) into revenue from rental properties.

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

18. COMMITMENTS AND CONTINGENCIES

The Company is a party to various legal proceedings, disputes and claims arising in the course of its business, including those that arise from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry, personal injury claims, title disputes, royalty disputes, contract claims, contamination claims relating to oil and gas exploration and development and environmental claims, including claims involving assets owned by acquired companies and claims involving assets previously sold to third parties and no longer part of the Company’s current operations. While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on the Company, cannot be predicted with certainty, the Company believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Company’s financial condition, cash flows or results of operations. The Company’s assessment is based on information known about the pending matters and its experience in contesting, litigating and settling similar matters. Actual outcomes could differ materially from the Company’s assessment. The Company records reserves for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated. The Company reassesses the probability and estimability of contingent losses as new information becomes available.

Commitments

The following is a schedule of minimum future payments with commitments that have initial or remaining noncancelable terms in excess of one year as of December 31, 2019:

Year Ending December 31,	Sand Supply Agreement
	(in millions)
2020	$	18
2021	18
2022	18
2023	18
2024	18
Thereafter	23
Total	$	113

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.

The following table presents rent expense for the years ended December 31, 2019, 2018 and 2017:

	Year ended December 31,
	2019				2018				2017
	(in millions)
Rent Expense	$	3			$	1			$	2

Agreement with Trafigura Trading LLC

The Company has entered into a firm commitment oil purchase agreement with Trafigura Trading LLC (“Trafigura”) in which the Company agreed to sell and deliver a firm quantity of 25,000 barrels of crude oil per day 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 us 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.

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Agreement with Plains Marketing LP

In July 2019, the Company’s wholly-owned subsidiary, Energen Resources Corporation (“Energen Resources”) entered into a long-term crude oil sales agreement with Plains Marketing LP (“Plains”) pursuant to which, among other things, the Company’s existing agreements with Plains were terminated. The Company’s new agreement with Plains requires that it makes available 50,000 barrels of crude oil per day until the date occurring ten years following the date service commences for ExxonMobil Oil Corporation (“Exxon”) pursuant to the transportation service agreement between Exxon and the Wink to Webster pipeline carrier (plus extensions for force majeure). 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 or acts or omissions of Plains, the Company has agreed to pay Plains a specified per barrel amount, subject to escalation, multiplied by the deficiency volume. If during the term of the agreement the Company fails to deliver the quantities of oil for any month that it has committed for such month other than for specified force majeure events or acts or omissions of Plains, the Company has agreed to pay Plains a deficiency payment . The Company has also dedicated certain crude oil production attributable to certain of its interests to Plains in connection with this agreement. Pricing for the Company’s production under the Plains agreement (i) prior to the date service commences for Exxon pursuant to the transportation service agreement between Exxon and the Wink to Webster pipeline carrier, is at a Midland WTI or WTL, as applicable, base price less certain costs and (ii) following the date service commences for Exxon pursuant to the transportation service agreement between Exxon and the Wink to Webster pipeline carrier, for volumes up to 100,000 barrels of crude oil per day, is at a MEH WTI or WTL base price, as applicable, less certain costs.

Agreement with Shell Trading (USA) Company

In December 2018, the Company entered into an oil purchase agreement with Shell Trading (USA) Company (“Shell”) which was amended and restated in December 2019, in which Shell agreed to transport crude oil it purchases from us through the EPIC pipeline, with which the Company has an agreement for the transportation of certain crude oil. The Company’s agreement with Shell provides for different purchase obligations during the pre-commencement and service commencement periods for the EPIC pipeline, and provides for a three-year term beginning on the service commencement date for the EPIC pipeline. Shell has the option to extend its purchase obligations for up to three one-year terms, but not beyond March 31, 2026 except in the event of force majeure. The Company’s delivery obligation (i) prior to the full service commencement of the EPIC pipeline will be, subject to certain conditions, including the Company’s right to repurchase certain volumes, either 30,000 or 40,000 barrels of crude oil per day and (ii) during the full service term will not exceed 50,000 barrels of crude oil per day. In addition, the Company’s wholly-owned subsidiary Energen Resources has signed an agreement with Shell in which all or a portion of the 50,000 barrels of crude oil per day referenced in the previous sentence could also be satisfied by Energen Resources. During different pre-commencement periods, Shell has agreed to pay the Company the price per barrel of oil based on the arithmetic average of the daily settlement price for the “Light Sweet Crude Oil” Prompt Month future contracts reported by the NYMEX over the applicable one-month period, subject to certain adjustments, plus a Corpus Christi differential determined based on Shell’s average sales price for its WTI barrels in Corpus Christi less certain other costs, expenses and fees. During the full service term, the price per barrel of oil payable by Shell to the Company is based on calendar dated Brent pricing plus a negotiated differential generally based on certain Argus WTI Houston CIF Rotterdam and Platts Midland DAP Rotterdam pricing, less certain adjustments.

Agreement with Vitol Inc.

On October 18, 2018, the Company entered into an agreement with Vitol to, among other things, sell an average of 23,750 barrels of crude oil per day plus other agreed upon volumes. The Company is continuing to sell crude to Vitol on a month-to-month basis and expects to continue to do so under its existing arrangement with Vitol until its new agreement with Vitol becomes effective. Under the Company’s new agreement with Vitol, the Company agreed to sell, and Vitol agreed to purchase, (i) subject to certain conditions, including accelerated commissioning service on the Gray Oak pipeline and completion of certain infrastructure connections, 50,000 barrels of crude oil per day on average during each month occurring during the first seven years of full service on the Gray Oak pipeline, (ii) subject to certain conditions and the satisfaction of other conditions, including full service on the Gray Oak pipeline and completion of certain infrastructure connections, an additional 50,000 barrels of crude oil per day on average during each month occurring during the first seven years following satisfaction of such conditions, (iii) subject to certain conditions, including notice that transportation services on the EPIC pipeline are ready to commence and completion of certain infrastructure connections, an additional 50,000 barrels of crude oil per day on average during each month occurring during the first seven years following satisfaction of such conditions and (iv) such other volumes of crude oil as agreed by the parties. The Company is entitled to receive payment for such crude oil under netback pricing, whereby the price for the Company’s crude oil is determined based on a formula which takes into consideration the final purchase price obtained by Vitol in marketing such crude oil in certain third party transactions less certain costs. In connection therewith, Vitol has agreed to,

F-52

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

among other things, use commercially reasonable efforts to (i) maximize the final purchase price to the Company and mitigate any costs factored into the price determination and (ii) acquire third party crude oil to cover any shortfall below the Company’s volumes commitments. Vitol also agrees to (i) use the same care and apply the same policies as it would exercise and apply if it were trading the subject crude oil for Vitol’s own account and (ii) transport such crude oil on certain designated pipelines, including the Gray Oak pipeline pursuant to rights we have obtained through our Gray Oak transportation services agreement described below under third party shipper rights or term assignments, as applicable, prior to Vitol’s downstream marketing activities.

Transportation Services Agreement with Gray Oak Pipeline, LLC

Pursuant to an addendum, dated as of August 13, 2018, to the transportation services agreement with Gray Oak Pipeline, LLC, dated as of April 23, 2018 (the “Gray Oak TSA 1”), Diamondback E&P LLC agreed to accelerated commissioning service (“ACS”) on the Gray Oak pipeline in the amount of 50,000 barrels of crude oil per day. Under the ACS program, shippers must make a deficiency payment for any barrels not shipped during the ACS term, which expires the day before the Gray Oak pipeline goes into full service, which is currently anticipated to occur in the second quarter of 2020. The ACS commenced on November 12, 2019 and is ongoing. Due to restrictive API gravity provisions and the lack of markets, Diamondback E&P LLC has been unable to ship any volumes over the Gray Oak pipeline since the inception of ACS. This has resulted in Diamondback E&P LLC owing deficiency payments to Gray Oak Pipeline, LLC during 2019 in the aggregate amount of $11 million. The deficiency payment rate varies depending upon the month in which the deficiency occurs. Certain deficiencies can be used as a credit against volumes shipped in excess of a customer’s minimum contract volume each quarter during the first two years of full service on the Gray Oak pipeline, subject to certain restrictions.

Once full service commences on the Gray Oak pipeline, subject to the terms and conditions of the Gray Oak TSA 1, Diamondback E&P LLC will be required to ship 50,000 barrels per day of crude oil on the Gray Oak pipeline or pay a deficiency payment for any shortfall in volumes as measured on a quarterly basis. Such deficiency payments can be used as a credit against future shipments in excess of our minimum contract volume each quarter, subject to certain restrictions.

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, 2019, 2018 and 2017 the Company paid $8 million, $2 million and $2 million, respectively, in contributions to the plan.

19. SUBSEQUENT EVENTS

Fourth Quarter 2019 Dividend Declaration

On February 14, 2020, the Board of Directors of the Company declared a cash dividend for the fourth quarter of 2019 of $0.3750 per share of common stock, payable on March 10, 2020 to its stockholders of record at the close of business on March 3, 2020.

Commodity Contracts

Subsequent to December 31, 2019, the Company entered into new fixed price swaps, fixed price basis swaps, three-way collars and put spreads. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on WTI and Crude Oil Brent and gas derivative settlements based on Waha Hub and Brent.

F-53

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, 2019. When aggregating multiple contracts, the weighted average contract price is disclosed.

	2020
	Volume (Bbls/MMBtu)		Fixed Price Swap (per Bbl/MMBtu)
Oil Swaps - WTI Cushing	732,000		$	60.50
Oil Swaps - BRENT	732,000		$	65.00
Natural Gas Swaps - Waha Hub	1,840,000		$	0.75
Natural Gas Basis Swaps - Waha Hub	13,750,000		$	(1.85	)
Diesel Price Swaps	11,000,000		$	1.60

	2020
Oil Three-Way Collars	Brent
Volume (Bbls)	732,000
Short put price (per Bbl)	$	50.00
Floor price (per Bbl)	$	60.00
Ceiling price (per Bbl)	$	69.25

	2020
Oil Put Spreads - WTI
Volume (Bbls)	829,125
Short put price (per Bbl)	$	50.50
Floor price (per Bbl)	$	60.50
Oil Put Spreads - Brent
Volume (Bbls)	1,758,750
Short put price (per Bbl)	$	52.38
Floor price (per Bbl)	$	65.00

20. REPORT OF BUSINESS SEGMENTS

The Company reports its operations in two business segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas and (ii) the midstream operations segment includes midstream services and real estate. All of Rattler’s equity method investments are included in the midstream segment.

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

The following tables summarize the results of the Company's business segments during the periods presented:

	Upstream				Midstream Services				Eliminations				Total
Year Ended December 31, 2019:	(in millions)
Third-party revenues	$	3,891			$	73			$	—			$	3,964
Intersegment revenues	—				375				(375		)		—
Total revenues	3,891				448				(375		)		3,964
Depreciation, depletion and amortization	$	1,405			$	42			$	—			$	1,447
Impairment of oil and natural gas properties	$	790			$	—			$	—			$	790
Income from operations	$	790			$	219			$	(314	)		$	695
Interest expense, net	$	(171	)		$	(1	)		$	—			$	(172	)
Total other income (expense), net(1)	$	(320	)		$	(7	)		$	(6	)		$	(333	)
Provision for income taxes	$	21			$	26			$	—			$	47
Net income attributable to non-controlling interest	$	75			$	91			$	(91	)		$	75
Net income attributable to Diamondback Energy	$	374			$	95			$	(229	)		$	240
Total assets	$	22,125			$	1,636			$	(230	)		$	23,531

(1)	The impairment for the midstream services segment of $2 million is included in other income (expense).

	Upstream				Midstream Services				Eliminations				Total
Year Ended December 31, 2018:	(in millions)
Third-party revenues	$	2,132			$	44			$	—			$	2,176
Intersegment revenues	—				140				(140		)		—
Total revenues	2,132				184				(140		)		2,176
Depreciation, depletion and amortization	$	598			$	25			$	—			$	623
Income from operations	$	1,071			$	80			$	(140	)		$	1,011
Interest expense, net	$	(87	)		$	—			$	—			$	(87	)
Total other income (expense), net	$	102			$	—			$	—			$	102
Provision for income taxes	$	151			$	17			$	—			$	168
Net income attributable to non-controlling interest	$	99			$	—			$	—			$	99
Net income attributable to Diamondback Energy	$	923			$	63			$	(140	)		$	846
Total assets	$	21,096			$	604			$	(104	)		$	21,596

F-55

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

	Upstream				Midstream Services				Eliminations				Total
Year Ended December 31, 2017:	(in millions)
Third-party revenues	$	1,198			$	7			$	—			$	1,205
Intersegment revenues	—				32				(32		)		—
Total revenues	1,198				39				(32		)		1,205
Depreciation, depletion and amortization	$	324			$	3			$	—			$	327
Income from operations	$	613			$	24			$	(32	)		$	605
Interest expense, net	$	(41	)		$	—			$	—			$	(41	)
Total other income (expense), net	$	(109	)		$	1			$	—			$	(108	)
Provision for income taxes	$	(24	)		$	4			$	—			$	(20	)
Net income attributable to non-controlling interest	$	35			$	—			$	—			$	35
Net income attributable to Diamondback Energy	$	493			$	21			$	(32	)		$	482
Total assets	$	7,475			$	300			$	(4	)		$	7,771

21. GUARANTOR FINANCIAL STATEMENTS

As of December 31, 2019, Diamondback O&G LLC is a guarantor under the indenture relating to the Series of Senior Notes. In connection with the satisfaction and discharge of the indenture governing the 2024 Senior Notes, Diamondback E&P LLC and Energen Corporation and its subsidiaries were released as guarantors under the 2024 Senior Notes, the 2025 Senior Notes and Diamondback O&G LLC’s revolving credit facility. Rattler LLC was released as a guarantor under Diamondback O&G LLC’s credit agreement on May 28, 2019. Viper, Viper’s General Partner, Viper LLC, Rattler, Rattler’s General Partner and Rattler’s subsidiaries remain Non-Guarantor Subsidiaries. The following presents condensed consolidated financial information for the Company (which for purposes of this Note 21 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.

None of Rattler, Rattler’s General Partner or Rattler’s subsidiaries were guarantors under the 2024 Senior Notes, the 2025 Senior Notes or Diamondback O&G LLC’s revolving credit facility for the previous periods presented; therefore, the schedules that follow have been adjusted to reflect this correction of an immaterial change. Rattler LLC was a guarantor under Diamondback O&G LLC’s credit agreement until May 28, 2019.

F-56

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Condensed Consolidated Balance Sheet
December 31, 2019
(In millions)
									Non–
					Guarantor				Guarantor
	Parent				Subsidiaries				Subsidiaries				Eliminations				Consolidated
Assets
Current assets:
Cash and cash equivalents	$	93			$	—			$	30			$	—			$	123
Restricted cash	5				—				—				—				5
Accounts receivable, net	—				248				367				—				615
Intercompany receivable	5,331				—				572				(5,903		)		—
Inventories	—				1				36				—				37
Derivative instruments	—				46				—				—				46
Prepaid expenses and other	2				1				21				19				43
Total current assets	5,431				296				1,026				(5,884		)		869
Property and equipment:
Oil and natural gas properties, full cost method of accounting	—				13,276				12,707				(201		)		25,782
Midstream assets	—				—				931				—				931
Other property, equipment and land	—				—				125				—				125
Accumulated depletion, depreciation, amortization and impairment	—				(3,167		)		(1,831		)		(5		)		(5,003		)
Net property and equipment	—				10,109				11,932				(206		)		21,835
Equity method investments	—				—				479				—				479
Derivative instruments	—				7				—				—				7
Investment in subsidiaries	10,414				—				—				(10,414		)		—
Investment in real estate, net	—				—				109				—				109
Deferred tax asset	—				—				142				—				142
Other assets	—				10				310				(230		)		90
Total assets	$	15,845			$	10,422			$	13,998			$	(16,734	)		$	23,531
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	—			$	—			$	179			$	—			$	179
Intercompany payable	—				5,930				(27		)		(5,903		)		—
Accrued capital expenditures	—				—				475				—				475
Other accrued liabilities	17				132				155				—				304
Revenues and royalties payable	—				—				278				—				278
Derivative instruments	—				18				8				1				27
Total current liabilities	17				6,080				1,068				(5,902		)		1,263
Long-term debt	3,769				13				1,589				—				5,371
Asset retirement obligations	—				34				60				—				94
Deferred income taxes	470				—				1,416				—				1,886
Other long-term liabilities	—				—				11				—				11
Total liabilities	4,256				6,127				4,144				(5,902		)		8,625
Commitments and contingencies
Stockholders’ equity	11,589				4,295				7,908				(10,543		)		13,249
Non-controlling interest	—				—				1,946				(289		)		1,657
Total equity	11,589				4,295				9,854				(10,832		)		14,906
Total liabilities and equity	$	15,845			$	10,422			$	13,998			$	(16,734	)		$	23,531

F-57

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Condensed Consolidated Balance Sheet
December 31, 2018
(In millions)
									Non–
					Guarantor				Guarantor
	Parent				Subsidiaries				Subsidiaries				Eliminations				Consolidated
Assets
Current assets:
Cash and cash equivalents	$	84			$	2			$	129			$	—			$	215
Accounts receivable, net	—				143				249				—				392
Accounts receivable - related party	—				—				4				(4		)		—
Intercompany receivable	4,469				—				201				(4,670		)		—
Inventories	—				2				35				—				37
Derivative instruments	—				197				34				—				231
Prepaid expenses and other	2				—				48				—				50
Total current assets	4,555				344				700				(4,674		)		925
Property and equipment:
Oil and natural gas properties, full cost method of accounting	—				11,170				11,132				(3		)		22,299
Midstream assets	—				21				679				—				700
Other property, equipment and land	—				1				146				—				147
Accumulated depletion, depreciation, amortization and impairment	—				(2,432		)		(330		)		(12		)		(2,774		)
Net property and equipment	—				8,760				11,627				(15		)		20,372
Equity method investments	—				—				1				—				1
Investment in subsidiaries	12,689				—				112				(12,801		)		—
Deferred tax asset	—				—				97				—				97
Investment in real estate, net	—				—				116				—				116
Other assets	—				10				75				—				85
Total assets	$	17,244			$	9,114			$	12,728			$	(17,490	)		$	21,596
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	—			$	—			$	128			$	—			$	128
Intercompany payable	—				3,939				734				(4,673		)		—
Accrued capital expenditures	—				—				495				—				495
Other accrued liabilities	14				23				216				—				253
Revenues and royalties payable	—				—				143				—				143
Total current liabilities	14				3,962				1,716				(4,673		)		1,019
Long-term debt	2,036				1,490				938				—				4,464
Derivative instruments	—				11				4				—				15
Asset retirement obligations	—				30				106				—				136
Deferred income taxes	382				—				1,403				—				1,785
Other long-term liabilities	—				—				10				—				10
Total liabilities	2,432				5,493				4,177				(4,673		)		7,429
Commitments and contingencies
Stockholders’ equity	14,812				3,621				7,856				(12,589		)		13,700
Non-controlling interest	—				—				695				(228		)		467
Total equity	14,812				3,621				8,551				(12,817		)		14,167
Total liabilities and equity	$	17,244			$	9,114			$	12,728			$	(17,490	)		$	21,596

F-58

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Condensed Consolidated Statement of Operations
Year Ended December 31, 2019
(In millions)
									Non–
					Guarantor				Guarantor
	Parent				Subsidiaries				Subsidiaries				Eliminations				Consolidated
Revenues:
Oil sales	$	—			$	1,972			$	1,318			$	264			$	3,554
Natural gas sales	—				27				31				8				66
Natural gas liquid sales	—				132				114				21				267
Royalty income	—				—				293				(293		)		—
Lease bonus	—				—				4				—				4
Midstream services	—				—				434				(370		)		64
Other operating income	—				—				14				(5		)		9
Total revenues	—				2,131				2,208				(375		)		3,964
Costs and expenses:
Lease operating expenses	—				390				243				(143		)		490
Production and ad valorem taxes	—				130				118				—				248
Gathering and transportation	—				75				34				(21		)		88
Midstream services	—				—				170				(79		)		91
Depreciation, depletion and amortization	—				735				720				(8		)		1,447
Impairment of oil and natural gas properties	—				—				790				—				790
General and administrative expenses	48				1				67				(12		)		104
Asset retirement obligation accretion	—				2				5				—				7
Other operating expense	—				—				4				—				4
Total costs and expenses	48				1,333				2,151				(263		)		3,269
Income (loss) from operations	(48		)		798				57				(112		)		695
Other income (expense):
Interest expense, net	(47		)		(74		)		(51		)		—				(172		)
Other income (expense), net	3				—				2				(7		)		(2		)
Gain on derivative instruments, net	—				(56		)		(52		)		—				(108		)
Gain on revaluation of investment	—				—				5				—				5
Loss on extinguishment of debt	(56		)		—				—				—				(56		)
Income from subsidiaries	764				—				—				(764		)		—
Total other income (expense), net	664				(130		)		(96		)		(771		)		(333		)
Income (loss) before income taxes	616				668				(39		)		(883		)		362
Provision for (benefit from) income taxes	81				—				(33		)		(1		)		47
Net income (loss)	535				668				(6		)		(882		)		315
Net income (loss) attributable to non-controlling interest	—				—				266				(191		)		75
Net income (loss) attributable to Diamondback Energy, Inc.	$	535			$	668			$	(272	)		$	(691	)		$	240

F-59

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Condensed Consolidated Statement of Operations
Year Ended December 31, 2018
(In millions)
									Non–
					Guarantor				Guarantor
	Parent				Subsidiaries				Subsidiaries				Eliminations				Consolidated
Revenues:
Oil sales	$	—			$	1,545			$	87			$	247			$	1,879
Natural gas sales	—				43				5				13				61
Natural gas liquid sales	—				158				9				23				190
Royalty income	—				—				283				(283		)		—
Lease bonus	—				—				6				(3		)		3
Midstream services	—				—				172				(138		)		34
Other operating income	—				—				9				—				9
Total revenues	—				1,746				571				(141		)		2,176
Costs and expenses:
Lease operating expenses	—				230				17				(42		)		205
Production and ad valorem taxes	—				106				27				—				133
Gathering and transportation	—				41				1				(16		)		26
Midstream services	—				—				72				—				72
Depreciation, depletion and amortization	—				472				134				17				623
General and administrative expenses	28				1				38				(2		)		65
Merger and integration expense	18				—				18				—				36
Asset retirement obligation accretion	—				1				1				—				2
Other operating expenses	—				—				3				—				3
Total costs and expenses	46				851				311				(43		)		1,165
Income (loss) from operations	(46		)		895				260				(98		)		1,011
Other income (expense):
Interest expense, net	(43		)		(20		)		(24		)		—				(87		)
Other income (expense), net	1				—				90				(2		)		89
Loss on derivative instruments, net	—				169				(68		)		—				101
Gain on revaluation of investment	—				—				(1		)		—				(1		)
Income from subsidiaries	1,113				—				—				(1,113		)		—
Total other expense, net	1,071				149				(3		)		(1,115		)		102
Income (loss) before income taxes	1,025				1,044				257				(1,213		)		1,113
Provision for (benefit from) income taxes	241				—				(73		)		—				168
Net income (loss)	784				1,044				330				(1,213		)		945
Net income attributable to non-controlling interest	—				—				119				(20		)		99
Net income (loss) attributable to Diamondback Energy, Inc.	$	784			$	1,044			$	211			$	(1,193	)		$	846

F-60

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Condensed Consolidated Statement of Operations
Year Ended December 31, 2017
(In millions)
									Non–
					Guarantor				Guarantor
	Parent				Subsidiaries				Subsidiaries				Eliminations				Consolidated
Revenues:
Oil sales	$	—			$	904			$	—			$	140			$	1,044
Natural gas sales	—				43				—				9				52
Natural gas liquid sales	—				79				—				11				90
Royalty income	—				—				160				(160		)		—
Lease bonus income	—				—				12				—				12
Midstream services	—				—				39				(32		)		7
Total revenues	—				1,026				211				(32		)		1,205
Costs and expenses:
Lease operating expenses	—				143				—				(16		)		127
Production and ad valorem taxes	—				63				11				—				74
Gathering and transportation	—				21				—				(8		)		13
Midstream services	—				—				11				(1		)		10
Depreciation, depletion and amortization	—				277				46				4				327
General and administrative expenses	27				—				23				(2		)		48
Asset retirement obligation accretion expense	—				1				—				—				1
Total costs and expenses	27				505				91				(23		)		600
Income (loss) from operations	(27		)		521				120				(9		)		605
Other income (expense):
Interest expense, net	(30		)		(6		)		(5		)		—				(41		)
Other income (expense), net	1				—				12				(2		)		11
Loss on derivative instruments, net	—				(77		)		(1		)		—				(78		)
Income from subsidiaries	446				—				—				(446		)		—
Total other expense, net	417				(83		)		6				(448		)		(108		)
Income (loss) before income taxes	390				438				126				(457		)		497
Provision for income taxes	(20		)		—				—				—				(20		)
Net income (loss)	410				438				126				(457		)		517
Net income attributable to non-controlling interest	—				—				—				35				35
Net income (loss) attributable to Diamondback Energy, Inc.	$	410			$	438			$	126			$	(492	)		$	482

F-61

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Condensed Consolidated Statement of Cash Flows
Year Ended December 31, 2019
(In millions)
									Non–
					Guarantor				Guarantor
	Parent				Subsidiaries				Subsidiaries				Eliminations				Consolidated
Net cash (used in) provided by operating activities	$	(956	)		$	1,433			$	2,257			$	—			$	2,734
Cash flows from investing activities:
Additions to oil and natural gas properties	—				(2,038		)		(639		)		—				(2,677		)
Additions to midstream assets	—				(38		)		(206		)		—				(244		)
Purchase of other property, equipment and land	—				—				(5		)		—				(5		)
Acquisition of leasehold interests	—				(360		)		(83		)		—				(443		)
Acquisition of mineral interests	—				—				(523		)		190				(333		)
Proceeds from sale of assets	—				118				372				(190		)		300
Investment in real estate	—				—				(1		)		—				(1		)
Equity investments	—				—				(485		)		—				(485		)
Intercompany transfers	(860		)		—				860				—				—
Net cash used in investing activities	(860		)		(2,318		)		(710		)		—				(3,888		)
Cash flows from financing activities:
Proceeds from borrowing under credit facility	—				1,292				1,058				—				2,350
Repayment under credit facility	—				(2,769		)		(949		)		—				(3,718		)
Proceeds from senior notes	2,968				—				501				—				3,469
Repayment of senior notes	(1,250		)		—				—				—				(1,250		)
Premium on extinguishment of debt	(44		)		—				—				—				(44		)
Proceeds from joint venture	—				—				39				—				39
Debt issuance costs	—				—				(18		)		—				(18		)
Public offering costs	—				—				(41		)		—				(41		)
Proceeds from public offerings	—				—				1,106				—				1,106
Distributions from subsidiary	860				—				—				(860		)		—
Proceeds from exercise of stock options	9				—				—				—				9
Repurchased for tax withholdings	(13		)		—				—				—				(13		)
Repurchased as part of share buyback	(593		)		—				—				—				(593		)
Dividends to stockholders	(112		)		—				—				—				(112		)
Distributions to non-controlling interest	—				—				(982		)		860				(122		)
Intercompany transfers	—				2,360				(2,360		)		—				—
Net cash (used in) provided by financing activities	1,825				883				(1,646		)		—				1,062
Net increase (decrease) in cash and cash equivalents	9				(2		)		(99		)		—				(92		)
Cash and cash equivalents at beginning of period	84				2				129				—				215
Cash and cash equivalents at end of period	$	93			$	—			$	30			$	—			$	123

F-62

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Condensed Consolidated Statement of Cash Flows
Year Ended December 31, 2018
(In millions)
									Non–
					Guarantor				Guarantor
	Parent				Subsidiaries				Subsidiaries				Eliminations				Consolidated
Net cash provided by operating activities	$	(58	)		$	1,224			$	399			$	—			$	1,565
Cash flows from investing activities:
Additions to oil and natural gas properties	—				(1,461		)		—				—				(1,461		)
Additions to midstream assets	—				(21		)		(183		)		—				(204		)
Purchase of other property, equipment and land	—				(7		)		—				—				(7		)
Acquisition of leasehold interests	—				(1,371		)		—				—				(1,371		)
Acquisition of mineral interests	—				—				(440		)		—				(440		)
Proceeds from sale of assets	—				79				1				—				80
Investment in real estate	—				—				(111		)		—				(111		)
Funds held in escrow	—				27				(16		)		—				11
Intercompany transfers	(367		)		989				(622		)		—				—
Net cash used in investing activities	(367		)		(1,765		)		(1,371		)		—				(3,503		)
Cash flows from financing activities:
Proceeds from borrowing under credit facility	—				1,960				692				—				2,652
Repayment under credit facility	—				(867		)		(375		)		—				(1,242		)
Repayment on Energen's credit facility	—				—				(559		)		—				(559		)
Proceeds from senior notes	1,062				—				—				—				1,062
Debt issuance costs	(14		)		—				(11		)		—				(25		)
Public offering costs	—				—				(3		)		—				(3		)
Proceeds from public offerings	—				—				305				—				305
Contributions to subsidiaries	(1		)		—				(1		)		2				—
Distribution to parent	155				—				—				(155		)		—
Distributions from subsidiary	(696		)		—				696				—				—
Repurchased for tax withholdings	(14		)		—				—				—				(14		)
Dividends to stockholders	(37		)		—				—				—				(37		)
Distributions to non-controlling interest	—				—				(253		)		155				(98		)
Intercompany transfers	—				(550		)		552				(2		)		—
Net cash provided by financing activities	455				543				1,043				—				2,041
Net increase (decrease) in cash and cash equivalents	30				2				71				—				103
Cash and cash equivalents at beginning of period	54				—				58				—				112
Cash and cash equivalents at end of period	$	84			$	2			$	129			$	—			$	215

F-63

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Condensed Consolidated Statement of Cash Flows
Year Ended December 31, 2017
(In millions)
									Non–
					Guarantor				Guarantor
	Parent				Subsidiaries				Subsidiaries				Eliminations				Consolidated
Net cash provided by (used in) operating activities	$	(29	)		$	768			$	150			$	—			$	889
Cash flows from investing activities:
Additions to oil and natural gas properties	—				(790		)		(3		)		—				(793		)
Additions to midstream assets	—				—				(68		)		—				(68		)
Purchase of other property, equipment and land	—				(22		)		(1		)		—				(23		)
Acquisition of leasehold interests	—				(1,961		)		—				—				(1,961		)
Acquisition of mineral interests	—				(63		)		(344		)		—				(407		)
Acquisition of midstream assets	—				—				(50		)		—				(50		)
Proceeds from sale of assets	—				66				—				—				66
Funds held in escrow	—				(27		)		131				—				104
Intercompany transfers	(1,631		)		1,631				—				—				—
Net cash used in investing activities	(1,631		)		(1,166		)		(335		)		—				(3,132		)
Cash flows from financing activities:
Proceeds from borrowing under credit facility	—				475				279				—				754
Repayment under credit facility	—				(78		)		(306		)		—				(384		)
Purchase of subsidiary units by parent	(10		)		—				—				10				—
Debt issuance costs	(8		)		1				(2		)		—				(9		)
Public offering costs	—				—				(1		)		—				(1		)
Proceeds from public offerings	—				—				380				(10		)		370
Distribution from subsidiary	90				—				(1		)		(89		)		—
Distribution to non-controlling interest	—				—				(130		)		89				(41		)
Net cash provided by financing activities	72				398				219				—				689
Net increase (decrease) in cash and cash equivalents	(1,588		)		—				34				—				(1,554		)
Cash and cash equivalents at beginning of period	1,642				—				24				—				1,666
Cash and cash equivalents at end of period	$	54			$	—			$	58			$	—			$	112

F-64

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

22. 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,
	2019				2018
	(In millions)
Oil and natural gas properties:
Proved properties	$	16,575			$	12,629
Unproved properties	9,207				9,670
Total oil and natural gas properties	25,782				22,299
Accumulated depreciation, depletion, amortization	(2,995		)		(1,599		)
Accumulated impairment	(1,934		)		(1,144		)
Net oil and natural gas properties capitalized	$	20,853			$	19,556

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,
	2019				2018				2017
	(In millions)
Acquisition costs:
Proved properties	$	194			$	5,665			$	455
Unproved properties	418				5,818				2,692
Development costs	956				493				145
Exploration costs	1,915				1,090				780
Total	$	3,483			$	13,066			$	4,072

F-65

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, natural gas and natural gas liquids. It does not include any interest costs or general and administrative costs and it reflects estimated corporate income taxes at enacted tax rates expected to be applicable the Company. Therefore, the following schedule is not necessarily indicative of the contribution to the net operating results of the Company’s oil, natural gas and natural gas liquids operations.

	Year Ended December 31,
	2019				2018				2017
	(In millions)
Oil, natural gas and natural gas liquid sales	$	3,887			$	2,130			$	1,186
Lease operating expenses	(490		)		(205		)		(127		)
Production and ad valorem taxes	(248		)		(133		)		(74		)
Gathering and transportation	(88		)		(26		)		(13		)
Depreciation, depletion, and amortization	(1,447		)		(595		)		(321		)
Impairment	(790		)		—				—
Asset retirement obligation accretion expense	(7		)		(2		)		(1		)
Income tax benefit (expense)	(89		)		(241		)		20
Results of operations	$	728			$	928			$	670

Oil and Natural Gas Reserves

Proved oil and natural gas reserve estimates as of December 31, 2019, 2018 and 2017 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-66

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, 2017	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
Extensions and discoveries	256,569			66,572			318,874
Revisions of previous estimates	(84,789	)		(8,166	)		(149,657	)
Purchase of reserves in place	13,974			3,813			19,830
Divestitures	(33,269	)		(3,809	)		(21,272	)
Production	(68,518	)		(18,498	)		(97,613	)
As of December 31, 2019	710,903			230,203			1,118,811
Proved Developed Reserves:
January 1, 2017	79,457			22,080			105,399
December 31, 2017	141,246			35,412			190,740
December 31, 2018	403,051			125,509			705,084
December 31, 2019	457,083			165,173			824,760
Proved Undeveloped Reserves:
January 1, 2017	59,717			15,054			69,497
December 31, 2017	91,935			19,198			94,629
December 31, 2018	223,885			64,782			343,565
December 31, 2019	253,820			65,030			294,051

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, 2019, the Company’s extensions and discoveries totaling 376,287 MBOE resulted primarily from the drilling of 283 new wells and from 291 new proved undeveloped locations added in which the Company owns a working interest. Viper royalty interests accounted for 5% of the extension volumes. The Company’s downward revisions of 117,898 MBOE were the result of proved undeveloped downgrades associated with inventory refinement following the Energen acquisition along with updated development plans and lower realized prices. Purchases of 21,092 MBOE were the result of 10,939 MBOE of working interest purchases and 10,153 MBOE of Viper royalty purchases, excluding mineral interests dropped down to Viper.

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

F-67

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

owns a working interest. Viper 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 Viper 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. Viper royalty interests 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 Viper royalty interest purchases accounted for 10%, with working interest purchases contributing the remainder.

At December 31, 2019, the Company’s estimated PUD reserves were approximately 367,859 MBOE, a 21,931 MBOE increase over the reserve estimate at December 31, 2018 of 345,928 MBOE. The following table includes the changes in PUD reserves for 2019:

	(MBOE)
Beginning proved undeveloped reserves at December 31, 2018	345,928
Undeveloped reserves transferred to developed	(120,920	)
Revisions	(77,519	)
Net purchases	4,542
Divestitures	(5,672	)
Extensions and discoveries	221,500
Ending proved undeveloped reserves at December 31, 2019	367,859

The increase in proved undeveloped reserves was primarily attributable to extensions of 213,909 MBOE from 291 gross (262 net) wells in which the Company has a working interest and 7,591 MBOE from 97 gross wells in which Viper owns royalty interests. Of the 291 gross working interest wells, 64 were in the Delaware Basin. Transfers of 120,920 MBOE were the result of drilling or participating in 135 gross (119 net) horizontal wells in which the Company has a working interest and 79 gross wells in which the Company has a royalty interest or mineral interest through Viper. The Company owns a working interest in 75 of the 79 gross Viper wells. Downward revisions of 77,519 MBOE resulted from 67,114 MBOE of PUD downgrades due to refinement of the PUD inventory following the acquisition of Energen. These downgrades were offset with Extensions. The remaining 10,405 MOE of downward revisions were mostly from lower benchmark commodity prices.

As of December 31, 2019, all of the Company’s proved undeveloped reserves are planned to be developed within five years from the date they were initially recorded. During 2019, approximately $956 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.

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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, 2019, 2018 and 2017.

	December 31,
	2019				2018				2017
	(In millions)
Future cash inflows	$	40,681			$	43,578			$	12,922
Future development costs	(3,809		)		(3,560		)		(1,124		)
Future production costs	(9,319		)		(7,727		)		(2,995		)
Future production taxes	(2,905		)		(2,935		)		(929		)
Future income tax expenses	(2,635		)		(3,913		)		(84		)
Future net cash flows	22,013				25,443				7,790
10% discount to reflect timing of cash flows	(11,829		)		(13,767		)		(4,033		)
Standardized measure of discounted future net cash flows	$	10,184			$	11,676			$	3,757

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,
	2019				2018				2017
	Unweighted Arithmetic Average
	First-Day-of-the-Month Prices
Oil (per Bbl)	$	51.88			$	59.63			$	48.03
Natural gas (per Mcf)	$	0.18			$	1.47			$	2.06
Natural gas liquids (per Bbl)	$	15.65			$	24.43			$	20.79

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,
	2019				2018				2017
	(In millions)
Standardized measure of discounted future net cash flows at the beginning of the period	$	11,676			$	3,757			$	1,711
Sales of oil and natural gas, net of production costs	(3,334		)		(1,786		)		(986		)
Acquisition of reserves	309				5,520				439
Divestiture of reserves	(500		)		(2		)		(11		)
Extensions and discoveries, net of future development costs	4,004				3,287				1,792
Previously estimated development costs incurred during the period	120				535				190
Net changes in prices and production costs	831				1,805				578
Changes in estimated future development costs	(3,190		)		(81		)		(53		)
Revisions of previous quantity estimates	(1,242		)		271				(99		)
Accretion of discount	1,344				380				174
Net change in income taxes	693				(1,728		)		(9		)
Net changes in timing of production and other	(527		)		(282		)		31
Standardized measure of discounted future net cash flows at the end of the period	$	10,184			$	11,676			$	3,757

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

23. QUARTERLY FINANCIAL DATA (Unaudited)

The Company’s unaudited quarterly financial data for 2019 and 2018 is summarized below.

	2019
(in millions)	First Quarter				Second Quarter				Third Quarter				Fourth Quarter
Revenues	$	864			$	1,021			$	975			$	1,104
Income (loss) from operations	319				411				349				(384		)
Income tax expense (benefit)	(33		)		102				102				(124		)
Net income (loss)	43				356				388				(472		)
Net income attributable to non-controlling interest	33				7				20				15
Net income (loss) attributable to Diamondback Energy, Inc.	$	10			$	349			$	368			$	(487	)
Earnings per common share
Basic	$	0.06			$	2.12			$	2.27			$	(3.04	)
Diluted	$	0.06			$	2.11			$	2.26			$	(3.04	)
	2018
(in millions)	First Quarter				Second Quarter				Third Quarter				Fourth Quarter
Revenues	$	479			$	527			$	537			$	633
Income from operations	267				281				268				195
Income tax expense (benefit)	47				(7		)		43				85
Net income	178				301				160				306
Net income attributable to non-controlling interest	15				82				3				(1		)
Net income attributable to Diamondback Energy, Inc.	$	163			$	219			$	157			$	307
Earnings per common share
Basic	$	1.65			$	2.22			$	1.59			$	2.50
Diluted	$	1.65			$	2.22			$	1.59			$	2.50

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