Item 16. FORM 10-K SUMMARY

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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 24, 2022
		/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/ Travis D. Stice	Chairman of the Board, Chief Executive Officer and Director	February 24, 2022
Travis D. Stice	(Principal Executive Officer)

/s/ Vincent K. Brooks	Director	February 24, 2022
Vincent K. Brooks

/s/ Michael P. Cross	Director	February 24, 2022
Michael P. Cross

/s/ David L. Houston	Director	February 24, 2022
David L. Houston

/s/ Stephanie K. Mains	Director	February 24, 2022
Stephanie K. Mains

/s/ Mark L. Plaumann	Director	February 24, 2022
Mark L. Plaumann

/s/ Melanie M. Trent	Director	February 24, 2022
Melanie M. Trent

/s/ Steven E. West	Director	February 24, 2022
Steven E. West

/s/ Kaes Van’t Hof	President and Chief Financial Officer	February 24, 2022
Kaes Van’t Hof	(Principal Financial Officer)

/s/ Teresa L. Dick	Chief Accounting Officer, Executive Vice President and Assistant Secretary	February 24, 2022
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 (the “Company”) as of December 31, 2021 and 2020, the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, 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, 2021, 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 24, 2022 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 regarding 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.

Estimation of proved reserves as it relates to the calculation and recognition of depletion expense, the evaluation of impairment, and the valuation of oil and gas properties in the Guidon Acquisition and QEP Merger

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 4 to the financial statements, the Company acquired significant oil and gas properties during the year through the Guidon Acquisition and QEP Merger. 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 and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. Management also utilizes an estimated fair value pricing model for the valuation of acquired proved 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, including acquired reserves, due to its impact on depletion expense, impairment evaluation, and acquisition accounting, 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, and the fair value of acquired oil and gas properties. 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 the 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, the management review controls on information provided to the reservoir engineering specialists, the management review controls on the final proved reserve report and on the final fair value reserve reports of the acquired oil and gas properties 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.
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;

–Compared, on a sample basis, the working and net revenue interests used in the reserve report to 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 Company’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, on a sample basis; and

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

To the extent key, sensitive inputs and assumptions used to determine the fair value of the acquired proved reserve volumes and other cash flow inputs were analyzed by testing management’s process for determining the assumptions, including examining the underlying support. Specifically, our audit procedures involved testing management’s assumptions as follows:

–Utilized a valuation specialist to evaluate the appropriateness of fair value pricing used in the fair value reserve report to published product pricing on the acquisition closing date;

F-2

–Utilized a valuation specialist to evaluate whether the Company’s valuation methodology was reasonable and performed a sensitivity analysis;

–Evaluated the appropriateness of the future operating cost and capital expenditure assumptions used in the fair value reserve report to historical operating costs and capital expenditures of similarly located properties;

–Compared, on a sample basis, the working and net revenue interests used in the fair value reserve report to land and division order records;

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

–Compared the acreage value allocated, on a per acre basis, to other recent acquisitions in the same or similar locations.

/s/ GRANT THORNTON LLP

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

Oklahoma City, Oklahoma

February 24, 2022

F-3

Diamondback Energy, Inc. and Subsidiaries

Consolidated Balance Sheets


	December 31,
	2021		2020
	(In millions, except par value and share amounts)
Assets
Current assets:
Cash and cash equivalents	$	654	$	104
Restricted cash	18		4
Accounts receivable:
Joint interest and other, net	72		56
Oil and natural gas sales, net	598		281

Inventories	62		33

Derivative instruments	13		1
Income tax receivable	1		100
Prepaid expenses and other current assets	28		23
Total current assets	1,446		602
Property and equipment:
Oil and natural gas properties, full cost method of accounting ($8,496 million and $7,493 million excluded from amortization at December 31, 2021 and December 31, 2020, respectively)	32,914		27,377
Midstream assets	1,076		1,013
Other property, equipment and land	174		138
Accumulated depletion, depreciation, amortization and impairment	(13,545)		(12,314)
Property and equipment, net	20,619		16,214
Funds held in escrow	12		51
Equity method investments	613		533
Derivative instruments	4		—
Deferred income taxes, net	40		73
Investment in real estate, net	88		101
Other assets	76		45
Total assets	$	22,898	$	17,619
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable - trade	$	36	$	71

Accrued capital expenditures	295		186
Current maturities of long-term debt	45		191
Other accrued liabilities	436		302
Revenues and royalties payable	452		237
Derivative instruments	174		249


Total current liabilities	1,438		1,236
Long-term debt	6,642		5,624
Derivative instruments	29		57
Asset retirement obligations	166		108
Deferred income taxes	1,338		783
Other long-term liabilities	40		7
Total liabilities	9,653		7,815
Commitments and contingencies (Note 18)
Stockholders’ equity:
Common stock, $0.01 par value; 400,000,000 shares authorized; 177,551,347 and 158,088,182 shares issued and outstanding at December 31, 2021 and December 31, 2020, respectively	2		2
Additional paid-in capital	14,084		12,656
Retained earnings (accumulated deficit)	(1,998)		(3,864)

Total Diamondback Energy, Inc. stockholders’ equity	12,088		8,794
Non-controlling interest	1,157		1,010
Total equity	13,245		9,804
Total liabilities and equity	$	22,898	$	17,619

See accompanying notes to consolidated financial statements.

F-4

Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Operations


	Year Ended December 31,
	2021		2020		2019
	(In millions, except per share amounts, shares in thousands)
Revenues:
Oil sales	$	5,396	$	2,410	$	3,554
Natural gas sales	569		107		66
Natural gas liquid sales	782		239		267

Midstream services	45		50		64
Other operating income	5		7		13
Total revenues	6,797		2,813		3,964
Costs and expenses:
Lease operating expenses	565		425		490
Production and ad valorem taxes	425		195		248
Gathering and transportation	212		140		88
Midstream services expense	89		105		91
Depreciation, depletion, amortization and accretion	1,275		1,311		1,454
Impairment of oil and natural gas properties	—		6,021		790
General and administrative expenses	146		88		104

Merger and integration expense	78		—		—
Other operating expense	6		4		4
Total costs and expenses	2,796		8,289		3,269
Income (loss) from operations	4,001		(5,476)		695
Other income (expense):

Interest expense, net	(199)		(197)		(172)
Other income (expense), net	(10)		(7)		9

Gain (loss) on derivative instruments, net	(848)		(81)		(108)

Gain (loss) on sale of equity method investments	23		—		—
Gain (loss) on extinguishment of debt	(75)		(5)		(56)
Income (loss) from equity investments	15		(10)		(6)
Total other income (expense), net	(1,094)		(300)		(333)
Income (loss) before income taxes	2,907		(5,776)		362
Provision for (benefit from) income taxes	631		(1,104)		47
Net income (loss)	2,276		(4,672)		315
Net income (loss) attributable to non-controlling interest	94		(155)		75
Net income (loss) attributable to Diamondback Energy, Inc.	$	2,182	$	(4,517)	$	240

Earnings (loss) per common share:
Basic	$	12.35	$	(28.59)	$	1.47
Diluted	$	12.30	$	(28.59)	$	1.47
Weighted average common shares outstanding:
Basic	176,643		157,976		163,493
Diluted	177,359		157,976		163,843
Dividends declared per share	$	1.95	$	1.5250	$	0.9375

See accompanying notes to consolidated financial statements.

F-5

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, 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
Cash paid for tax withholding on vested equity awards	—	—		(13)		—			—		(13)
Repurchased shares under buyback program	(6,385)	—		(598)		—			—		(598)
Distribution to non-controlling interest	—	—		—		—			(122)		(122)
Dividend paid	—	—		—		(112)			—		(112)
Exercise of stock and unit options and awards of restricted stock	1,114	—		8		—			—		8
Change in ownership of consolidated subsidiaries, net	—	—		(33)		—			45		12
Net income	—	—		—		240			75		315
Balance at December 31, 2019	159,002	2		12,357		890			1,657		14,906
Unit-based compensation	—	—		—		—			10		10
Distribution equivalent rights payments	—	—		—		(1)			(2)		(3)
Stock-based compensation	—	—		43		—			—		43
Cash paid for tax withholding on vested equity awards	—	—		(5)		—			(2)		(7)
Repurchased shares under buyback program	(1,280)	—		(98)		—			—		(98)
Repurchased units under buyback programs	—	—		—		—			(39)		(39)
Distribution to non-controlling interest	—	—		—		—			(93)		(93)
Dividend paid	—	—		—		(236)			—		(236)
Exercise of stock options and vesting of restricted stock units	366	—		1		—			—		1
Change in ownership of consolidated subsidiaries, net	—	—		358		—			(366)		(8)
Net income (loss)	—	—		—		(4,517)			(155)		(4,672)
Balance at December 31, 2020	158,088	2		12,656		(3,864)			1,010		9,804
Issuance of common units - Viper Energy Partners LP	—	—		—		—			337		337
Unit-based compensation	—	—		—		—			11		11
Distribution equivalent rights payments	—	—		—		(4)			(2)		(6)
Common stock issued for acquisitions	22,795	—		1,727		—			—		1,727
Stock-based compensation	—	—		60		—			—		60
Cash paid for tax withholding on vested equity awards	—	—		(6)		—			(2)		(8)
Repurchased shares under buyback program	(4,128)	—		(431)		—			—		(431)
Repurchased units under buyback programs	—	—		—		—			(94)		(94)
Distribution to non-controlling interest	—	—		—		—			(112)		(112)
Dividend paid	—	—		—		(312)			—		(312)
Exercise of stock options and issuance of restricted stock units and awards	796	—		12		—			—		12
Change in ownership of consolidated subsidiaries, net	—	—		66		—			(85)		(19)
Net income (loss)	—	—		—		2,182			94		2,276
Balance at December 31, 2021	177,551	$	2	$	14,084	$	(1,998)		$	1,157	$	13,245

See accompanying notes to consolidated financial statements.

F-6

Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows


	Year Ended December 31,
	2021		2020		2019
	(In millions)
Cash flows from operating activities:
Net income (loss)	$	2,276	$	(4,672)	$	315
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Provision for (benefit from) deferred income taxes	606		(1,042)		47

Impairment of oil and natural gas properties	—		6,021		790

Depreciation, depletion, amortization and accretion	1,275		1,311		1,454

(Gain) loss on extinguishment of debt	75		5		56

(Gain) loss on derivative instruments, net	848		81		108
Cash received (paid) on settlement of derivative instruments	(1,247)		250		80


Equity-based compensation expense	51		37		48
(Gain) loss on sale of equity method investments	(23)		—		—
Other	47		30		8



Changes in operating assets and liabilities:
Accounts receivable	(196)		217		(187)

Income tax receivable	152		(62)		—

Prepaid expenses and other	20		2		29
Accounts payable and accrued liabilities	(41)		(20)		(129)



Revenues and royalties payable	148		(41)		135

Other	(47)		1		(15)
Net cash provided by (used in) operating activities	3,944		2,118		2,739
Cash flows from investing activities:
Drilling, completions and infrastructure additions to oil and natural gas properties	(1,457)		(1,719)		(2,677)


Additions to midstream assets	(30)		(140)		(244)

Property acquisitions	(812)		(185)		(776)




Proceeds from sale of assets	820		63		300



Contributions to equity method investments	(114)		(102)		(485)
Distributions from equity method investments	9		40		—
Other	45		(58)		(6)


Net cash provided by (used in) investing activities	(1,539)		(2,101)		(3,888)
Cash flows from financing activities:
Proceeds from borrowings under credit facilities	1,313		1,130		2,350
Repayments under credit facilities	(1,000)		(1,478)		(3,718)
Proceeds from senior notes	2,200		997		3,469
Repayment of senior notes	(3,193)		(239)		(1,250)
Proceeds from (repayments to) joint venture	(20)		40		39
Premium on extinguishment of debt	(178)		(2)		(44)



Public offering costs	—		—		(41)
Proceeds from public offerings	—		—		1,106






Repurchased shares under buyback program	(431)		(98)		(593)
Repurchased units under buyback program	(94)		(39)		—
Dividends to stockholders	(312)		(236)		(112)

Distributions to non-controlling interest	(112)		(93)		(122)
Financing portion of net cash received (paid) for derivative instruments	22		—		—
Other	(36)		(19)		(22)

Net cash provided by (used in) financing activities	(1,841)		(37)		1,062
Net increase (decrease) in cash and cash equivalents	564		(20)		(87)
Cash, cash equivalents and restricted cash at beginning of period	108		128		215
Cash, cash equivalents and restricted cash at end of period(1)	$	672	$	108	$	128

See Note 2—Summary of Significant Accounting Policies

See accompanying notes to consolidated financial statements.

F-7

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 currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas.

The wholly-owned subsidiaries of Diamondback, as of December 31, 2021, include Diamondback E&P LLC (“Diamondback E&P”), 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 QEP Resources, Inc. (“QEP”), a Delaware Corporation. Diamondback O&G LLC (“O&G”), Energen Corporation (“Energen”), Energen Resources Corporation and EGN Services, Inc., former wholly owned subsidiaries of Diamondback, were merged with and into Diamondback E&P LLC effective June 30, 2021 as part of the internal restructuring of the Company’s subsidiaries (the “E&P Merger”).

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.

Diamondback’s publicly traded subsidiaries Viper and Rattler are consolidated in the financial statements of the Company. As of December 31, 2021, the Company owned approximately 54% of Viper’s total units outstanding. The Company’s wholly owned subsidiary, Viper Energy Partners GP LLC, is the general partner of Viper. As of December 31, 2021, the Company owned approximately 74% of Rattler’s total units outstanding. The Company’s wholly owned subsidiary, Rattler Midstream GP LLC, is the general partner of Rattler. The results of operations attributable to the non-controlling interest in Viper and Rattler are presented within equity and net income and are shown separately from the equity and net income attributable to the Company.

Reclassifications

Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had an immaterial effect on the previously reported total assets, total liabilities, stockholders’ equity, results of operations or cash flows.

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 as of the date of the consolidated financial statements. Actual results could differ from those estimates.

Making accurate estimates and assumptions is particularly difficult in the oil and natural gas industry, given the challenges resulting from volatility in oil and natural gas prices and the effects of the ongoing COVID-19 pandemic. Such circumstances generally increase the uncertainty in the Company’s accounting estimates, particularly those involving financial forecasts.

F-8

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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

Cash, Cash Equivalents and Restricted Cash

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.

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.

The Company adopted Accounting Standards Update (“ASU”) 2016-13 and the subsequent applicable modifications

to the rule on January 1, 2020. Accounts receivable are stated at amounts due from joint interest owners or purchasers, net of an allowance for expected losses as estimated by the Company when 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 from joint interest owners or purchasers outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance for each type of receivable 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 expected losses. At December 31, 2021 and 2020, the Company’s allowances for credit losses related to joint interest receivables and credit losses related to sales of oil and natural gas production were not material.

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. For commodity derivative instruments and interest rate swaps which have not been designated as hedges for accounting purposes, the Company 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. The Company accounts for its interest rate swaps which have been designated as fair value hedges under the “shortcut” method of accounting. As such, gains and losses due to changes in the fair value of the interest rate swaps completely offset changes in the fair value of the hedged portion of the underlying debt. For additional information regarding the Company’s derivative instruments, see Note 15—Derivatives.

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

F-9

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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 and natural liquids. 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. 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 $8.77, $11.30 and $13.54 for the years ended December 31, 2021, 2020 and 2019, respectively. Depletion expense for oil and natural gas properties was $1.2 billion, $1.2 billion and $1.4 billion for the years ended December 31, 2021, 2020 and 2019, 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 write-down is required. For additional information regarding the Company’s impairments on proved oil and natural gas properties, see Note 8—Property and Equipment.

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 at least 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.

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. For additional information regarding the Company’s real estate assets, see Note 7—Real Estate Assets.

Other Property, Equipment and Land

Other property, equipment and land 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 30 years.

F-10

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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.

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.

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. For additional information regarding the Company’s asset retirement obligations, see Note 9—Asset Retirement Obligations.

Impairment of Long-Lived Assets

Other property and equipment used in operations and midstream assets 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 significant impairment losses for the years ended December 31, 2021, 2020 and 2019.

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. See Note 11—Debt for further details.

Inventories

Inventories are stated at the lower of cost or market and consist of tubular goods and equipment at December 31, 2021 and 2020. 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.

Debt Issuance Costs

Long-term debt includes capitalized costs related to the senior notes, net of accumulated amortization. The costs associated with the senior notes are netted against the senior notes balances and are amortized over the term of the senior notes using the effective interest method. See Note 11—Debt for further details. The costs associated with the Company’s credit facilities are included in other assets on the consolidated balance sheet and are amortized over the term of the facility.

F-11

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Other Accrued Liabilities

Other accrued liabilities consist of the following:


	December 31,
	2021		2020
	(In millions)
Derivative liability payable	$	101	$	30
Lease operating expenses payable	86		115
Ad valorem taxes payable	70		57
Accrued compensation	48		27
Interest payable	46		37
Midstream operating expenses payable	13		18
Liability for drilling costs prepaid by joint interest partners	10		5
Other	62		13
Total other accrued liabilities	$	436	$	302

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.

Non-controlling Interests

Non-controlling interests in the accompanying consolidated financial statements represent minority interest ownership in Viper and Rattler and are presented as a component of equity. When the Company’s relative ownership interests in Viper and Rattler change, adjustments to non-controlling interest and additional paid-in-capital, tax effected, will occur. Because these changes in the ownership interests in Viper and Rattler do not result in a change of control, the transactions are accounted for as equity transactions under ASC Topic 810, “Consolidation”, which requires that any differences between the carrying value of the Company’s basis in Viper and Rattler and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest. See Note 12—Stockholders' Equity and Earnings Per Share for a discussion of changes of the Company’s ownership interest in consolidated subsidiaries during the year ended December 31, 2021.

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.

F-12

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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. Generally, 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 frac-water meter for a specified well pad and the wastewater volumes have been metered downstream of the Company’s facilities. For services contracted through third party providers, Rattler’s performance obligation is satisfied when the service performed by the third party provider has been completed. Revenue is recognized based on the per barrel 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.

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.

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.

Prior-period performance obligations

The Company records revenue in the month production is delivered to the purchaser. However, purchaser and settlement statements for 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

F-13

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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 years ended December 31, 2021, 2020 and 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

The Company accounts for its corporate joint ventures under the equity method of accounting in accordance with Financial Accounting Standards Board Accounting Standards Codification (“ASC”) Topic 323 “Investments — Equity Method and Joint Ventures.” The Company also applies the equity method of accounting to investments of less than 50% in an investee over which the Company exercises significant influence but does not have control and investments of greater than 50% in an investee over which the Company does not exercise significant influence or have control. Under the equity method, the Company’s share of the investee’s earnings or loss is recognized in the consolidated statement of operations. As of December 31, 2021, the Company’s proportionate share of the income or loss from equity method investments is recognized on a one-month lag for all equity method investments.

Judgment regarding the level of influence over each equity method investment includes considering key factors such as ownership interest, representation on the board of directors, participation in policy-making decisions, material intercompany transactions and extent of ownership by an investor in relation to the concentration of other shareholdings. Additionally, an investment in a limited liability company that maintains a specific ownership account for each investor shall be viewed as similar to an investment in a limited partnership for purposes of determining whether a noncontrolling investment shall be accounted for using the cost method or the equity method.

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 were no material impairments of the Company’s equity investments for the years ended December 31, 2021, 2020 and 2019. For additional information on the Company’s investments, see Note 10—Equity Method Investments.

Accounting for Equity-Based Compensation

The Company has granted various types of stock-based awards including stock options and restricted stock units. Viper and Rattler have granted various unit-based awards including unit options and phantom units to employees, officers and directors of Viper’s General Partner, Rattler’s General Partner and the Company who perform services for the respective entities. These plans and related accounting policies for material awards are defined and described more fully in Note 13—Equity-Based Compensation. Equity compensation awards are measured at fair value on the date of grant and are expensed over the required service period. Forfeitures for these awards are recognized as they occur.

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

The Company 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. For additional information regarding income taxes, see Note 14—Income Taxes.

F-14

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Recent Accounting Pronouncements

Recently Adopted Pronouncements

In December 2019, the FASB issued 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 and is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Company adopted this update effective January 1, 2021. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity.

Accounting Pronouncements Not Yet Adopted

In October 2021, the FASB issued ASU 2021-08, "Business Combinations (Topic 805) – Accounting for Contract Assets and Contract Liabilities from Contracts with Customers.” This update requires the acquirer in a business combination to record contract asset and liabilities following Topic 606 – “Revenue from Contracts with Customers” at acquisition as if it had originated the contract, rather than at fair value. This update is effective for public business entities beginning after December 15, 2022 with early adoption permitted. The Company continues to evaluate the provisions of this update, but does not believe the adoption will have a material impact on its financial position, results of operations or liquidity.

The Company considers the applicability and impact of all ASUs. ASUs not discussed above were assessed and determined to be either not applicable, the effects of adoption are not expected to be material or are clarifications of ASUs previously disclosed.

3. REVENUE FROM CONTRACTS WITH CUSTOMERS

Revenue from Contracts with Customers

The following tables present the Company’s revenue from contracts with customers disaggregated by product type and basin:


	Year Ended December 31, 2021
	Midland Basin		Delaware Basin		Other		Total
	(In millions)
Oil sales	$	3,468	$	1,663	$	265	$	5,396
Natural gas sales	327		215		27		569
Natural gas liquid sales	493		249		40		782

Total	$	4,288	$	2,127	$	332	$	6,747


	Year Ended December 31, 2020
	Midland Basin		Delaware Basin		Other		Total
	(In millions)
Oil sales	$	1,393	$	1,011	$	6	$	2,410
Natural gas sales	56		50		1		107
Natural gas liquid sales	138		100		1		239

Total	$	1,587	$	1,161	$	8	$	2,756

F-15

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)


	Three Months Ended December 31, 2019
	Midland Basin		Delaware Basin		Other		Total
	(In millions)
Oil sales	$	2,139	$	1,351	$	64	$	3,554
Natural gas sales	32		33		1		66
Natural gas liquid sales	154		110		3		267

Total	$	2,325	$	1,494	$	68	$	3,887

Customers

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, 2021, three purchasers each accounted for more than 10% of our revenue: Vitol Inc. (“Vitol”) (21%); Shell Trading (USA) Company (“Shell”) (19%); and Plains Marketing LP (“Plains”) (12%). For the year ended December 31, 2020, four purchasers each accounted for more than 10% of the Company’s revenue: Vitol (26%); Shell (22%); Plains (20%); and Trafigura Trading LLC (11%). For the year ended December 31, 2019, three purchasers each accounted for more than 10% of the Company’s revenue: Shell (27%); Plains (23%); and Vitol (15%). 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.

4. ACQUISITIONS AND DIVESTITURES

2021 Activity

Guidon Operating LLC

On February 26, 2021, the Company closed on its acquisition of all leasehold interests and related assets of Guidon Operating LLC (the “Guidon Acquisition”) which include approximately 32,500 net acres in the Northern Midland Basin in exchange for 10.68 million shares of the Company’s common stock and $375 million of cash. The cash portion of this transaction was funded through a combination of cash on hand and borrowings under the Company’s credit facility. As a result of the Guidon Acquisition, the Company added approximately 210 gross producing wells.

The following table presents the acquisition consideration paid in the Guidon Acquisition (in millions, except per share data, shares in thousands):


Consideration:
Shares of Diamondback common stock issued at closing	10,676
Closing price per share of Diamondback common stock on the closing date	$	69.28
Fair value of Diamondback common stock issued	$	740
Cash consideration	375
Total consideration (including fair value of Diamondback common stock issued)	$	1,115

F-16

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Purchase Price Allocation

The Guidon Acquisition has been accounted for as a business combination using the acquisition method. The following table represents the allocation of the total purchase price paid in the Guidon Acquisition to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date and may revise the value of the assets and liabilities as appropriate within that time frame. Through December 31, 2021, there have been no material changes to the allocation presented in the March 31, 2021 10-Q filed with the SEC on May 7, 2021.

The following table sets forth the Company’s preliminary purchase price allocation (in millions):








Total consideration	$	1,115

Fair value of liabilities assumed:
Asset retirement obligations	9

Fair value of assets acquired:
Oil and gas properties	1,110
Midstream assets	14
Amount attributable to assets acquired	1,124
Net assets acquired and liabilities assumed	$	1,115

Oil and natural gas properties were valued using an income approach utilizing the discounted cash flow method, which takes into account production forecasts, projected commodity prices and pricing differentials, and estimates of future capital and operating costs which were then discounted utilizing an estimated weighted-average cost of capital for industry market participants. The fair value of acquired midstream assets was based on the cost approach, which utilized asset listings and cost records with consideration for the reported age, condition, utilization and economic support of the assets. The majority of the measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and are therefore considered Level 3 inputs.

With the completion of the Guidon Acquisition, the Company acquired proved properties of $537 million and unproved properties of $573 million. The results of operations attributable to the Guidon Acquisition since the acquisition date have been included in the consolidated statements of operations and include $345 million of total revenue and $170 million of net income for the year ended December 31, 2021.

QEP Resources, Inc.

On March 17, 2021, the Company completed its acquisition of QEP in an all-stock transaction (the “QEP Merger”). The addition of QEP’s assets increased the Company’s net acreage in the Midland Basin by approximately 49,000 net acres. Under the terms of the QEP Merger, each eligible share of QEP common stock issued and outstanding immediately prior to the effective time converted into the right to receive 0.050 of a share of Diamondback common stock, with cash being paid in lieu of any fractional shares (the “merger consideration”). At the closing date of the QEP Merger, the carrying value of QEP’s outstanding debt was approximately $1.6 billion. See Note 11—Debt for further discussion.

F-17

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

The following table presents the acquisition consideration paid to QEP stockholders in the QEP Merger (in millions, except per share data, shares in thousands):


Consideration:
Eligible shares of QEP common stock converted into shares of Diamondback common stock	238,153
Shares of QEP equity awards included in precombination consideration	4,221
Total shares of QEP common stock eligible for merger consideration	242,374
Exchange ratio	0.050
Shares of Diamondback common stock issued as merger consideration	12,119
Closing price per share of Diamondback common stock	$	81.41
Total consideration (fair value of the Company's common stock issued)	$	987

Purchase Price Allocation

The QEP Merger has been accounted for as a business combination using the acquisition method. The following table represents the preliminary allocation of the total purchase price for the acquisition of QEP to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date. Although the purchase price allocation is substantially complete as of the date of this filing, certain data necessary to complete the purchase price allocation is not yet available and includes, but is not limited to, final tax returns that provide the underlying tax basis of QEP’s assets and liabilities and final valuations of the acquired oil and natural gas properties. As such, there may be further adjustments to the fair value of certain assets acquired and liabilities assumed. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date.

The following table sets forth the Company’s preliminary purchase price allocation (in millions):



Total consideration	$	987

Fair value of liabilities assumed:
Accounts payable - trade	$	26
Accrued capital expenditures	38
Other accrued liabilities	107
Revenues and royalties payable	67
Derivative instruments	242
Long-term debt	1,710
Asset retirement obligations	54

Other long-term liabilities	63
Amount attributable to liabilities assumed	$	2,307

Fair value of assets acquired:
Cash, cash equivalents and restricted cash	$	22
Accounts receivable - joint interest and other, net	87
Accounts receivable - oil and natural gas sales, net	44
Inventories	18
Income tax receivable	33
Prepaid expenses and other current assets	7
Oil and natural gas properties	2,927
Other property, equipment and land	10
Deferred income taxes	40
Other assets	106
Amount attributable to assets acquired	3,294
Net assets acquired and liabilities assumed	$	987

F-18

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

The purchase price allocation above is based on estimates of the fair values of the assets and liabilities of QEP as of the closing date of the QEP Merger. The majority of the measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and are therefore considered Level 3 inputs. The fair value of acquired property and equipment, including midstream assets classified in oil and natural gas properties, is based on the cost approach, which utilized asset listings and cost records with consideration for the reported age, condition, utilization and economic support of the assets. Oil and natural gas properties were valued using an income approach utilizing the discounted cash flow method, which takes into account production forecasts, projected commodity prices and pricing differentials, and estimates of future capital and operating costs which were then discounted utilizing an estimated weighted-average cost of capital for industry market participants. The fair value of QEP’s outstanding senior unsecured notes was based on unadjusted quoted prices in an active market, which are considered Level 1 inputs. The value of derivative instruments was based on observable inputs including forward commodity price curves which are considered Level 2 inputs. Deferred income taxes represent the tax effects of differences in the tax basis and merger-date fair values of assets acquired and liabilities assumed.

With the completion of the QEP Merger, the Company acquired proved properties of $2.0 billion and unproved properties of $742 million, primarily in the Midland Basin and the Williston Basin. The Williston Basin assets were divested in October 2021 as discussed further below. Through December 31, 2021, the fair value allocated to proved properties acquired in the QEP Merger has decreased by $300 million and the fair value allocated to unproved properties has increased by $300 million based on management’s continuing assessment of the inputs utilized in the fair value estimates discussed above. There have been no other material changes to the allocation presented in the March 31, 2021 10-Q filed with the SEC on May 7, 2021.

The results of operations attributable to the QEP Merger since the acquisition date have been included in the consolidated statements of operations and include $1.1 billion of total revenue and $455 million of net income for the year ended December 31, 2021.

Pro Forma Financial Information

The following unaudited summary pro forma financial information for the years ended December 31, 2021 and 2020 has been prepared to give effect to the QEP Merger and the Guidon Acquisition as if they had occurred on January 1, 2020. The unaudited pro forma financial information does not purport to be indicative of what the combined company’s results of operations would have been if these transactions had occurred on the dates indicated, nor is it indicative of the future financial position or results of operations of the combined company.

The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for QEP’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 adjustments to depreciation, depletion and amortization based on the full cost method of accounting and the purchase price allocated to property, plant, and equipment as well as adjustments to interest expense and the provision for (benefit from) income taxes.

Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company for the QEP Merger and the Guidon Acquisition of approximately $78 million for the year ended December 31, 2021 and acquisition-related costs incurred by QEP of $31 million through the closing date of the QEP Merger. These acquisition-related costs primarily consist of one-time severance costs and the accelerated or change-in-control vesting of certain QEP share-based awards for former QEP employees based on the terms of the merger agreement relating to the QEP Merger and other bank, legal and advisory fees. The pro forma results of operations do not include any cost savings or other synergies that may result from the QEP Merger and the Guidon Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the acquired assets. The pro forma financial data does not include the results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material.

F-19

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)


	Year Ended December 31,
		2021		2020
		(In millions, except per share amounts)
Revenues		$	7,069	$	3,727
Income (loss) from operations		$	4,182	$	(5,771)
Net income (loss)		$	2,186	$	(4,641)
Basic earnings per common share		$	12.09	$	(25.67)
Diluted earnings per common share		$	12.05	$	(25.67)

Divestitures of Certain Non-Core Assets

On June 3, 2021 and June 7, 2021, respectively, the Company closed transactions to divest certain non-core Permian assets including over 7,000 net acres of non-core Southern Midland Basin acreage in Upton county, Texas and approximately 1,300 net acres of non-core, non-operated Delaware Basin assets in Lea county, New Mexico for combined net cash proceeds of $82 million, after customary closing adjustments. The Company used its net proceeds from these transactions toward debt reduction.

Williston Basin Divestiture

On October 21, 2021, the Company completed the divestiture of its Williston Basin oil and natural gas assets, consisting of approximately 95,000 net acres, to Oasis Petroleum Inc., for net cash proceeds of approximately $586 million, after customary closing adjustments. This transaction did not result in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves and, accordingly, the Company recorded the proceeds as a reduction of its full cost pool with no gain or loss recognized on the sale. The Company used its net proceeds from this transaction toward debt reduction.

Gas Gathering Assets Divestiture

On November 1, 2021, the Company completed the sale of certain gas gathering assets to Brazos Delaware Gas, LLC, an affiliate of Brazos Midstream (“Brazos”), for net cash proceeds of approximately $54 million, after customary closing adjustments.

2021 Drop Down Transaction

On December 1, 2021, Diamondback completed the sale of certain water midstream assets to Rattler in exchange for cash proceeds of approximately $160 million, in a drop down transaction (the “Drop Down”). The midstream assets consist primarily of produced water gathering and disposal systems, produced water recycling facilities, and sourced water gathering and storage assets acquired by the Company through the Guidon Acquisition and the QEP Merger with a carrying value of approximately $160 million. The Company and Rattler have also mutually agreed to amend their commercial agreements covering produced water gathering and disposal and sourced water gathering services to add certain Diamondback leasehold acreage to Rattler’s dedication. The Drop Down transaction was accounted for as a transaction between entities under common control.

Viper’s Swallowtail Acquisition

On October 1, 2021, Viper acquired certain mineral and royalty interests from the Swallowtail entities pursuant to a definitive purchase and sale agreement for 15.25 million of Viper’s common units and approximately $225 million in cash (the “Swallowtail Acquisition”). The mineral and royalty interests acquired in the Swallowtail Acquisition represent approximately 2,313 net royalty acres primarily in the Northern Midland Basin, of which approximately 62% are operated by Diamondback. The Swallowtail Acquisition had an effective date of August 1, 2021. The cash portion of this transaction was funded through a combination of Viper’s cash on hand and approximately $190 million of borrowings under Viper LLC’s revolving credit facility.

F-20

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Rattler’s WTG Joint Venture Acquisition

On October 5, 2021, Rattler and a private affiliate of an investment fund formed the WTG joint venture. Rattler contributed approximately $104 million in cash for a 25% membership interest in the WTG joint venture, which then completed the acquisition of a majority interest in WTG Midstream from West Texas Gas, Inc. and its affiliates. WTG Midstream’s assets primarily consist of an interconnected gas gathering system and six major gas processing plants servicing the Midland Basin with 925 MMcf/d of total processing capacity with additional gas gathering and processing expansions planned.

Rattler’s Gas Gathering Divestiture

On November 1, 2021, Rattler completed the sale of its gas gathering assets to Brazos for aggregate total gross potential consideration of $93 million, consisting of (i) $83 million due at closing, after customary closing adjustments, (ii) a $5 million contingent payment due in 2023 if the aggregate actual deliveries of gas volumes into the gas gathering system by and/or on behalf of the Company and its affiliates exceed certain specified thresholds during 2022, and (iii) a $5 million contingent payment due in 2024 if the aggregate actual deliveries of gas volumes into the gas gathering system by and/or on behalf of the Company and its affiliates exceed certain specified thresholds during 2022 and 2023. The contingent payments will be recorded if and when they become realizable.

2020 Activity

Viper’s Acquisition of Certain Mineral and Royalty Interests

During the year ended December 31, 2020, Viper acquired, from unrelated third-party sellers, mineral and royalty interests representing 4,948 gross (417 net royalty) acres in the Permian Basin for an aggregate purchase price of approximately $64 million, including post-closing adjustments. Viper funded these acquisitions with cash on hand and borrowings under Viper LLC’s revolving credit facility.

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 conventional and non-core Permian assets, which were acquired by the Company in its merger with Energen, 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.

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, 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 million of Viper’s newly-issued Class B units, approximately 18 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 mineral and royalty interests divested in the drop down transaction represented approximately 5,490 net royalty acres across the Midland and Delaware Basins, of which over 95% were operated by the Company, and had an average net royalty interest of approximately 3.2%. The drop down transaction 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 transaction through a combination of cash on hand and borrowings under Viper LLC’s revolving credit facility.

F-21

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

5. 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 to, among other things, own, acquire and exploit oil and natural gas properties in the Permian Basin in North America. Viper LLC (“Viper’s General Partner”), a wholly owned subsidiary of Diamondback, serves as the general partner of viper. As of December 31, 2021, Diamondback owned approximately 54% of Viper’s total units outstanding.

In March 2019, Viper completed an underwritten public offering of 10,925,000 common units, which included 1,425,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Viper received net proceeds from this offering of approximately $341 million, after deducting underwriting discounts and commissions and estimated offering expenses. There were no equity offerings during the years ended December 31, 2021 and 2020.

During the years ended December 31, 2021, 2020, and 2019, Diamondback received distributions of $101 million, $62 million and $133 million, respectively, in respect of its interests in Viper and Viper LLC.

The Company is party to a partnership agreement and tax sharing agreement with Viper which govern the reimbursement of various expenses and state, local and other taxes, respectively. No significant transactions occurred under these agreements during the years ended December 31, 2021, 2020 and 2019.

See Note 4—Acquisitions and Divestitures for discussions of Viper’s acquisitions and divestitures.

Implementation of Viper’s Common Unit Repurchase Program

On November 6, 2020, the board of directors of Viper’s general partner approved a common unit repurchase program to acquire up to $100 million of Viper’s outstanding common units. The common unit repurchase program was initially authorized to extended through December 31, 2021, but in November 2021, the board of directors of Viper’s general partner increased the repurchase program authorization to $150 million and extended the program indefinitely. During the year ended December 31, 2021, Viper repurchased approximately $46 million of its common units under its repurchase program. As of December 31, 2021, $80 million remained available for use to repurchase common units under Viper’s common unit repurchase program.

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 11—Debt for a description of this credit facility.

6. 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 Midstream GP LLC (“Rattler’s General Partner”), a wholly owned subsidiary of Diamondback, serves as the general partner of Rattler. As of December 31, 2021, Diamondback owned approximately 74% 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. 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

F-22

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

from Rattler’s General Partner and (iii) caused Rattler LLC to make a distribution of approximately $727 million to Diamondback.

During the years ended December 31, 2021, 2020, and 2019, Diamondback received distributions of $97 million, $115 million and $36 million, respectively, in respect of its interests in Rattler and Rattler Midstream GP LLC.

The Company is party to a partnership agreement, services and secondment agreement and tax sharing agreement with Rattler which govern the reimbursement of various expenses and state, local and other taxes, respectively. No significant transactions occurred under these agreements during the years ended December 31, 2021, 2020 and 2019.

See Note 4—Acquisitions and Divestitures for discussions of Rattler’s acquisitions and divestitures.

Implementation of Rattler’s Common Unit Repurchase Program

On October 29, 2020, the board of directors of Rattler’s general partner approved a common unit repurchase program to acquire up to $100 million of Rattler’s outstanding common units. The common unit repurchase program was initially authorized to extend through December 31, 2021, but in October 2021, the board of directors of Rattler’s general partner increased the repurchase program authorization to $150 million and extended the program indefinitely. During the year ended December 31, 2021, Rattler repurchased approximately $48 million of its common units under its repurchase program. As of December 31, 2021, $88 million remained available for use to repurchase common units under Rattler’s common unit repurchase program.

Rattler LLC’s Revolving Credit Facility

Rattler LLC has entered into a secured revolving credit facility with Wells Fargo, as administrative agent, sole book runner and lead arranger. See Note 11—Debt for a description of this credit facility.

7. REAL ESTATE ASSETS

The following schedules present the cost and related accumulated depreciation related to Diamondback’s significant real estate assets:


	Estimated Useful Lives		December 31,
		2021			2020
	(Years)		(In millions)
Buildings	20-30		$	95		$	102
Tenant improvements	5 - 15		4			5
Land	N/A		1			2
Land improvements	5 - 15		1			1
Total real estate assets			101			110
Less: accumulated depreciation			(16)			(13)
Total investment in land and buildings, net			$	85		$	97

F-23

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

8. PROPERTY AND EQUIPMENT

Property and equipment includes the following:


	December 31,
	2021		2020
	(In millions)
Oil and natural gas properties:
Subject to depletion	$	24,418	$	19,884
Not subject to depletion	8,496		7,493
Gross oil and natural gas properties	32,914		27,377
Accumulated depletion	(5,434)		(4,237)
Accumulated impairment	(7,954)		(7,954)
Oil and natural gas properties, net	19,526		15,186
Midstream assets	1,076		1,013
Other property, equipment and land	174		138
Accumulated depreciation and impairment	(157)		(123)
Total property and equipment, net	$	20,619	$	16,214

Balance of costs not subject to depletion:
Incurred in 2021	$	1,688
Incurred in 2020	71
Incurred in 2019	422
Thereafter	6,315


Total not subject to depletion	$	8,496

Capitalized internal costs were approximately $60 million, $53 million and $49 million for the years ended December 31, 2021, 2020 and 2019, 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 ten years.

Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter which determines a limit, or ceiling, on the book value of proved oil and natural gas properties. No impairment expense was recorded for the year ended December 31, 2021. The Company recorded non-cash ceiling test impairments for the years ended December 31, 2020 and 2019 of $6.0 billion and $790 million, respectively, which are included in accumulated depletion, depreciation, amortization and impairment on the consolidated balance sheet. The impairment charge affected the Company’s reported net income but did not reduce its cash flow.

In connection with the QEP Merger and the Guidon Acquisition, the Company recorded the oil and natural gas properties acquired at fair value, based on forward strip oil and natural gas pricing existing at the closing date of the respective transactions, in accordance with ASC 820 Fair Value Measurement. Pursuant to SEC guidance, the Company determined that the fair value of the properties acquired in the QEP Merger and the Guidon Acquisition clearly exceeded the related full cost ceiling limitation beyond a reasonable doubt. As such, the Company requested and received a waiver from the SEC to exclude the properties acquired from the ceiling test calculation for the quarter ended March 31, 2021. As a result, no impairment expense related to the QEP Merger and the Guidon Acquisition was recorded for the three months ended March 31, 2021. Had the Company not received a waiver from the SEC, an impairment charge of approximately $1.1 billion would have been recorded for such period. Management affirmed there has not been a decline in the fair value of these acquired assets. The properties acquired in the QEP Merger and the Guidon Acquisition had total unamortized costs at March 31, 2021 of $3.0 billion and $1.1 billion, respectively.

F-24

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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. If the trailing 12-month commodity prices decline as compared to the commodity prices used in prior quarters, the Company may have material write downs in subsequent quarters. Given the rate of change impacting the oil and natural gas industry described above, it is possible that circumstances requiring additional impairment testing will occur in future interim periods, which could result in potentially material impairment charges being recorded.

At December 31, 2021, there were $135 million in exploration costs and development costs and $124 million in capitalized interest that are not subject to depletion. At December 31, 2020, there were $85 million in exploration costs and development costs and $51 million capitalized interest that were not subject to depletion.

9. 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,
	2021		2020
	(In millions)
Asset retirement obligations, beginning of period	$	109	$	94
Additional liabilities incurred	11		13
Liabilities acquired	65		2
Liabilities settled and divested	(36)		(8)
Accretion expense	9		7
Revisions in estimated liabilities	13		1
Asset retirement obligations, end of period	171		109
Less: current portion(1)	5		1
Asset retirement obligations - long-term	$	166	$	108

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

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.

F-25

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

10. EQUITY METHOD INVESTMENTS

At December 31, 2021 and 2020, Rattler had the following investments:


	Ownership Interest		December 31, 2021		December 31, 2020
			(In millions)
EPIC Crude Holdings, LP	10	%	$	107	$	121
Gray Oak Pipeline, LLC	10	%	121		130
Wink to Webster Pipeline LLC(1)	4	%	86		83
OMOG JV LLC	60	%	188		194
Amarillo Rattler, LLC(2)	—	%	—		5
Remuda Midstream Holdings LLC	25	%	111		—
Total			$	613	$	533

(1)The Wink to Webster joint venture is developing a crude oil pipeline (the “Wink to Webster pipeline”). The Wink to Webster pipeline’s main segment began interim service operation in the fourth quarter of 2020, and the joint venture is expected to begin full commercial operations in the first quarter of 2022.

(2)The ownership interest in Amarillo Rattler was 50% at December 31, 2020. See Note 4—Acquisitions and D ivestitures for discussion regarding the sale of this equity method investment during the second quarter of 2021.

Income (loss) and distributions from Rattler’s equity method investees were not material for the years ended December 31, 2021, 2020 or 2019.

The Company reviews its equity method investments to determine if a loss in value which is other than temporary has occurred when events indicate the carrying value of the investment may not be recoverable. Based on indicators present at December 31, 2021, the Company reviewed its investment in EPIC and determined the carrying value of the investment was less than its estimated fair value due to a reduction in expected future cash flow. However, based on the Company’s review of various factors leading to the decline in the fair value of the investment, it was determined the carrying value of the EPIC investment will recover in the near term and therefore an other than temporary impairment in the carrying value of the EPIC equity method investment did not exist at December 31, 2021. However, should the conclusions on certain factors included in the Company’s analysis, including estimates of EPIC’s future cash flows, change, the Company may recognize an impairment that could materially impact it’s consolidated financial statements. No significant impairments were recorded for Rattler’s equity method investments for the years ended December 31, 2020 or 2019. Rattler’s investees all serve customers in the oil and natural gas industry, which experienced economic challenges due to the COVID-19 pandemic and other macroeconomic factors during 2020 prior to recovering in 2021. If similar economic challenges occur in future interim periods, it could result in circumstances requiring Rattler to record potentially material impairment charges on its equity method investments.

F-26

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

11. DEBT

The Company’s debt consisted of the following as of the dates indicated:


	December 31,
	2021		2020
	(In millions)
4.625% Notes due 2021(1)	$	—	$	191
5.375% Senior Notes due 2022(3)	25		—
7.320% Medium-term Notes, Series A, due 2022(4)	20		20
5.250% Senior Notes due 2023(3)	10		—
2.875% Senior Notes due 2024	1,000		1,000
4.750% Senior Notes due 2025	500		500
5.375% Senior Notes due 2025(2)	—		800
3.250% Senior Notes due 2026	800		800

5.625% Senior Notes due 2026(3)	14		—
7.125% Medium-term Notes, Series B, due 2028(4)	100		100
3.500% Senior Notes due 2029	1,200		1,200
3.125% Senior Notes due 2031	900		—
4.400% Senior Notes due 2051	650		—
DrillCo Agreement(5)	58		79
Unamortized debt issuance costs	(31)		(29)
Unamortized discount costs	(28)		(27)
Unamortized premium costs	8		15
Fair value of interest rate swap agreements(6)	(18)		—
Revolving credit facility	—		23
Viper revolving credit facility	304		84
Viper 5.375% Senior Notes due 2027	480		480
Rattler revolving credit facility	195		79
Rattler 5.625% Senior Notes due 2025	500		500
Total debt, net	6,687		5,815
Less: current maturities of long-term debt	(45)		(191)
Total long-term debt	$	6,642	$	5,624

(1) In June 2021, the Company redeemed the remaining $191 million principal amount of outstanding legacy 4.625% senior notes due September 1, 2021 of Energen.

(2) In August 2021, the Company redeemed the remaining $432 million principal amount of its outstanding 5.375% 2025 Senior Notes.

(3) At the effective time of the QEP Merger, QEP became a wholly owned subsidiary of the Company and remained the issuer of these senior notes.

(4) In November 2018, Energen became the Company’s wholly owned subsidiary and remained the issuer of these senior notes. In connection with the E&P Merger, Diamondback E&P became the successor issuer under the indenture.

(5) 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. As of December 31, 2021, the amount due to CEMOF related to this alliance was $58 million. As of December 31, 2021, fifteen joint wells under this agreement have been drilled and completed.

(6) The Company has two interest rate swap agreements in place on the Company’s $1.2 billion 3.500% fixed rate senior notes due 2029. See Note 15—Derivatives for additional information on the Company’s interest rate swaps designated as fair value hedges.

F-27

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Debt maturities as of December 31, 2021, excluding debt issuance costs, premiums and discounts and fair value of interest rate swap premiums are as follows:


Year Ending December 31,
	(In millions)
2022	$	45
2023	10
2024	1,195
2025	1,304
2026	814
Thereafter	3,388
Total	$	6,756

References in this section to the Company shall mean Diamondback Energy, Inc. and Diamondback E&P, collectively, unless otherwise specified.

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 2, 2021, Diamondback Energy, Inc., as parent guarantor, and O&G, as borrower (the “Borrower”), entered into a twelfth amendment (the “Amendment”) to the Second Amended and Restated Credit Agreement, dated as of November 1, 2013, with Wells Fargo Bank, National Association, as administrative agent (the “Administrative Agent”), and the lenders party thereto. The Amendment, among other things, (i) extended the maturity date to June 2, 2026, which may be further extended by two one-year extensions pursuant to the terms set forth in the credit agreement, (ii) decreased the total revolving loan commitments from $2.0 billion to $1.6 billion, which may be increased in an amount up to $1.0 billion (for a total maximum commitment amount of $2.6 billion) upon election of the Borrower, subject to obtaining additional lender commitments and satisfaction of customary conditions pursuant to the terms set forth in the credit agreement, (iii) added the ability of the Borrower to incur up to $100 million of the loans under the credit agreement as swingline loans and (iv) changed the interest rate applicable to the loans and certain fees payable under the credit agreement.

Outstanding borrowings under the credit agreement bear interest at a per annum rate elected by the Borrower that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50%, and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. After giving effect to the Amendment, (i) the applicable margin ranges from 0.250% to 1.125% per annum in the case of the alternate base rate, and from 1.250% to 2.125% per annum in the case of LIBOR, in each case based on the pricing level, and (ii) the commitment fee ranges from 0.150% to 0.350% per annum on the average daily unused portion of the commitments, based on the pricing level. The pricing level depends on certain ratings agencies’ ratings of the Company’s long-term senior unsecured debt.

On June 30, 2021, Diamondback E&P, as successor borrower to Diamondback O&G LLC, Diamondback Energy, Inc., as parent guarantor, and the Administrative Agent entered into a Successor Borrower Joinder Agreement (the “Joinder Agreement”) in connection with the E&P Merger. Pursuant to the Joinder Agreement, Diamondback E&P assumed all obligations (including, without limitation, all of the indebtedness) of O&G as the borrower under the credit agreement, the Second Amended and Restated Guaranty Agreement, dated as of November 20, 2019, made by O&G and Diamondback Energy, Inc., and the other documents entered into connection therewith.

As of December 31, 2021, the maximum credit amount available under the credit agreement is $1.6 billion which was fully available for future borrowings, except for an aggregate of $3 million in outstanding letters of credit, which reduce available borrowings under the credit agreement on a dollar for dollar basis. The weighted average interest rate on borrowings under the credit agreement was 1.67%, 2.02% and 4.10% for the years ended December 31, 2021, 2020 and 2019, respectively.

F-28

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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, 2021 and 2020, the Company was in compliance with all financial maintenance 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.

2021 Issuances of Notes

On March 24, 2021, Diamondback Energy, Inc. issued $650 million aggregate principal amount of 0.900% Senior Notes due March 24, 2023 (the “2023 Notes”), $900 million aggregate principal amount of 3.125% Senior Notes due March 24, 2031 (the “2031 Notes”) and $650 million aggregate principal amount of 4.400% Senior Notes due March 24, 2051 (the “2051 Notes” and together with the 2023 Notes and the 2031 Notes, the “March 2021 Notes”) and received proceeds, net of $24 million in debt issuance costs and discounts, of $2.18 billion. The net proceeds were primarily used to fund the repurchase of other senior notes outstanding as discussed further below. Interest on the March 2021 Notes is payable semi-annually in March and September, beginning in September 2021. The Company redeemed the 2023 Notes in November 2021 as discussed in “—Redemptions of Diamondback Notes” below.

The 2031 Notes and the 2051 Notes are the Company’s senior unsecured obligations and are fully and unconditionally guaranteed by Diamondback E&P. The 2031 Notes and the 2051 Notes are senior in right of payment to any of the Company’s future subordinated indebtedness and rank equal in right of payment with all of the Company’s existing and future senior indebtedness. The 2031 Notes and the 2051 Notes are effectively subordinated to the Company’s existing and future secured indebtedness, if any, to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all of the existing and future indebtedness and other liabilities of the Company’s subsidiaries other than Diamondback E&P.

The Company may redeem (i) the 2031 Notes in whole or in part at any time prior to December 24, 2030 and (ii) the 2051 Notes in whole or in part at any time prior to September 24, 2050, in each case at the redemption price set forth in the IG Indenture. If the 2031 Notes or the 2051 Notes are redeemed on or after the dates noted above, in each case, they may be redeemed at a redemption price equal to 100% of the principal amount of the 2031 Notes or 2051 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 IG Indenture, holders may require the Company to purchase some or all of its 2031 Notes or 2051 Notes for cash at a price equal to 101% of the principal amount being purchased, plus accrued and unpaid interest, if any, to the date of purchase.

2021 Redemptions of Notes

On March 17, 2021, at the time of the QEP Merger discussed in Note 4—Acquisitions and Divestitures, QEP had outstanding debt at fair values consisting of $478 million of 5.375% Senior Notes due 2022 (the “QEP 2022 Notes”), $673 million of 5.250% Senior Notes due 2023 (the “QEP 2023 Notes”) and $558 million of 5.625% Senior Notes due 2026 (the “QEP 2026 Notes” and together with the QEP 2022 Notes and QEP 2023 Notes, the “QEP Notes”). Subsequent to the QEP Merger, in March 2021, the Company repurchased pursuant to tender offers commenced by the Company, approximately $1.65 billion in fair value carrying amount of the QEP Notes for total cash consideration of $1.7 billion, including redemption and early premium fees of $152 million, which resulted in a loss on extinguishment of debt during the year ended December 31, 2021 of approximately $47 million. The aggregate fair value of the QEP Notes repurchased consisted of (i) $453 million, or 94.65%, of the outstanding fair value carrying amount of the QEP 2022 Notes, (ii) $663 million, or 98.43%, of the

F-29

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

outstanding fair value carrying amount of the QEP 2023 Notes and (iii) $538 million, or 96.35%, of the outstanding fair value carrying amount of the QEP 2026 Notes.

In March 2021, the Company also repurchased an aggregate of $368 million principal amount of its 5.375% 2025 Senior Notes representing approximately 45.97% of the outstanding 2025 Senior Notes, for total cash consideration of $381 million, including redemption and early premium fees of $13 million. This resulted in a loss on extinguishment of debt during the year ended December 31, 2021 of $14 million. The Company funded the repurchases of the QEP Notes and 2025 Senior Notes with the proceeds from the March 2021 Notes offering discussed above.

In connection with the tender offers to repurchase the QEP Notes discussed above, the Company also solicited consents from holders of the QEP Notes to amend the indenture for the QEP Notes to, among other things, eliminate substantially all of the restrictive covenants and related provisions and certain events of default contained in the indenture under which the QEP Notes were issued. The Company received the requisite number of consents and, on March 23, 2021, entered into a supplemental indenture relating to the QEP Notes adopting these amendments.

In June 2021, the Company redeemed the remaining $191 million principal amount of the outstanding 4.625% senior notes of Energen due on September 1, 2021. The Company recorded an immaterial pre-tax loss on extinguishment of debt related to the redemption, which included the write-off of unamortized debt discounts associated with the redeemed notes. The Company funded the redemption with internally generated cash flow from operations as well as proceeds from the divestitures of certain non-core assets as discussed in Note 4—Acquisitions and Divestitures.

In August 2021, the Company redeemed the remaining $432 million principal amount of its outstanding 5.375% 2025 Senior Notes for total cash consideration of $449 million, including redemption and early premium fees of $12 million, which resulted in a loss on extinguishment of debt during the year ended December 31, 2021 of $12 million. The Company funded the redemption with cash on hand and borrowings under its revolving credit facility.

On November 1, 2021, the Company redeemed the aggregate $650 million principal amount of its outstanding 2023 Notes at a redemption price equal to 100% of the principal amount, plus accrued and unpaid interest up to, but not including, the redemption date. The Company funded the redemption with proceeds received from the divestiture of its Williston Basin assets and cash on hand.

Viper’s Credit Agreement

On June 2, 2021, Viper LLC entered into the seventh amendment to the existing credit agreement, which (i) extended the maturity date under the credit agreement to June 2, 2025, (ii) changed the interest rates applicable to the loans under the credit agreement and certain fees payable under the credit agreement, and (iii) added a financial covenant requiring the ratio of secured debt to EBITDAX (as each is defined in the credit agreement) to be not greater than 2.50 to 1.0. On November 15, 2021, Viper LLC entered into the eighth amendment to the existing credit agreement, which maintained the maximum amount of the revolving credit facility of $2.0 billion, reaffirmed the borrowing base of $580 million based on Viper LLC’s oil and natural gas reserves and other factors and added new provisions that allow Viper LLC to elect a commitment amount that is less than its borrowing base as determined by the lenders. The borrowing base is scheduled to be redetermined semi-annually in May and November. In addition, Viper LLC and Wells Fargo may each request up to three interim redeterminations of the borrowing base during any 12-month period. As of December 31, 2021, Viper LLC had elected a commitment amount of $500 million, with $304 million of outstanding borrowings and $196 million available for future borrowings under the Viper credit agreement.

The outstanding borrowings under the Viper credit agreement bear interest at a 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 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 1.00% to 2.00% per annum in the case of the alternate base rate and from 2.00% to 3.00% per annum in the case of LIBOR, in each case depending on the amount of loans outstanding in relation to the commitment, which is calculated using the least of the maximum credit amount, the aggregate elected commitment 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 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 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

F-30

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (iii) at the maturity date. The loan is secured by substantially all of the assets of Viper and Viper LLC. The weighted average interest rates on borrowings under the Viper credit agreement were 2.35%, 2.20%, and 4.51% for the years ended December 31, 2021, 2020 and 2019, respectively.

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, excess cash 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 in the Viper credit agreement			Not less than 1.0 to 1.0
Ratio of secured debt to EBITDAX, as defined in the Viper credit agreement			Not greater than 2.5 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. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.

As of December 31, 2021, Viper LLC was in compliance with all financial maintenance covenants under the Viper credit agreement. 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. With certain specified exceptions, the terms and provisions of the credit agreement generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.

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, as administrative agent, and a syndicate of banks, as lenders party thereto (the “Rattler credit agreement”).

The Rattler credit agreement, as amended, provides for a revolving credit facility in the maximum credit amount of $600 million, which is expandable to $1.0 billion upon Rattler’s election, subject to obtaining additional lender commitments and satisfaction of customary conditions. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary 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, Rattler Ajax Processing LLC, Rattler WTG LLC and Rattler Holdings and is secured by substantially all of the assets of Rattler and Rattler LLC. On December 21, 2021, Rattler, as parent, entered into a third amendment (the “Third Amendment”) to the Credit Agreement, dated as of May 28, 2019, with Rattler LLC, as borrower, Wells Fargo Bank, National Association, as administrative agent, and the lenders from time to time party thereto to, among other things, (i) permit the Rattler internal reorganization, including, without limitation, the formation of Rattler Holdings LLC (“Rattler Holdings”) and the contribution of 100% of the limited liability company interests Rattler held in Rattler LLC to Rattler Holdings and (ii) provide for the addition of Rattler Holdings as a guarantor and restricted subsidiary. As of December 31, 2021, Rattler LLC had $195 million of outstanding borrowings and $405 million available for future borrowings under the Rattler credit agreement.

The outstanding borrowings under the Rattler credit agreement bear interest at a 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 weighted average interest rates on borrowings under the Rattler credit agreement were 1.41%, 2.10%, and 3.13% for the years ended December 31, 2021, 2020 and 2019, respectively.

F-31

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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 or Rattler LLC 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						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 Financial Covenant Election (as defined in the Rattler credit agreement) is made, 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)						Not less than 2.50 to 1.00

As of December 31, 2021, Rattler LLC was in compliance with all financial maintenance 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. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial maintenance covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods. With certain specified exceptions, the terms and provisions of the Credit Agreement generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.

Interest expense

The following amounts have been incurred and charged to interest expense for the years ended December 31, 2021, 2020 and 2019:


	Year Ended December 31,
	2021		2020		2019
	(In millions)
Interest expense	$	277	$	250	$	235
Other fees and expenses	11		6		4
Less: interest income	1		4		1
Less: capitalized interest	88		55		66
Interest expense, net	$	199	$	197	$	172

12. STOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE

Diamondback did not complete any equity offerings during the years ended December 31, 2021, 2020 and 2019.

Stock Repurchase Programs

In September 2021, the Company’s board of directors approved a stock repurchase program to acquire up to $2 billion of the Company’s outstanding common stock. Purchases under the repurchase program may be made from time to time in open market or privately negotiated transactions, and are subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program does not require the Company to acquire any specific

F-32

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

number of shares. This repurchase program may be suspended from time to time, modified, extended or discontinued by the board of directors at any time. During the year ended December 31, 2021, the Company repurchased approximately $431 million of common stock under this repurchase program, respectively. As of December 31, 2021, $1.6 billion remained available for use to repurchase shares under the Company’s common stock repurchase program.

In May 2019, the Company’s board of directors approved a stock repurchase program to acquire up to $2 billion of the Company’s outstanding common stock through December 31, 2020. Purchases under the repurchase program were made from time to time in open market or privately negotiated transactions, and were subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program did not require the Company to acquire any specific number of shares. During the years ended December 31, 2020 and 2019, the Company repurchased $98 million and $598 million, respectively, of its common stock under the repurchase program. The repurchase program was suspended beginning in the first quarter of 2020 and expired on December 31, 2020.

Change in Ownership of Consolidated Subsidiaries

Non-controlling interests in the accompanying consolidated financial statements represent minority interest ownership in Viper and Rattler and are presented as a component of equity. The Company’s ownership percentage in Viper and Rattler change as a result of public offerings, issuance of units for acquisitions, issuance of unit-based compensation, repurchases of common units and distribution equivalent rights paid on its units. These changes in ownership percentage and the disproportionate allocation of net income to the Company result in the difference between the Company’s share of the underlying net book value in Viper and Rattler. When the Company’s relative ownership interests in Viper and Rattler change, adjustments to non-controlling interest and additional paid-in-capital, tax effected, will occur.

The following table summarizes changes in the ownership interest in consolidated subsidiaries during the period:


	Year Ended December 31,
	2021		2020		2019
	(In millions)
Net income (loss) attributable to the Company	$	2,182	$	(4,517)	$	240
Change in ownership of consolidated subsidiaries(1)	66		358		(33)
Change from net income (loss) attributable to the Company's stockholders and transfers to non-controlling interest	$	2,248	$	(4,159)	$	207

(1) The year ended December 31, 2020 includes an adjustment to non-controlling interest for Rattler of $329 million and to additional paid-in-capital of $329 million to reflect the ownership structure that was effective at June 30, 2020. The adjustment had no impact on the consolidated statement of income or consolidated statement of cash flows for the year ended December 31, 2020.

Viper Unitholders’ Equity

For information regarding Viper’s significant equity transactions, refer to Note 5—Viper Energy Partners LP.

Rattler Unitholders’ Equity

For information regarding Rattler’s significant equity transactions, refer to Note 6—Rattler Midstream LP.

Earnings (Loss) Per Share

The Company’s basic earnings (loss) 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, the per share earnings of Viper and Rattler are included in the consolidated earnings per share computation based on the consolidated group’s holdings of the subsidiaries.

F-33

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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


	Year Ended December 31,
	2021		2020		2019
	(In millions, except per share amounts, shares in thousands)
Net income (loss) attributable to common stock	$	2,182	$	(4,517)	$	240
Weighted average common shares outstanding:
Basic weighted average common shares outstanding	176,643		157,976		163,493
Effect of dilutive securities:
Potential common shares issuable(1)(2)	716		—		350
Diluted weighted average common shares outstanding	177,359		157,976		163,843
Basic net income (loss) attributable to common stock	$	12.35	$	(28.59)	$	1.47
Diluted net income (loss) attributable to common stock	$	12.30	$	(28.59)	$	1.47

(1) For the year ended December 31, 2021, there were 115,865 potential common shares excluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive under the treasury stock method.

(2) For the year ended December 31, 2020, there were 696,223 potential common shares excluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive due to recording a net loss.

13. EQUITY-BASED COMPENSATION

On June 3, 2021, the Company’s stockholders approved and adopted the Company’s 2021 amended and restated equity incentive plan (the “Equity Plan”), which, among other things, increased total shares authorized for issuance from 8.3 million to 11.8 million. At December 31, 2021, the Company had 6.9 million shares of common stock available for future grants.

Under the Equity Plan, approved by the Board of Directors, the Company is authorized to issue incentive and non-statutory stock options, restricted stock awards and restricted stock units, performance awards and stock appreciation rights to eligible employees. At December 31, 2021, the Company had outstanding restricted stock units, performance-based restricted stock units, immaterial amounts of restricted share awards which were assumed in connection with the QEP Merger, and immaterial amounts of stock options and stock appreciation rights.

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


	Year Ended December 31,
	2021		2020		2019
	(In millions)
General and administrative expenses	$	51	$	37	$	48
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	$	20	$	16	$	17

Restricted Stock Units

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.

F-34

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

The following table presents the Company’s restricted stock unit activity under the Equity Plan during the year ended December 31, 2021:


	Restricted Stock Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2020	1,113,480	$	48.58
Granted	776,045	$	82.98
Vested	(713,777)	$	65.07
Forfeited	(96,159)	$	52.14
Unvested at December 31, 2021	1,079,589	$	62.09

The aggregate fair value of restricted stock units that vested during the years ended December 31, 2021, 2020 and 2019 was $46 million, $25 million and $45 million, respectively. As of December 31, 2021, the Company’s unrecognized compensation cost related to unvested restricted stock units was $52 million. Such cost is expected to be recognized over a weighted-average period of 2.0 years.

During the year ended December 31, 2020, the Company modified an insignificant amount of restricted stock units to include dividend equivalent rights during the vesting period which did not result in any incremental compensation costs.

Performance-Based Restricted Stock Units

To provide long-term incentives for 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 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 based upon the TSR during the performance period of January 1, 2019 to December 31, 2021, subject to continued employment. All remaining awards under this grant cliff vested at December 31, 2021 at 100% based on the final TSR 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 had a performance period of January 1, 2019 to December 31, 2021 and were awarded at 100% based upon the final TSR. The awards under this grant vest in five equal installments beginning on March 1, 2025.

In March 2020, eligible employees received performance restricted stock unit awards totaling 225,047 units from which a minimum of 0% and a maximum of 200% units could be awarded based upon the TSR during the three-year performance period of January 1, 2020 to December 31, 2022 and cliff vest at December 31, 2022 subject to continued employment. The initial payout of the March 2020 awards will be further adjusted by a TSR modifier that may reduce the payout or increase the payout up to a maximum of 250%.

In March 2021, eligible employees received performance restricted stock unit awards totaling 198,454 units from which a minimum of 0% and a maximum of 200% of the units could be awarded based upon the measurement of total stockholder return of the Company’s common stock as compared to a designated peer group during the three-year performance period of January 1, 2021 to December 31, 2023 and cliff vest at December 31, 2023 subject to continued employment. The initial payout of the March 2021 awards will be further adjusted by a TSR modifier that may reduce the payout or increase the payout up to a maximum of 250%.

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

F-35

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

The following table presents a summary of the grant-date fair values of performance restricted stock units granted and the related assumptions for the awards granted during the period presented:


	2021		2020			2019
Grant-date fair value	131.06		$	70.17		$	137.22
Grant-date fair value (5-year vesting)						$	132.48
Risk-free rate	0.15	%	0.86		%	2.55		%
Company volatility	69.60	%	36.70		%	35.00		%

The following table presents the Company’s performance restricted stock unit activity under the Equity Plan for the year ended December 31, 2021:


	Performance Restricted Stock Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2020	411,587	$	99.10
Granted	198,454	$	131.06
Vested	(153,582)	$	137.22
Forfeited	—	$	—
Unvested at December 31, 2021(1)	456,459	$	100.17

(1)A maximum of 1,091,711 units could be awarded based upon the Company’s final TSR ranking.

As of December 31, 2021, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $26 million, which is expected to be recognized over a weighted-average period of 1.9 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”) which authorized a total of 15.2 million common units for issuance, 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. Excluding unvested common units, as of December 31, 2021, a total of 12,696,146 common units had been reserved for future issuance pursuant to the Rattler 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 Rattler LTIP is administered by the board of directors of Rattler’s General Partner or a committee thereof.

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 based on closing price of Rattler’s common units on the grant date of the award, and expenses this value 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.

F-36

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

The following table presents the phantom unit activity under the Rattler LTIP for the year ended December 31, 2021:


	Phantom Units	Weighted Average Grant-Date Fair Value
Unvested at December 31, 2020	2,089,668	$	17.07
Granted	259,916	$	11.07
Vested	(571,341)	$	16.34
Forfeited	(40,718)	$	7.28
Unvested at December 31, 2021	1,737,525	$	16.64

The aggregate fair value of phantom units that vested during the year ended December 31, 2021 was $9 million. As of December 31, 2021, the unrecognized compensation cost related to unvested phantom units was $23 million which is expected to be recognized over a weighted-average period of 2.3 years.

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 Company’s effective income tax rates were 21.7%, 19.1% and 13.0% for the years ended December 31, 2021, 2020 and 2019, respectively. Total income tax expense for the year ended December 31, 2021 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to state income taxes, net of federal benefit. Total income tax benefit for the year ended December 31, 2020 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax loss for the period primarily due to the impact of recording a valuation allowance on Viper’s deferred tax assets, partially offset by state income taxes net of federal benefit and by tax benefit resulting from the carryback of federal net operating losses. 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 impact of deferred taxes recognized as a result of Viper’s change in tax status and state income taxes net of federal benefit.

The Company considered the impact of the American Rescue Plan Act, enacted on March 11, 2021, and concluded its provisions related to U.S. income taxes for corporations did not materially affect the Company’s current or deferred tax balances. Under provisions enacted March 27, 2020 in the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”), the Company realized income tax benefit of $25 million in the period of enactment related to the carryback of approximately $179 million of the Company’s federal net operating losses to tax years in which the corporate income tax rate was 35%. Prior to the enactment of the CARES Act in the first quarter of 2020, there was no tax refund available to the Company with respect to its losses, resulting in deferred tax assets associated with federal net operating loss carryforwards at the statutory 21% corporate income tax rate. As a result of the refund associated with such carryback as well as the accelerated refund available for minimum tax credits, the Company received a refund of federal taxes in the first quarter of 2021 of approximately $100 million. In addition, the Company received in the third quarter of 2021 a federal tax refund of approximately $50 million related to refundable minimum tax credits resulting from carryback of certain federal net operating losses acquired from QEP.

F-37

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, 2021, 2020 and 2019 are as follows:


	Year Ended December 31,
	2021		2020		2019
	(In millions)
Current income tax provision (benefit):
Federal	$	10	$	(62)	$	—
State	15		—		—
Total current income tax provision (benefit)	25		(62)		—
Deferred income tax provision (benefit):
Federal	594		(1,010)		40
State	12		(32)		7
Total deferred income tax provision (benefit)	606		(1,042)		47
Total provision for (benefit from) income taxes	$	631	$	(1,104)	$	47

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


	Year Ended December 31,
	2021		2020		2019
	(In millions)
Income tax expense at the federal statutory rate (21%)	$	610	$	(1,213)	$	76

Income tax benefit relating to net operating loss carryback	—		(25)		—
State income tax expense, net of federal tax effect	23		(30)		6
Non-deductible compensation	10		6		4
Change in valuation allowance	(12)		153		—
Deferred taxes related to change in Viper LP's tax status	—		—		(42)
Other, net	—		5		3
Provision for (benefit from) income taxes	$	631	$	(1,104)	$	47

F-38

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, 2021 and 2020 are as follows:


	December 31,
	2021		2020
	(In millions)












Deferred tax assets:
Net operating loss and other carryforwards	$	682	$	524
Derivative instruments	36		60
Stock based compensation	5		7

Viper's investment in Viper LLC	163		150
Rattler's investment in Rattler LLC	40		58
Other	22		8
Deferred tax assets	948		807
Valuation allowance	(315)		(166)
Deferred tax assets, net of valuation allowance	633		641
Deferred tax liabilities:
Oil and natural gas properties and equipment	1,702		1,156
Midstream investments	224		192


Other	5		3
Total deferred tax liabilities	1,931		1,351
Net deferred tax liabilities	$	1,298	$	710

The Company had net deferred tax liabilities of approximately $1.3 billion and $0.7 billion at December 31, 2021 and 2020, respectively.

At December 31, 2021, the Company had approximately $0.5 billion of federal NOLs expiring in 2037 and $2.0 billion of federal NOLs with an indefinite carryforward life, including NOLs acquired from QEP. 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, including those acquired from QEP, 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. Other than as described below regarding realization of tax attributes acquired from QEP, 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.

On March 17, 2021, the Company completed its acquisition of QEP. For federal income tax purposes, the transaction qualified as a nontaxable merger whereby the Company acquired carryover tax basis in QEP’s assets and liabilities. As of December 31, 2021, QEP’s opening balance sheet net deferred tax asset was approximately $40 million, primarily consisting of deferred tax assets related to tax attributes acquired from QEP, partially offset by a valuation allowance, and deferred tax liabilities resulting from the excess of financial reporting carrying value over tax basis of oil and natural gas properties and other assets acquired from QEP. The acquired income tax attributes, including federal net operating loss and credit carryforwards, are subject to an annual limitation under Section 382. The Company has considered the positive and negative evidence regarding realizability of these federal tax attributes including taxable income in prior carryback years, the annual limitation imposed by Section 382, and the anticipated timing of reversal of its deferred tax liabilities, resulting in a valuation allowance of $23 million on the portion of QEP’s federal tax attributes estimated not more likely than not to be realized prior to expiration. Acquired tax attributes also include state net operating loss carryforwards for which a valuation allowance of $117 million has been provided, since the Company does not believe the state net operating losses are more likely than not to be realized based on its assessment of anticipated future operations in those states.

In addition, as of December 31, 2021, the Company had a valuation allowance of $6 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 and a valuation allowance of $169 million related to Viper’s deferred tax assets, as discussed further below. 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

F-39

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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, 2021, management determined that it is more likely than not that the Company will realize its remaining deferred tax assets.

At December 31, 2021, the Company’s net deferred tax liabilities include deferred tax assets of approximately $6 million related to Viper’s NOL carryforwards and approximately $163 million related to Viper’s investment in Viper LLC. Subsequent to Viper’s change in tax status, deferred taxes are provided on the difference between Viper’s basis for financial accounting purposes and basis for federal income tax purposes in its investment in Viper LLC. As of December 31, 2021, Viper had federal NOL carryforwards of approximately $29 million which may be carried forward indefinitely to offset future taxable income.

As of December 31, 2021, Viper had a valuation allowance of approximately $169 million related to deferred tax assets that Viper does not believe are more likely than not to be realized. Management considers the likelihood that Viper’s NOLs and other deferred tax attributes will be utilized prior to their expiration, if applicable. The determination to record a valuation allowance was based on Management’s assessment of all available evidence, both positive and negative, supporting realizability of Viper’s deferred tax assets as required by applicable accounting standards. In light of those criteria for recognizing the tax benefit of deferred tax assets, the assessment resulted in application of a valuation allowance against Viper’s federal deferred tax assets as of March 31, 2020 and subsequent balance sheet dates within the years ended December 31, 2020 and 2021.

As discussed further in Note 6—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, 2021, the Company’s net deferred tax liabilities include deferred tax assets of approximately $23 million related to Rattlers NOL carryforwards and approximately $40 million related to Rattler’s investment in Rattler LLC. At December 31, 2021, Rattler had federal net operating loss carryforwards of approximately $108 million which may be carried forward indefinitely to offset future taxable income.

Management considers the likelihood that Rattler’s NOLs and other deferred tax attributes will be utilized prior to their expiration, if applicable. At December 31, 2021, Rattler’s assessment included consideration of all available positive and negative evidence, including Rattler’s projected future taxable income and the anticipated timing of reversal of deferred tax assets. As a result of the assessment, management determined that it is more likely than not that Rattler will realize its deferred tax assets as of December 31, 2021.

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


	December 31,
	2021		2020
	(In millions)
Balance at beginning of year	$	7	$	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	(4)		(5)
Total that, if recognized, would impact the effective income tax rate as of the end of the year	$	3	$	2

The Company recognizes the tax benefit from a tax position only if it is more likely than not that it will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. 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

F-40

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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.

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, 2021 and 2020, there was less than $0.2 million of interest and no penalties related to each period associated with uncertain tax positions recognized in the Company’s consolidated financial statements.

15. DERIVATIVES

At December 31, 2021, the Company has commodity derivative contracts and receive-fixed, pay-variable interest rate hedges outstanding. All derivative financial instruments are recorded at fair value.

Commodity Contracts

The Company has entered into multiple crude oil, natural gas and natural gas liquids derivatives, indexed to the respective indices as noted in the table below, to reduce price volatility associated with certain of its oil and natural gas sales. The Company has not designated its commodity derivative instruments as hedges for accounting purposes and, as a result, marks its commodity 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.”

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 has entered into commodity derivative instruments only with counterparties that are also lenders in our credit facility and have been deemed an acceptable credit risk. As such, the Company does not require collateral from its counterparties.

The Company has multiple commodity derivative contracts that contain an other-than-insignificant financing element at inception and, therefore, the cash receipts were classified as cash flows from financing activities in the consolidated statements of cash flow for the year ended December 31, 2021.

F-41

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

As of December 31, 2021, the Company had the following outstanding commodity derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed:


					Swaps		Collars
Settlement Month	Settlement Year	Type of Contract	Bbls/MMBtu Per Day	Index	Weighted Average Differential	Weighted Average Fixed Price	Weighted Average Floor Price	Weighted Average Ceiling Price
OIL
Jan. - June	2022	Swap	1,000	WTI	$—	$45.00	$—	$—
Jan. - June	2022	Swap(1)	13,900	Brent	$—	$67.54	$—	$—
Jan. - June	2022	Basis Swap(2)	17,000	Argus WTI Midland	$0.66	$—	$—	$—
July - Dec.	2022	Basis Swap(2)	10,000	Argus WTI Midland	$0.84	$—	$—	$—

Jan. - Dec.	2022	Roll Swap	30,000	WTI	$0.65	$—	$—	$—
Jan. - Mar.	2022	Costless Collar	19,500	WTI	$—	$—	$46.28	$72.67
Jan. - Mar.	2022	Costless Collar	55,000	Brent	$—	$—	$45.55	$71.08
Jan. - Mar.	2022	Costless Collar	22,000	Argus WTI Houston	$—	$—	$45.91	$70.95
Apr. - June	2022	Costless Collar	13,000	WTI	$—	$—	$46.92	$75.00
Apr. - June	2022	Costless Collar	34,000	Brent	$—	$—	$46.47	$77.00
Apr. - June	2022	Costless Collar	26,000	Argus WTI Houston	$—	$—	$46.92	$72.78
July - Sep.	2022	Costless Collar	4,000	WTI	$—	$—	$45.00	$92.65
July - Sep.	2022	Costless Collar	11,000	Brent	$—	$—	$47.73	$78.65
July - Sep.	2022	Costless Collar	10,000	Argus WTI Houston	$—	$—	$50.00	$76.66
Oct. - Dec.	2022	Costless Collar	5,000	Brent	$—	$—	$45.00	$75.56
NATURAL GAS
Jan. - Dec.	2022	Basis Swap(2)	230,000	Waha Hub	$(0.36)	$—	$—	$—
Jan. - Mar.	2022	Costless Collar	350,000	Henry Hub	$—	$—	$2.67	$4.76
Apr. - June	2022	Costless Collar	370,000	Henry Hub	$—	$—	$2.64	$4.89
July - Dec.	2022	Costless Collar	260,000	Henry Hub	$—	$—	$2.67	$5.40
Jan. - June	2023	Basis Swap(2)	60,000	Waha Hub	$(0.57)	$—	$—	$—
July - Dec.	2023	Basis Swap(2)	40,000	Waha Hub	$(0.60)	$—	$—	$—
Jan. - Mar.	2023	Costless Collar	80,000	Henry Hub	$—	$—	$2.75	$6.83
Apr. - Dec.	2023	Costless Collar	60,000	Henry Hub	$—	$—	$2.75	$5.72

(1) Excludes 8,250 BO/d of Brent swaptions, whereby the counterparty has the right to exercise the hedge at a weighted-average price of $68.62/Bbl in the second half of 2022.

(2) The Company has fixed price basis swaps for the spread between the Cushing crude oil price and the Midland WTI crude oil price as well as the spread between the Henry Hub natural gas price and the Waha Hub natural gas price. The weighted average differential represents the amount of reduction to the Cushing, Oklahoma, oil price and the Waha Hub natural gas price for the notional volumes covered by the basis swap contracts.

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)


Settlement Month	Settlement Year	Type of Contract	Bbls Per Day	Index	Strike Price	Weighted Average Differential	Deferred Premium
OIL
Jan. - Mar.	2022	Put	9,500	WTI	$47.51	$—	$1.57
Jan. - Mar.	2022	Put	14,000	Brent	$50.00	$—	$1.66
Jan. - Sep.	2022	Put	8,000	Argus WTI Houston	$50.00	$—	$1.93
Oct. - Dec.	2022	Put	6,000	Argus WTI Houston	$50.00	$—	$1.88
Apr. - June	2022	Put	8,000	WTI	$47.50	$—	$1.55
Apr. - June	2022	Put	24,000	Brent	$50.00	$—	$1.80
July - Sep.	2022	Put	20,000	Brent	$50.00	$—	$1.84
Oct. - Dec.	2022	Put	16,000	Brent	$50.00	$—	$1.84
Jan. - Dec.	2022	Basis Put	50,000	Brent	$—	$(10.40)	$0.78

Interest Rate Swaps

In the second quarter of 2021, the Company entered into two interest rate swap agreements for notional amounts of $600 million each to limit the Company’s exposure to changes in the fair value of debt due to movements in LIBOR interest rates. These interest rate swaps have been designated as fair value hedges of the Company’s $1.2 billion 3.50% fixed rate senior notes due 2029 (the “2029 Notes”) whereby the Company will receive the fixed rate of interest and will pay an average variable rate of interest based on three month LIBOR plus 2.1865%. Gains and losses due to changes in the fair value of the interest rate swaps completely offset changes in the fair value of the hedged portion of the underlying debt, and were not material for the year ended December 31, 2021. These interest rate swaps are assumed to be perfectly effective and were determined to qualify for the shortcut method of accounting. The swaps expire on December 1, 2029, with an alternative early termination date of September 1, 2029, which mirrors the call option in the 2029 Notes.

During 2020 and the first quarter of 2021, the Company used interest rate swaps to reduce its exposure to variable rate interest payments associated with the Company’s revolving credit facility. These interest rate swaps were not designated as hedging instruments and as a result, the Company recognized all changes in fair value immediately in earnings. During the first quarter of 2021, the Company terminated all of its previously outstanding interest rate swaps which resulted in cash received upon settlement of $80 million, net of fees, during the year ended December 31, 2021. The interest rate swaps contained an other-than-insignificant financing element at inception, and therefore, the cash receipts were classified as cash flows from financing activities in the consolidated statements of cash flow for the year ended December 31, 2021.

Balance Sheet Offsetting of Derivative Assets and Liabilities

The fair value of derivative instruments 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, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. See Note 16—Fair Value Measurements for further details.

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

Gains and Losses on Derivative Instruments

The following table summarizes the gains and losses on derivative instruments not designated as hedging instruments included in the consolidated statements of operations:


	Year Ended December 31,
	2021		2020		2019
	(In millions)
Gain (loss) on derivative instruments, net:
Commodity contracts	$	(978)	$	(32)	$	(151)
Interest rate swaps	130		(49)		43
Total	$	(848)	$	(81)	$	(108)

Net cash received (paid) on settlements:
Commodity contracts(1)(2)	$	(1,305)	$	250	$	37
Interest rate swaps(3)	80		—		43
Total	$	(1,225)	$	250	$	80

(1)The year ended December 31, 2021 includes cash paid on commodity contracts terminated prior to their contractual maturity of $16 million.

(2)The year ended December 31, 2020 includes cash received on commodity contracts terminated prior to their contractual maturity of $17 million.

(3)The years ended December 31, 2021 and 2019 include cash received on interest rate swap contracts terminated prior to their contractual maturity of $80 million and $43 million, respectively.

16. FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

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 commodity derivative instruments and interest rate swaps. The fair values of the Company’s commodity derivative contracts 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. Interest rate swaps designated as fair value hedges and those that are not designated as hedges are determined based on inputs that are readily available in public markets, can be derived from information available in publicly quoted markets, or are provided by financial institutions that trade these contracts. These valuations are Level 2 inputs. The net fair value of the Company’s interest rate swaps designated as hedges are included in long-term debt in the consolidated balance sheet.

The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Company’s consolidated balance sheets as of December 31, 2021 and December 31, 2020. The net amounts of derivative instruments are classified as current or noncurrent based on their anticipated settlement dates.


	As of December 31, 2021
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In millions)
Assets:
Current:
Derivative instruments	$	—	$	60	$	—	$	60	$	(57)	$	3
Interest rate swaps designated as hedges	$	—	$	10	$	—	$	10	$	—	$	10
Non-current:
Derivative instruments	$	—	$	12	$	—	$	12	$	(8)	$	4
Interest rate swaps designated as hedges	$	—	$	1	$	—	$	1	$	(1)	$	—
Liabilities:
Current:
Derivative instruments	$	—	$	231	$	—	$	231	$	(57)	$	174

Non-current:
Derivative instruments	$	—	$	9	$	—	$	9	$	(8)	$	1
Interest rate swaps designated as hedges	$	—	$	29	$	—	$	29	$	(1)	$	28

F-45

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)


	As of December 31, 2020
	Level 1		Level 2		Level 3		Total Gross Fair Value		Gross Amounts Offset in Balance Sheet		Net Fair Value Presented in Balance Sheet
	(In millions)
Assets:
Current:
Derivative instruments	$	—	$	43	$	—	$	43	$	(42)	$	1

Non-current:
Derivative instruments	$	—	$	187	$	—	$	187	$	(187)	$	—

Liabilities:
Current:
Derivative instruments	$	—	$	291	$	—	$	291	$	(42)	$	249

Non-current:
Derivative instruments	$	—	$	244	$	—	$	244	$	(187)	$	57

Assets and Liabilities Not Recorded at Fair Value

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


	December 31, 2021				December 31, 2020
	Carrying				Carrying
	Value		Fair Value		Value		Fair Value
	(In millions)
Debt	$	6,687	$	7,148	$	5,815	$	6,213

The fair values of the Company’s credit agreement, the Viper credit agreement and the Rattler credit agreement approximate their carrying values 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 values of the outstanding notes were determined using the December 31, 2021 quoted market prices, a Level 1 classification in the fair value hierarchy.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis in certain circumstances. These assets and liabilities can include those acquired in a business combination, inventory, proved and unproved oil and gas properties and other long-lived assets that are written down to fair value when they are impaired or held for sale. Refer to Note 4—Acquisitions and Divestitures and Note 8—Property and Equipment for additional discussion of nonrecurring fair value adjustments.

Fair Value of Financial Assets

The carrying amount of cash and cash equivalents, receivables, funds held in escrow, prepaid expenses and other current assets, payables and other accrued liabilities approximate their fair value because of the short-term nature of the instruments.

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

17. SUPPLEMENTAL INFORMATION TO STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2021		2020		2019
	(In millions)
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest	$	194	$	221	$	187
Cash paid (received) for income taxes	$	(138)	$	—	$	—
Supplemental disclosure of non-cash transactions:
Accrued capital expenditures included in accounts payable and accrued expenses	$	287	$	213	$	553
Capitalized stock-based compensation	$	20	$	16	$	17
Common stock issued for business combinations	$	1,727	$	—	$	—
Asset retirement obligations acquired	$	65	$	2	$	4

18. COMMITMENTS AND CONTINGENCIES

The Company is a party to various legal proceedings, disputes and claims arising in the ordinary course of its business, including those that arise from interpretation of federal and state laws and regulations affecting the crude oil and natural gas industry, personal injury claims, title disputes, royalty disputes, contract claims, contamination claims relating to oil and natural gas exploration and development and environmental claims, including 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’s management believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Company’s financial condition, results of operations or cash flows. 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.

Commitments

The following is a schedule of minimum future payments with commitments that have initial or remaining noncancellable terms in excess of one year as of December 31, 2021:


Year Ending December 31,	Transportation Commitments(1)		Sand Supply Agreement(2)		Produced Water Disposal Commitments(3)
	(In millions)
2022	$	82	$	18	$	5
2023	85		18		5
2024	81		18		5
2025	86		18		5
2026	92		5		4
Thereafter	452		—		27
Total	$	878	$	77	$	51

(1)The Company has committed to transport gross quantities of crude oil and natural gas on various pipelines under a variety of contracts including throughput and take-or-pay agreements. The Company’s failure to purchase the minimum level of quantities would require it to pay shortfall fees up to the amount of the original monthly commitment amounts included in the table above.

(2)The Company has committed to purchase minimum quantities of sand for use in its drilling operations. Our failure to purchase the minimum level of quantities would require us to pay shortfall fees up to the commitment amounts included in the table above.

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

(3)Rattler entered into a minimum volume commitment to purchase produced water disposal services under a 14 year agreement beginning in 2021.

At December 31, 2021, the Company’s delivery commitments covered the following gross volumes of oil:


Year Ending December 31,						Oil Volume Commitments (Bbl/d)
2022						175,000
2023						175,000
2024						125,000
2025						125,000
2026						125,000
Thereafter						325,000
Total						1,050,000

As of December 31, 2021, Rattler’s anticipated future capital commitments for its equity method investments total $28 million in the aggregate. The timing of when capital commitments will be requested can vary, but at December 31, 2021, approximately $11 million of the remaining commitment is expected to be funded in 2022, with the remaining $17 million expected to be funded in 2023.

19. SUBSEQUENT EVENTS

Fourth Quarter 2021 Dividend Declaration

On February 18, 2022, the Board of Directors of the Company declared a cash dividend for the fourth quarter of 2021 of $0.60 per share of common stock, payable on March 11, 2022 to its stockholders of record at the close of business on March 4, 2022.

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Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

20. SEGMENT INFORMATION

The Company reports its operations in two operating segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas and (ii) the midstream operations segment, which is focused on owning, operating, developing and acquiring midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. All of the Company’s equity method investments are included in the midstream operations segment. The segments comprise the structure used by its Chief Operating Decision Maker (“CODM”) to make key operating decisions and assess performance.

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


	Upstream		Midstream Operations		Eliminations		Total
	(In millions)
Year Ended December 31, 2021:
Third-party revenues	$	6,747	$	50	$	—	$	6,797
Intersegment revenues	—		371		(371)		—
Total revenues	$	6,747	$	421	$	(371)	$	6,797

Depreciation, depletion, amortization and accretion	$	1,219	$	56	$	—	$	1,275

Income (loss) from operations	$	3,879	$	180	$	(58)	$	4,001
Interest expense, net	$	(167)	$	(32)	$	—	$	(199)
Other income (expense)	$	(925)	$	38	$	(8)	$	(895)
Provision for (benefit from) income taxes	$	620	$	11	$	—	$	631
Net income (loss) attributable to non-controlling interest	$	57	$	37	$	—	$	94
Net income (loss) attributable to Diamondback Energy, Inc.	$	2,110	$	138	$	(66)	$	2,182
Total assets	$	21,329	$	1,942	$	(373)	$	22,898


	Upstream		Midstream Operations		Eliminations		Total
	(In millions)
Year Ended December 31, 2020:
Third-party revenues	$	2,756	$	57	$	—	$	2,813
Intersegment revenues	—		367		(367)		—
Total revenues	$	2,756	$	424	$	(367)	$	2,813

Depreciation, depletion, amortization and accretion	$	1,257	$	54	$	—	$	1,311
Impairment of oil and natural gas properties	$	6,021	$	—	$	—	$	6,021
Income (loss) from operations	$	(5,562)	$	182	$	(96)	$	(5,476)
Interest expense, net	$	(180)	$	(17)	$	—	$	(197)
Other income (expense)	$	(87)	$	(10)	$	(6)	$	(103)
Provision for (benefit from) income taxes	$	(1,114)	$	10	$	—	$	(1,104)
Net income (loss) attributable to non-controlling interest	$	(190)	$	35	$	—	$	(155)
Net income (loss) attributable to Diamondback Energy, Inc.	$	(4,525)	$	110	$	(102)	$	(4,517)
Total assets	$	16,128	$	1,809	$	(318)	$	17,619

F-49

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)


	Upstream		Midstream Operations		Eliminations		Total
	(In millions)
Year Ended December 31, 2019:
Third-party revenues	$	3,891	$	73	$	—	$	3,964
Intersegment revenues	—		375		(375)		—
Total revenues	$	3,891	$	448	$	(375)	$	3,964

Depreciation, depletion, amortization and accretion	$	1,411	$	43	$	—	$	1,454
Impairment of oil and natural gas properties	$	790	$	—	$	—	$	790
Income (loss) from operations	$	790	$	219	$	(314)	$	695
Interest expense, net	$	(171)	$	(1)	$	—	$	(172)
Other income (expense)	$	(149)	$	(6)	$	(6)	$	(161)
Provision for (benefit from) income taxes	$	21	$	26	$	—	$	47
Net income (loss) attributable to non-controlling interest	$	75	$	91	$	(91)	$	75
Net income (loss) attributable to Diamondback Energy, Inc.	$	374	$	95	$	(229)	$	240
Total assets	$	22,125	$	1,636	$	(230)	$	23,531

21. 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,
	2021		2020
	(In millions)
Oil and natural gas properties:
Proved properties	$	24,418	$	19,884
Unproved properties	8,496		7,493
Total oil and natural gas properties	32,914		27,377
Accumulated depletion	(5,434)		(4,237)
Accumulated impairment	(7,954)		(7,954)
Net oil and natural gas properties capitalized	$	19,526	$	15,186

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,
	2021		2020		2019
	(In millions)
Acquisition costs:
Proved properties	$	2,805	$	13	$	194
Unproved properties	1,829		106		418
Development costs	516		381		956
Exploration costs	1,223		1,098		1,915

Total	$	6,373	$	1,598	$	3,483

F-50

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 income tax expense has been calculated by applying statutory income tax rates to oil, gas and natural gas liquids sales after deducting production costs, depreciation, depletion and amortization and accretion and impairment. 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,
	2021		2020		2019
	(In millions)
Oil, natural gas and natural gas liquid sales	$	6,747	$	2,756	$	3,887



Production costs	(1,202)		(760)		(826)
Depreciation, depletion, amortization and accretion	(1,211)		(1,249)		(1,405)
Impairment	—		(6,021)		(790)

Income tax benefit (expense)	(918)		1,151		(186)
Results of operations	$	3,416	$	(4,123)	$	680

Oil and Natural Gas Reserves

Proved oil and natural gas reserve estimates as of December 31, 2021, 2020 and 2019 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-51

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 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
Extensions and discoveries	191,009	58,410	316,035
Revisions of previous estimates	(78,244)	21,927	300,160
Purchase of reserves in place	2,124	778	3,512
Divestitures	(209)	(141)	(905)
Production	(66,182)	(21,981)	(130,549)
As of December 31, 2020	759,401	289,196	1,607,064
Extensions and discoveries	271,222	127,479	720,125
Revisions of previous estimates	(160,570)	(6,685)	195,302
Purchase of reserves in place	176,261	58,587	302,770
Divestitures	(36,503)	(11,597)	(70,048)
Production	(81,522)	(27,246)	(169,406)
As of December 31, 2021	928,289	429,734	2,585,807

Proved Developed Reserves:
December 31, 2018	403,051	125,509	705,084
December 31, 2019	457,083	165,173	824,760
December 31, 2020	443,464	192,495	1,085,035
December 31, 2021	620,474	285,513	1,770,688

Proved Undeveloped Reserves:
December 31, 2018	223,885	64,782	343,565
December 31, 2019	253,820	65,030	294,051
December 31, 2020	315,937	96,701	522,029
December 31, 2021	307,815	144,221	815,119

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, 2021, the Company’s extensions and discoveries of 518,722 MBOE resulted primarily from the drilling of 470 new wells, including 345 wells in which we own only a mineral interest through Viper, and from 439 new proved undeveloped locations added. Viper royalty interests accounted for 6% of the extension volumes. The Company’s downward revisions of previous estimates of 134,705 MBOE were the result of negative revisions of 268,560 MBOE due primarily to PUD downgrades related to changes in the corporate development plan following the QEP and Guidon acquisitions. These negative revisions were partially offset with positive revisions of 133,855 MBOE associated with higher commodity prices and improved well performance. Purchases of 285,309 MBOE primarily resulted from 276,207 MBOE attributable largely to the QEP Merger and Guidon Acquisition, and 9,102 MBOE of Viper royalty purchases, including the Swallowtail Acquisition. Divestitures of 59,775 MBOE related primarily to the Williston Basin Divestiture.

F-52

Diamondback Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements-(Continued)

During the year ended December 31, 2020, the Company’s extensions and discoveries of 302,092 MBOE resulted primarily from the drilling of 682 new wells and from 298 new proved undeveloped locations added. Viper royalty interests accounted for 8% of the extension volumes. The Company’s downward revisions of previous estimates of 6,290 MBOE were the result of negative revisions due to lower product pricing of 54,645 MBOE, which were partially offset by positive revisions of 23,066 MBOE associated with a reduction in lease operating expenses, resulting in a total negative pricing revision of 31,579 MBOE. Downgrades of 31,074 MBOE are primarily from changes in the corporate development plan. These revisions were offset by positive performance revisions of 56,362 MBOE associated with less gas flaring and a corresponding increase in natural gas liquid recoveries.

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. 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.

At December 31, 2021, the Company’s estimated PUD reserves were approximately 587,889 MBOE, an 88,246 MBOE increase over the reserve estimate at December 31, 2020 of 499,643 MBOE. The following table includes the changes in PUD reserves for 2021 (MBOE):


Beginning proved undeveloped reserves at December 31, 2020			499,643
Undeveloped reserves transferred to developed			(172,526)
Revisions			(243,268)
Purchases			63,013
Divestitures			—
Extensions and discoveries			441,027
Ending proved undeveloped reserves at December 31, 2021			587,889

The increase in proved undeveloped reserves was primarily attributable to extensions of 416,327 MBOE from 439 gross (383 net) wells in which the Company has a working interest and 24,700 MBOE from 336 gross wells in which Viper owns royalty interests. Of the 439 gross working interest wells, 409 were in the Midland Basin and 30 were in the Delaware Basin. Transfers of 172,526 MBOE from undeveloped to developed reserves were the result of drilling or participating in 154 gross (142 net) horizontal wells in which the Company has a working interest and 127 gross wells in which the Company has a royalty interest or mineral interest through Viper. The Company owns a working interest in 106 of the 127 gross Viper wells. Downward revisions of 243,268 MBOE were the result of negative revisions of 260,494 MBOE due to downgrades related to changes in the corporate development plan following the QEP and Guidon acquisitions. These negative revisions were partially offset with positive revisions of 17,226 MBOE primarily attributable to higher commodity prices and improved well performance. Purchases of 63,013 MBOE were the result of 59,023 MBOE primarily from QEP and Guidon, and 3,990 MBOE of Viper royalty purchases.

As of December 31, 2021, all of the Company’s proved undeveloped reserves are planned to be developed within five years from the date they were initially recorded. During 2021, approximately $516 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 arithmetic average, first-day-of-the-month price for the rolling 12-month period. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.

F-53

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, 2021, 2020 and 2019:


	December 31,
	2021		2020		2019
	(In millions)
Future cash inflows	$	77,085	$	32,173	$	40,681
Future development costs	(4,243)		(3,585)		(3,809)
Future production costs	(19,123)		(10,763)		(9,319)
Future production taxes	(5,572)		(2,354)		(2,905)
Future income tax expenses	(7,237)		(727)		(2,635)
Future net cash flows	40,910		14,744		22,013
10% discount to reflect timing of cash flows	(22,193)		(7,986)		(11,829)
Standardized measure of discounted future net cash flows(1)	$	18,717	$	6,758	$	10,184

(1) Includes $2.1 billion, $1.0 billion, and $1.3 billion, for the years ended December 31, 2021, 2020 and 2019, respectively, attributable to the Company’s consolidated subsidiary, Viper, in which there is a 54% non-controlling interest at December 31, 2021.

The table below presents the unweighted arithmetic average first-day-of–the-month price for oil, natural gas and natural gas liquids utilized in the computation of future cash inflows:


	December 31,
	2021		2020		2019


Oil (per Bbl)	$	64.78	$	38.06	$	51.88
Natural gas (per Mcf)	$	2.61	$	0.09	$	0.18
Natural gas liquids (per Bbl)	$	23.71	$	10.83	$	15.65

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,
	2021		2020		2019
	(In millions)
Standardized measure of discounted future net cash flows at the beginning of the period	$	6,758	$	10,184	$	11,676
Sales of oil and natural gas, net of production costs	(5,757)		(2,225)		(3,334)
Acquisitions of reserves	1,914		30		309
Divestitures of reserves	(275)		(4)		(500)
Extensions and discoveries, net of future development costs	6,298		1,514		4,004
Previously estimated development costs incurred during the period	548		704		120
Net changes in prices and production costs	10,748		(5,273)		831
Changes in estimated future development costs	(19)		526		(3,190)
Revisions of previous quantity estimates	719		(462)		(1,242)
Accretion of discount	703		1,126		1,344
Net change in income taxes	(2,841)		807		693
Net changes in timing of production and other	(79)		(169)		(527)
Standardized measure of discounted future net cash flows at the end of the period	$	18,717	$	6,758	$	10,184

F-54

Previous: Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES