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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

☒			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2021

OR

☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934

Commission File Number 001-35700

 

Diamondback Energy, Inc.

(Exact Name of Registrant As Specified in Its Charter)

DE									45-4502447
(State or Other Jurisdiction of Incorporation or Organization)									(I.R.S. Employer Identification Number)
500 West Texas
Suite 1200
Midland,			TX						79701
(Address of principal executive offices)									(Zip code)

(432) 221-7400

(Registrant’s telephone number, including area code)

 Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934:

Title of each class			Trading Symbol(s)			Name of each exchange on which registered
Common Stock			FANG			The Nasdaq Stock Market LLC
						(NASDAQ Global Select Market)

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ☒    No  ☐

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

Large Accelerated Filer

☒

Accelerated Filer

☐

Non-Accelerated Filer

☐

Smaller Reporting Company

☐

Emerging Growth Company

☐

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

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

As of April 30, 2021, the registrant had 180,997,368 shares of common stock outstanding.

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DIAMONDBACK ENERGY, INC.

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2021

TABLE OF CONTENTS

			Page
Glossary of Oil and Natural Gas Terms			ii
Glossary of Certain Other Terms			iii
Cautionary Statement Regarding Forward-Looking Statements			iv
PART I. FINANCIAL INFORMATION
Item 1. Condensed Consolidated Financial Statements (Unaudited)			1
Condensed Consolidated Balance Sheets			1
Condensed Consolidated Statements of Operations			3
Condensed Consolidated Statements of Stockholders’ Equity			4
Condensed Consolidated Statements of Cash Flows			5
Condensed Notes to Consolidated Financial Statements			7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			31
Item 3. Quantitative and Qualitative Disclosures About Market Risk			44
Item 4. Controls and Procedures			45
PART II. OTHER INFORMATION
Item 1. Legal Proceedings			45
Item 1A. Risk Factors			46
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			46
Item 6. Exhibits			47
Signatures			48

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GLOSSARY OF OIL AND NATURAL GAS TERMS

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

Basin			A large depression on the earth’s surface in which sediments accumulate.
Bbl or barrel			One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
BOE			One barrel of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BOE/d			BOE per day.
British Thermal Unit or Btu			The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Completion			The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Crude oil			Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
Finding and development costs			Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.
Gross acres or gross wells			The total acres or wells, as the case may be, in which a working interest is owned.
Horizontal wells			Wells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.
MBbl			One thousand barrels of crude oil and other liquid hydrocarbons.
MBOE/d			One thousand BOE per day.
Mcf			One thousand cubic feet of natural gas.
Mineral interests			The interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
MMBtu			One million British Thermal Units.
Net acres or net wells			The sum of the fractional working interest owned in gross acres.
Oil and natural gas properties			Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.
Plugging and abandonment			Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
Prospect			A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved reserves			The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
Reserves			The estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves are not assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Reservoir			A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or crude oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Royalty interest			An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development, which may be subject to expiration.
Working interest			An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

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GLOSSARY OF CERTAIN OTHER TERMS

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

ASC			Accounting Standards Codification.
ASU			Accounting Standards Update.
Equity Plan			The Company’s Equity Incentive Plan.
Exchange Act			The Securities Exchange Act of 1934, as amended.
FASB			Financial Accounting Standards Board.
GAAP			Accounting principles generally accepted in the United States.
2025 Indenture			The indenture relating to the 2025 Senior Notes (defined below), dated as of December 20, 2016, among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented.
2025 Senior Notes			The Company’s 5.375% senior unsecured notes due 2025 in the aggregate principal amount of $800 million.
December 2019 Notes			The Company’s 2.875% senior unsecured notes due 2024 in the aggregate principal amount of $1.0 billion, the Company’s 3.250% senior unsecured notes due 2026 in the aggregate principal amount of $800 million and the Company’s 3.500% senior unsecured notes due 2029 in the aggregate principal amount of $1.2 billion.
December 2019 Notes Indenture			The indenture, dated as of December 5, 2019, among the Company and Wells Fargo, as the trustee, as supplemented by the first supplemental indenture dated as of December 5, 2019 and the second supplemental indenture dated as of May 26, 2020, relating to the December 2019 Notes (defined above), the May 2020 Notes (defined below) and the March 2021 Notes (defined below).
LIBOR			The London interbank offered rate.
May 2020 Notes			The Company’s 4.750% Senior Notes due 2025 in the aggregate principal amount of $500.0 million issued on May 26, 2020 under the December 2019 Notes Indenture (defined above) and the related second supplemental indenture.
March 2021 Notes			The Company’s 0.900% Senior Notes due 2023 in the aggregate principal amount of $650 million, the Company’s 3.125% Senior Notes due 2031 in the aggregate principal amount of $900 million and the Company’s 4.400% Senior Notes due 2051 in the aggregate principal amount of $650 million.
NYMEX			New York Mercantile Exchange.
OPEC			Organization of the Petroleum Exporting Countries.
Rattler			Rattler Midstream LP, a Delaware limited partnership.
Rattler’s General Partner			Rattler Midstream GP LLC, a Delaware limited liability company; the general partner of Rattler Midstream LP and a wholly owned subsidiary of the Company.
Rattler LLC			Rattler Midstream Operating LLC, a Delaware limited liability company and a subsidiary of Rattler.
Rattler LTIP			Rattler Midstream LP Long-Term Incentive Plan.
SEC			United States Securities and Exchange Commission.
Senior Notes			The 2025 Senior Notes, the December 2019 Notes and the May 2020 Notes.
Viper			Viper Energy Partners LP, a Delaware limited partnership.
Viper LLC			Viper Energy Partners LLC, a Delaware limited liability company and a subsidiary of the Partnership.
Wells Fargo			Wells Fargo Bank, National Association.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this report are “forward-looking statements” as defined by the SEC. These forward-looking statements are subject to a number of risks, uncertainties and assumptions, many of which are beyond our control. All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed in this report and detailed under Part II, Item 1A. Risk Factors in this report and our Annual Report on Form 10–K for the year ended December 31, 2020 could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted or implied in such forward-looking statements. Unless the context requires otherwise, references to “we,” “us,” “our” or the “Company” are intended to mean the business and operations of the Company and its consolidated subsidiaries.

Forward-looking statements may include statements about:

•the volatility of realized oil and natural gas prices;

•the implications and logistical challenges of epidemic or pandemic diseases, including the ongoing COVID-19 pandemic on the oil and natural gas industry, including the impact on pricing and demand for oil and natural gas and the supply chain disruptions during the ongoing COVID-19 pandemic;

•logistical challenges and the supply chain disruptions;

•changes in general economic, business or industry conditions, including conditions of the U.S. oil and natural gas industry and the effect of U.S. energy, environmental, monetary and trade policies;

•conditions in the capital, financial and credit markets and our ability to obtain capital needed for development and exploration operations on favorable terms or at all;

•conditions of the U.S. oil and natural gas industry and the effect of U.S. energy, monetary and trade policies;

•our ability to execute our business and financial strategies;

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

•levels of production;

•the impact of reduced drilling activity on our exploration and development drilling prospects, inventories, projects and programs;

•regional supply and demand factors, delays, curtailment delays or interruptions of production, and any governmental order, rule or regulation that may impose production limits;

•our ability to replace our oil and natural gas reserves;

•our ability to identify, complete and effectively integrate acquisitions of properties or businesses, including our recently completed acquisition of certain assets of Guidon Operating LLC and our merger with QEP Resources, Inc., as well as our anticipated synergies and cost savings from these transactions;

•competition in the oil and natural gas industry;

•uncertainties with respect to identified drilling locations and estimates of reserves;

•the impact of severe weather conditions, including the recent winter storms in the Permian Basin, on our production;

•our ability to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;

•our environmental initiatives and targets;

•future operating results;

•future dividends to our stockholders;

•impact of any impairment charges;

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

•capital expenditure plans;

•other plans, objectives, expectations and intentions; and

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•certain other factors discussed elsewhere in this report.

All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities laws. You should not place undue reliance on these forward-looking statements. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.

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PART I. FINANCIAL INFORMATION

ITEM 1.     CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Diamondback Energy, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets
(Unaudited)
			March 31,						December 31,
			2021						2020
			(In millions, except par values and share data)
Assets
Current assets:
Cash and cash equivalents			$	121					$	104
Restricted cash			19						4
Accounts receivable:
Joint interest and other, net			68						56
Oil and natural gas sales, net			531						281
Inventories			52						33
Derivative instruments			—						1
Income tax receivable			33						100
Prepaid expenses and other current assets			27						23
Total current assets			851						602
Property and equipment:
Oil and natural gas properties, full cost method of accounting ($8,430 million and $7,493 million excluded from amortization at March 31, 2021 and December 31, 2020, respectively)			31,765						27,377
Midstream assets			1,018						1,013
Other property, equipment and land			152						138
Accumulated depletion, depreciation, amortization and impairment			(12,583)						(12,314)
Property and equipment, net			20,352						16,214
Funds held in escrow			34						51
Equity method investments			525						533
Derivative instruments			4						—
Deferred income taxes, net			32						73
Investment in real estate, net			101						101
Other assets			97						45
Total assets			$	21,996					$	17,619

See accompanying notes to condensed consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets-(Continued)

(Unaudited)

			March 31,						December 31,
			2021						2020
Liabilities and Stockholders’ Equity			(In millions, except par values and share data)
Current liabilities:
Accounts payable - trade			$	71					$	71
Accrued capital expenditures			233						186
Current maturities of long-term debt			191						191
Other accrued liabilities			416						302
Revenues and royalties payable			353						237
Derivative instruments			604						249
Total current liabilities			1,868						1,236
Long-term debt			7,465						5,624
Derivative instruments			8						57
Asset retirement obligations			190						108
Deferred income taxes			790						783
Other long-term liabilities			23						7
Total liabilities			10,344						7,815
Commitments and contingencies (Note 15)
Stockholders’ equity:
Common stock, $0.01 par value; 200,000,000 shares authorized; 180,984,014 and 158,088,182 shares issued and outstanding at March 31, 2021 and December 31, 2020, respectively			2						2
Additional paid-in capital			14,384						12,656
Retained earnings (accumulated deficit)			(3,713)						(3,864)
Total Diamondback Energy, Inc. stockholders’ equity			10,673						8,794
Non-controlling interest			979						1,010
Total equity			11,652						9,804
Total liabilities and equity			$	21,996					$	17,619

See accompanying notes to condensed consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Operations

(Unaudited)

			Three Months Ended March 31,
			2021						2020
			(In millions, except per share amounts, shares in thousands)
Revenues:
Oil sales			$	944					$	827
Natural gas sales			104						4
Natural gas liquid sales			124						52
Midstream services			11						14
Other operating income			1						2
Total revenues			1,184						899
Costs and expenses:
Lease operating expenses			102						127
Production and ad valorem taxes			75						71
Gathering and transportation			31						36
Midstream services expense			28						23
Depreciation, depletion, amortization and accretion			273						409
Impairment of oil and natural gas properties			—						1,009
Impairment of midstream assets			3						—
General and administrative expenses			25						24
Merger and integration expense			75						—
Other operating expense			1						2
Total costs and expenses			613						1,701
Income (loss) from operations			571						(802)
Other income (expense):
Interest expense, net			(56)						(48)
Other income (expense), net			1						1
Gain (loss) on derivative instruments, net			(164)						542
Gain (loss) on revaluation of investment			—						(10)
Loss on extinguishment of debt			(61)						—
Income (loss) from equity investments			(3)						—
Total other income (expense), net			(283)						485
Income (loss) before income taxes			288						(317)
Provision for (benefit from) income taxes			65						83
Net income (loss)			223						(400)
Net income (loss) attributable to non-controlling interest			3						(128)
Net income (loss) attributable to Diamondback Energy, Inc.			$	220					$	(272)
Earnings (loss) per common share:
Basic			$	1.34					$	(1.72)
Diluted			$	1.33					$	(1.72)
Weighted average common shares outstanding:
Basic			164,169						158,291
Diluted			164,926						158,494
Dividends declared per share			$	0.40					$	0.375

See accompanying notes to condensed consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Stockholders’ Equity

(Unaudited)

			Common Stock												Additional Paid-in Capital						Retained Earnings (Accumulated Deficit)									Non-Controlling Interest						Total
			Shares						Amount
			($ in millions, shares in thousands)
Balance December 31, 2020			158,088						$	2					$	12,656					$	(3,864)								$	1,010					$	9,804
Unit-based compensation			—						—						—						—									3						3
Distribution equivalent rights payments			—						—						—						(1)									—						(1)
Common units issued for acquisitions			22,795						—						1,727						—									—						1,727
Stock-based compensation			—						—						11						—									—						11
Cash paid for tax withholding on vested equity awards			—						—						(6)						—									—						(6)
Repurchased units under buyback programs			—						—						—						—									(24)						(24)
Distributions to non-controlling interest			—						—						—						—									(17)						(17)
Dividend paid			—						—						—						(68)									—						(68)
Exercise of stock options and issuance of restricted stock units and awards			101						—						—						—									—						—
Change in ownership of consolidated subsidiaries, net			—						—						(4)						—									4						—
Net income (loss)			—						—						—						220									3						223
Balance March 31, 2021			180,984						$	2					$	14,384					$	(3,713)								$	979					$	11,652

			Common Stock												Additional Paid-in Capital						Retained Earnings (Accumulated Deficit)									Non-Controlling Interest						Total
			Shares						Amount
			($ in millions, shares in thousands)
Balance December 31, 2019			159,002						$	2					$	12,357					$	890								$	1,657					$	14,906
Unit-based compensation			—						—						—						—									5						5
Distribution equivalent rights payments			—						—						—						—									(1)						(1)
Stock-based compensation			—						—						10						—									—						10
Cash paid for tax withholding on vested equity awards			—						—						(5)						—									—						(5)
Repurchased shares for share buyback program			(1,280)						—						(98)						—									—						(98)
Distribution to non-controlling interest			—						—						—						—									(43)						(43)
Dividend paid			—						—						—						(59)									—						(59)
Exercise of stock options and vesting of restricted stock units			93						—						1						—									—						1
Net income (loss)			—						—						—						(272)									(128)						(400)
Balance March 31, 2020			157,815						$	2					$	12,265					$	559								$	1,490					$	14,316

See accompanying notes to condensed consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(Unaudited)

			Three Months Ended March 31,
			2021						2020
			(In millions)
Cash flows from operating activities:
Net income (loss)			$	223					$	(400)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Provision for (benefit from) deferred income taxes			64						145
Impairment of oil and natural gas properties			—						1,009
Impairment of midstream assets			3						—
Depreciation, depletion, amortization and accretion			273						409
Loss on extinguishment of debt			61						—
(Gain) loss on derivative instruments, net			164						(542)
Cash received (paid) on settlement of derivative instruments			(178)						87
Equity-based compensation expense			10						9
Other			7						12
Changes in operating assets and liabilities:
Accounts receivable			(137)						175
Income tax receivable			100						(62)
Prepaid expenses and other			22						(4)
Accounts payable and accrued liabilities			(26)						(35)
Revenues and royalties payable			50						14
Other			(12)						32
Net cash provided by (used in) operating activities			624						849
Cash flows from investing activities:
Drilling, completions and non-operated additions to oil and natural gas properties			(281)						(690)
Infrastructure additions to oil and natural gas properties			(8)						(56)
Additions to midstream assets			(7)						(44)
Purchase of business and assets, net			(342)						(40)
Acquisitions of mineral interests			—						(65)
Funds held in escrow			50						—
Contributions to equity method investments			(4)						(33)
Other			5						5
Net cash provided by (used in) investing activities			(587)						(923)
Cash flows from financing activities:
Proceeds from borrowings under credit facilities			432						430
Repayments under credit facilities			(455)						(140)
Proceeds from senior notes			2,200						—
Repayment of senior notes			(1,916)						—
Premium on extinguishment of debt			(166)						—
Proceeds from joint venture			(4)						16
Debt issuance costs			(24)						—
Repurchased shares under buyback program			—						(98)
Repurchased units under buyback program			(24)						—
Dividends to stockholders			(68)						(59)
Distributions to non-controlling interest			(17)						(43)
Financing portion of net cash received (paid) for derivative instruments			76						—
Other			(5)						(5)
Net cash provided by (used in) financing activities			29						101
Net increase (decrease) in cash and cash equivalents			66						27
Cash, cash equivalents and restricted cash at beginning of period			108						128
Cash, cash equivalents and restricted cash at end of period(1)			$	174					$	155
(1) See Note 2—Summary of Significant Accounting Policies

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Diamondback Energy, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows - Continued

(Unaudited)

			Three Months Ended March 31,
			2021						2020
			(In millions)
Supplemental disclosure of non-cash transactions:
Accrued capital expenditures included in accounts payable and accrued expenses			$	252					$	646
Common stock issued for business combinations			$	1,727					$	—

See accompanying notes to condensed consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements

(Unaudited)

1.    DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION

Organization and Description of the Business

Diamondback Energy, Inc., together with its subsidiaries (collectively referred to as “Diamondback” or the “Company” unless the context otherwise requires), is an independent oil and natural 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 March 31, 2021, include Diamondback E&P LLC, a Delaware limited liability company, Diamondback O&G LLC (“O&G”), a Delaware limited liability company, Viper Energy Partners GP LLC, a Delaware limited liability company, Rattler Midstream GP LLC, a Delaware limited liability company, Energen Corporation, an Alabama corporation (“Energen”) and QEP Resources, Inc. (“QEP”), a Delaware corporation.

Basis of Presentation

The condensed 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 Energy Partners LP (“Viper”) and Rattler Midstream LP (“Rattler”) are consolidated in the Company’s financial statements. As of March 31, 2021, the Company owned approximately 59% 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 March 31, 2021, the Company owned approximately 72% 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 Company’s equity and net income attributable to the Company.

These condensed consolidated financial statements have been prepared by the Company without audit, pursuant to the rules and regulations of the SEC. They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been omitted pursuant to SEC rules and regulations, although the Company believes the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10–Q should be read in conjunction with the Company’s most recent Annual Report on Form 10–K for the fiscal year ended December 31, 2020, which contains a summary of the Company’s significant accounting policies and other disclosures.

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

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Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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. For instance, in 2020, the effects of COVID-19 and actions by OPEC members and other exporting nations on the supply and demand in global oil and natural gas markets resulted in significant negative pricing pressures in the first half of 2020, followed by a recovery in pricing in the second half of 2020 and into 2021. The financial results of companies in the oil and natural gas industry have been impacted materially as a result of changing market conditions. Such circumstances generally increase the uncertainty in the Company’s accounting estimates, particularly those involving financial forecasts.

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

Cash, Cash Equivalents and Restricted Cash

The following table provides a reconciliation of cash, cash equivalents and restricted cash as reported at the end of the period in the condensed consolidated statements of cash flows for the three months ended March 31, 2021 and 2020 to the line items within the condensed consolidated balance sheets:

			Three Months Ended March 31,
			2021						2020
			(In millions)
Cash and cash equivalents			$	121					$	149
Restricted cash			19						6
Restricted cash included in funds held in escrow(1)			34						—
Total cash, cash equivalents and restricted cash			$	174					$	155

(1) As of March 31, 2021, the restricted cash included in funds held in escrow on the condensed consolidated balance sheet is primarily related to cash deposited into an escrow account for a title dispute between outside parties in the Williston Basin.

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.

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

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Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

3.    REVENUE FROM CONTRACTS WITH CUSTOMERS

Revenue from Contracts with Customers

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

			Three Months Ended March 31, 2021															Three Months Ended March 31, 2020
			Midland Basin			Delaware Basin			Other			Total						Midland Basin			Delaware Basin			Other			Total
			(In millions)
Oil sales			$	569		$	358		$	17		$	944					$	473		$	351		$	3		$	827
Natural gas sales			41			61			2			104						2			2			—			4
Natural gas liquid sales			75			47			2			124						29			23			—			52
Total			$	685		$	466		$	21		$	1,172					$	504		$	376		$	3		$	883

4.    ACQUISITIONS

Guidon Operating LLC

On December 21, 2020, the Company entered into a definitive purchase agreement to acquire 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 Guidon Acquisition closed on February 26, 2021. 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

Purchase Price Allocation

The Guidon Acquisition has been accounted for as a business combination using the acquisition method of accounting. The following table represents the allocation of the total purchase price paid in the Guidon Acquisition to the identifiable assets acquired based on the fair values at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired. Although the purchase price allocation is substantially complete as of the date of this filing, there may be further adjustments to the fair value of certain assets acquired and liabilities assumed, including but not limited to the Company’s oil and natural gas properties. 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.

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Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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 are 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.

With the completion of the Guidon Acquisition, the Company acquired proved properties of $537 million and unproved properties of $573 million. The Company has included in its condensed consolidated statements of operations, revenues of $28 million and direct operating expenses of $12 million for the period from February 26, 2021 to March 31, 2021 attributable to the acquired assets.

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 9—Debt for further discussion.

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 (in thousands)			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, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired. 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. As such, there may be further adjustments to the fair value of certain assets acquired and liabilities assumed, including the Company’s oil and natural gas properties. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date.

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Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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			108
Revenues and royalties payable			67
Derivative instruments			242
Long-term debt			1,710
Asset retirement obligations			54
Other long-term liabilities			47
Amount attributable to liabilities assumed			$	2,292
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			2,938
Other property, equipment and land			9
Deferred income taxes			15
Other assets			106
Amount attributable to assets acquired			3,279
Net assets acquired and liabilities assumed			$	987

The purchase price allocation above was based on preliminary 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 cost which are 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 $2.3 billion and unproved properties of $444 million, primarily in the Midland Basin and the Williston Basin. The Company has included in its condensed consolidated statements of operations, revenues of $54 million and direct operating expenses of $31 million for the period from March 17, 2021 to March 31, 2021 attributable to the QEP business.

Pro Forma Financial Information

The following unaudited summary pro forma financial information for the three months ended March 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.

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Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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 $75 million for the three months ended March 31, 2021 and acquisition-related costs incurred by QEP of $31 million. 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 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.

			Three Months Ended March 31,
			2021						2020
			(In millions, except per share amounts)
Revenues			$	1,481					$	1,190
Income (loss) from operations			$	684					$	(822)
Net income (loss)			$	146					$	58
Basic earnings per common share			$	0.81					$	0.32
Diluted earnings per common share			$	0.80					$	0.32

5.    REAL ESTATE ASSETS    

The following schedule presents the cost and related accumulated depreciation of the Company’s real estate assets. The Company’s intangible lease assets and related accumulated amortization were immaterial as of March 31, 2021 and December 31, 2020.

			Estimated Useful Lives						March 31, 2021						December 31, 2020
			(Years)						(In millions)
Buildings			20-30						$	104					$	102
Tenant improvements			15						5						5
Land			N/A						2						2
Land improvements			15						1						1
Total real estate assets									112						110
Less: accumulated depreciation									(15)						(13)
Total investment in land and buildings, net									$	97					$	97

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Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

6.    PROPERTY AND EQUIPMENT

Property and equipment includes the following as of the dates indicated:

			March 31,						December 31,
			2021						2020
			(In millions)
Oil and natural gas properties:
Subject to depletion			$	23,335					$	19,884
Not subject to depletion			8,430						7,493
Gross oil and natural gas properties			31,765						27,377
Accumulated depletion			(4,493)						(4,237)
Accumulated impairment			(7,954)						(7,954)
Oil and natural gas properties, net			19,318						15,186
Midstream assets			1,018						1,013
Other property, equipment and land			152						138
Accumulated depreciation and impairment			(136)						(123)
Total property and equipment, net			$	20,352					$	16,214

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 three months ended March 31, 2021 and $1.0 billion in impairment expense was recorded during the three months ended March 31, 2020 based on the results of the respective quarterly ceiling tests.

Additionally, no impairment expense was recorded for the three months ended March 31, 2021 in relation to the oil and natural gas properties acquired in the QEP Merger and the Guidon Acquisition. These properties were recorded at fair value in accordance with ASC 820 Fair Value Measurement. Pursuant to SEC guidance, the Company determined the fair value of the properties acquired clearly exceeded the related full cost ceiling limitation beyond a reasonable doubt and received a waiver from the SEC to exclude the properties acquired from the ceiling test calculation. This waiver was granted for the quarter ended March 31, 2021. As part of the waiver received from the SEC, the Company is required to disclose what the full cost ceiling test impairment amounts would have been for all periods presented in each applicable quarterly and annual filing if the waiver had not been granted. The fair values of the properties acquired in the QEP Merger and the Guidon Acquisition were based on forward strip oil and natural gas pricing existing at the closing date of the respective QEP Merger and Guidon Acquisition, and management affirmed there has not been a decline to the fair value of these acquired assets. The properties acquired in the QEP Merger and Guidon Acquisition have total unamortized costs at March 31, 2021 of $3.0 billion and $1.1 billion, respectively. Had the Company not received the waiver from the SEC, the impairment charge recorded would have been approximately $1.1 billion for the three months ended March 31, 2021.

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 future 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. 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.

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Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

7.    ASSET RETIREMENT OBLIGATIONS

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

			Three Months Ended March 31,
			2021						2020
			(In millions)
Asset retirement obligations, beginning of period			$	109					$	94
Additional liabilities incurred			2						4
Liabilities acquired			63						—
Liabilities settled and divested			(1)						—
Accretion expense			2						2
Revisions in estimated liabilities			20						—
Asset retirement obligations, end of period			195						100
Less current portion(1)			5						1
Asset retirement obligations - long-term			$	190					$	99

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

8.    EQUITY METHOD INVESTMENTS

The following table presents the carrying values of Rattler’s equity method investments as of the dates indicated:

			Ownership Interest						March 31, 2021						December 31, 2020
									(In millions)
EPIC Crude Holdings, LP			10		%				$	116					$	121
Gray Oak Pipeline, LLC			10		%				127						130
Wink to Webster Pipeline LLC(1)			4		%				86						83
OMOG JV LLC			60		%				191						194
Amarillo Rattler, LLC(2)			50		%				5						5
Total									$	525					$	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 fourth quarter of 2021.

(2)On April 30, 2021, Rattler sold its interest in the Amarillo Rattler, LLC (“Amarillo Rattler”) joint venture. See Note 16—Subsequent Events for further discussion.

Income (loss) from Rattler’s equity method investees was not material for the three months ended March 31, 2021 or 2020.

Rattler reviews its investments to determine if a loss in value which is other than temporary has occurred. If such a loss has occurred, Rattler recognizes an impairment provision. During the three months ended March 31, 2021, Rattler’s loss from equity method investments includes an immaterial proportional charge representing impairment recorded by the investee associated with abandoned projects. No other impairments were recorded for Rattler’s equity method investments for the three months ended March 31, 2021 or 2020. Rattler’s investees all serve customers in the oil and natural gas industry, which has been experiencing economic challenges as described above. It is possible that prolonged industry challenges could result in circumstances requiring impairment testing, which could result in potentially material impairment charges in future interim periods.

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Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

9.    DEBT

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

			March 31,						December 31,
			2021						2020
			(In millions)
4.625% Notes due 2021			$	191					$	191
5.375% Senior Notes due 2022(1)			25						—
7.320% Medium-term Notes, Series A, due 2022			20						20
0.900% Senior Notes due 2023			650						—
5.250% Senior Notes due 2023(1)			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			432						800
3.250% Senior Notes due 2026			800						800
5.625% Senior Notes due 2026(1)			18						—
7.125% Medium-term Notes, Series B, due 2028			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(2)			75						79
Unamortized debt issuance costs			(42)						(29)
Unamortized discount costs			(31)						(27)
Unamortized premium costs			15						15
Revolving credit facility(3)			52						23
Viper revolving credit facility(3)			57						84
Viper 5.375% Senior Notes due 2027			480						480
Rattler revolving credit facility(4)			54						79
Rattler 5.625% Senior Notes due 2025			500						500
Total debt, net			7,656						5,815
Less: current maturities of long-term debt			(191)						(191)
Total long-term debt			$	7,465					$	5,624

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

(2) 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 March 31, 2021, the amount due to CEMOF related to this alliance was $75 million.

(3) Each of these revolving credit facilities matures on November 1, 2022.

(4) The Rattler revolving credit facility matures on May 28, 2024.

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Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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

Second Amended and Restated Credit Facility

As of March 31, 2021, O&G, as borrower, and Diamondback Energy, Inc., as parent guarantor, have a credit agreement, as amended, which provides for a maximum credit amount available of $2 billion, with $52 million of outstanding borrowings and $1.9 billion available for future borrowings. As of March 31, 2021, there was 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 the credit facility was 1.65% and 3.02% for the three months ended March 31, 2021 and 2020, respectively. The borrowing base is scheduled to be redetermined semi-annually in May and November.

As of March 31, 2021, the Company was in compliance with all financial maintenance covenants under the revolving credit facility.

March 2021 Notes Offering

On March 24, 2021, the Company 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 on March 24 and September 24, beginning on September 24, 2021.

The March 2021 Notes are the Company’s senior unsecured obligations and are fully and unconditionally guaranteed by O&G. The March 2021 Notes are senior in right of payment to any of the Company’s and O&G’s future subordinated indebtedness and rank equal in right of payment with all of the Company’s and O&G’s existing and future senior indebtedness. The March 2021 Notes are effectively subordinated to the Company’s and O&G’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 O&G.

The Company may not redeem the 2023 Notes in whole or in part at any time prior to September 24, 2021. 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 related indenture. If the March 2021 Notes are redeemed on or after the dates noted above, in each case, the March 2021 Notes may be redeemed at a redemption price equal to 100% of the principal amount of the March 2021 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 relevant indentures, holders may require the Company to purchase some or all of their March 2021 Notes for cash at a price equal to 101% of the principal amount of the March 2021 Notes being purchased, plus accrued and unpaid interest, if any, to the date of purchase.

QEP Notes and Repurchases of Notes

On March 17, 2021, at the time of the QEP Merger discussed in Note 4—Acquisitions, 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, which resulted in a loss on extinguishment of debt during the three months ended March 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 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.

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Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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, which resulted in a loss on extinguishment of debt during the three months ended March 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 QEP 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.

Viper’s Credit Agreement

Viper LLC’s credit agreement, as amended (the “Viper credit agreement”), provides for a revolving credit facility in the maximum credit amount of $2 billion and a borrowing base of $580 million based on Viper LLC’s oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be redetermined semi-annually in May and November. As of March 31, 2021, Viper LLC had $57 million of outstanding borrowings and $523 million available for future borrowings under the Viper credit agreement. The weighted average interest rate on borrowings under the Viper credit agreement was 1.88% and 3.32% for the three months ended March 31, 2021 and 2020, respectively. The Viper credit agreement will mature on November 1, 2022.

As of March 31, 2021, Viper LLC was in compliance with all financial maintenance covenants under the Viper credit agreement.

Rattler’s Credit Agreement

Rattler LLC’s credit agreement, as amended (the “Rattler credit agreement”), provides for a revolving credit facility in the maximum credit amount of $600 million, which is expandable to $1 billion upon Rattler’s election, subject to obtaining additional lender commitments and satisfaction of customary conditions. As of March 31, 2021, Rattler LLC had $54 million of outstanding borrowings and $546 million available for future borrowings under the Rattler credit agreement. The weighted average interest rate on borrowings under Rattler credit agreement was 1.40% and 2.79% for the three months ended March 31, 2021 and 2020, respectively. The revolving credit facility will mature on May 28, 2024.

As of March 31, 2021, Rattler LLC was in compliance with all financial maintenance covenants under the Rattler credit agreement.

10.    CAPITAL STOCK AND EARNINGS PER SHARE

Diamondback did not complete any equity offerings during the three months ended March 31, 2021 and March 31, 2020. As discussed in Note 4—Acquisitions, Diamondback issued 12.12 million shares of the Company’s stock as consideration in the QEP Merger and 10.68 million shares of the Company’s stock as consideration for the Guidon Acquisition during the three months ended March 31, 2021.

Earnings (Loss) Per Share

The Company’s basic earnings per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted earnings per share include the effect of potentially dilutive shares outstanding for the period. Additionally, 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.

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Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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

			Three Months Ended March 31,
			2021						2020
			($ in millions, except per share amounts, shares in thousands)
Net income (loss) attributable to common stock			$	220					$	(272)
Weighted average common shares outstanding:
Basic weighted average common units outstanding			164,169						158,291
Effect of dilutive securities:
Potential common shares issuable			757						203
Diluted weighted average common shares outstanding			164,926						158,494
Basic net income (loss) attributable to common stock			$	1.34					$	(1.72)
Diluted net income (loss) attributable to common stock			$	1.33					$	(1.72)

Change in Ownership of Consolidated Subsidiaries

Non-controlling interests in the accompanying condensed 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. The following table summarizes changes in the ownership interest in consolidated subsidiaries during the periods presented:

			Three Months Ended March 31,
			2021						2020
			(In millions)
Net income (loss) attributable to the Company			$	220					$	(272)
Change in ownership of consolidated subsidiaries			(4)						—
Change from net income (loss) attributable to the Company's stockholders and transfers to non-controlling interest			$	216					$	(272)

11.    EQUITY-BASED COMPENSATION

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 March 31, 2021, the Company had outstanding restricted stock units, performance-based restricted stock units, an immaterial amount of restricted share awards and restricted stock units which were assumed in connection with the QEP Merger and an immaterial amount of stock options and stock appreciation rights assumed from Energen. The Company classifies these as equity-based awards and estimates the fair values of restricted stock awards and units as the closing price of the Company’s common stock on the grant date of the award, which is expensed over the applicable vesting period. The Company values its stock options using a Black-Scholes option valuation model.

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

			Three Months Ended March 31,
			2021						2020
			(In millions)
General and administrative expenses			$	10					$	9
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties			$	4					$	6

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Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Restricted Stock Units

The following table presents the Company’s restricted stock units activity during the three months ended March 31, 2021 under the Equity Plan and the QEP equity incentive plan assumed by the Company in the QEP Merger:

			Restricted Stock  Units						Weighted Average Grant-Date Fair Value
Unvested at December 31, 2020			1,113,480						$	48.58
Granted(1)			638,589						$	79.89
Vested			(293,422)						$	79.76
Forfeited			(19,061)						$	45.33
Unvested at March 31, 2021			1,439,586						$	55.42

(1)    Includes 164,088 replacement restricted stock unit awards granted in connection with the QEP Merger, the majority of which vested upon closing of the QEP Merger. For additional information regarding the QEP Merger, see Note 4—Acquisitions.

The aggregate fair value of restricted stock units that vested during the three months ended March 31, 2021 and 2020 was $23 million and $8 million, respectively. As of March 31, 2021, the Company’s unrecognized compensation cost related to unvested restricted stock units was $71 million, which is expected to be recognized over a weighted-average period of 2.5 years.

Performance Based Restricted Stock Units

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% 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 performance period of January 1, 2019 to December 31, 2021 and cliff vest at December 31, 2021 subject to continued employment. In March 2019, eligible employees received performance restricted stock unit awards totaling 32,958 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2019 to December 31, 2021 and vest in five equal installments beginning on March 1, 2025.

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% 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, 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.

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Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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 periods 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 units activity under the Equity Plan for the three months ended March 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
Unvested at March 31, 2021(1)			610,041						$	109.49

(1)A maximum of 1,431,833 units could be awarded based upon the Company’s final TSR ranking.

As of March 31, 2021, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $43 million, which is expected to be recognized over a weighted-average period of 2.2 years.

Rattler Long-Term Incentive Plan

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

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

The following table presents the phantom unit activity under the Rattler LTIP for the three months ended March 31, 2021:

			Phantom Units						Weighted Average Grant-Date Fair Value
Unvested at December 31, 2020			2,089,668						$	17.07
Granted			210,631						$	11.01
Vested			(4,755)						$	12.59
Forfeited			(13,385)						$	5.79
Unvested at March 31, 2021			2,282,159						$	16.59

The aggregate fair value of phantom units that vested during the three months ended March 31, 2021 was immaterial. As of March 31, 2021, the unrecognized compensation cost related to unvested phantom units was $30 million, which is expected to be recognized over a weighted-average period of three years.

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Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

12.    INCOME TAXES

The Company’s effective income tax rates were 22.6% and (26.1)% for the three months ended March 31, 2021 and 2020, respectively. Total income tax expense from continuing operations for the three months ended March 31, 2021 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income primarily due to (i) state income taxes, net of federal benefit, and (ii) the impact of permanent differences between book and taxable income, partially offset by (iii) tax benefit resulting from a reduction in the valuation allowance on Viper’s deferred tax assets due to pre-tax income for the period.

For the three months ended March 31, 2021, the Company’s items of discrete income tax expense or benefit were not material.

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. The Company recorded an opening balance sheet net deferred tax asset of $15 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 Internal Revenue Code 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 on the portion of QEP’s federal tax attributes estimated not more likely than not to be realized prior to expiration. In addition, acquired tax attributes include state net operating loss carryforwards for which a valuation allowance 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.

Total income tax expense from continuing operations for the three months ended March 31, 2020 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax loss primarily due to (i) the impact of recording a valuation allowance on Viper’s deferred tax assets, (ii) state income taxes and (iii) the impact of permanent differences between book and taxable income, partially offset by tax benefit resulting from the anticipated carryback of federal net operating losses. For the three months ended March 31, 2020, the Company recorded a discrete income tax expense of $143 million related to application of a valuation allowance on Viper’s beginning-of-year deferred tax assets, which consisted primarily of its investment in Viper LLC and federal net operating loss carryforwards. A valuation allowance was also applied against the year-to-date tax benefit resulting from Viper’s pre-tax loss for 2020. 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. In light of the criteria established by applicable GAAP for recognizing the tax benefit of deferred tax assets, management’s assessment resulted in recording a valuation allowance against Viper’s deferred tax assets as of March 31, 2020. In addition, for the three months ended March 31, 2020, the Company recorded a discrete income tax benefit of $25 million related to the available carryback of certain federal net operating losses to tax year(s) in which the corporate income tax rate was 35%. Prior to the enactment of the Coronavirus Aid, Relief, and Economic Security Act (“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 benefit associated with federal net operating loss carryforwards at the statutory 21% corporate income tax rate.

The Company considered the impact of the American Rescue Plan, 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. The Company also considered the impact of the CARES Act, enacted March 27, 2020, in the period of enactment, resulting in discrete income tax benefit for the three months ended March 31, 2020 related to the carryback of approximately $179 million of the Company’s federal net operating losses as noted above. 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’s current and long-term income taxes receivable of approximately $33 million and $32 million, respectively, primarily relate to anticipated refunds of minimum tax credits resulting from available carryback of certain federal net operating losses acquired from QEP.

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Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

13.    DERIVATIVES

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

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.

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

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Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

As of March 31, 2021, the Company had the following outstanding 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
Apr. - June			2021			Swap			43,341			WTI			$—			$44.60						$—			$—
July - Sep.			2021			Swap			38,348			WTI			$—			$42.82						$—			$—
Oct. - Dec.			2021			Swap			30,674			WTI			$—			$42.36						$—			$—
Apr. - Dec.			2021			Swap			5,000			Argus WTI Houston			$—			$37.78						$—			$—
Apr. - Dec.			2021			Swap			5,000			Brent			$—			$41.62						$—			$—
Apr. - June			2021			Basis Swap(1)			39,000			Argus WTI Midland			$0.83			$—						$—			$—
July - Dec.			2021			Basis Swap(1)			34,000			Argus WTI Midland			$0.91			$—						$—			$—
July - Dec.			2021			Swaption			5,000			Brent			$—			$51.00						$—			$—
Apr. - June			2021			Roll Swap(2)(3)			46,000			WTI			$0.16			$—						$—			$—
July - Dec.			2021			Roll Swap(2)(3)			34,000			WTI			$0.24			$—						$—			$—
Apr. - June			2021			Costless Collar			20,670			WTI			$—			$—						$35.78			$47.08
July - Sep.			2021			Costless Collar			17,685			WTI			$—			$—						$35.27			$46.50
Oct. - Dec.			2021			Costless Collar			26,663			WTI			$—			$—						$38.69			$53.80
July - Dec.			2021			Costless Collar			5,000			Argus WTI Houston			$—			$—						$45.00			$68.33
Apr. - June			2021			Costless Collar			82,000			Brent			$—			$—						$39.40			$48.84
July - Sep.			2021			Costless Collar			62,000			Brent			$—			$—						$39.61			$48.42
Oct. - Dec.			2021			Costless Collar			64,000			Brent			$—			$—						$39.78			$48.90
Jan. - June			2022			Swap			1,000			WTI			$—			$45.00						$—			$—
Jan. - Dec.			2022			Basis Swap(1)			10,000			Argus WTI Midland			$0.84			$—						$—			$—
Jan. - Mar.			2022			Costless Collar			2,000			Argus WTI Houston			$—			$—						$45.00			$67.50
Jan. - Mar.			2022			Costless Collar			12,000			WTI			$—			$—						$45.00			$68.00
Apr. - June			2022			Costless Collar			6,000			WTI			$—			$—						$45.00			$68.75
Jan. - Mar.			2022			Costless Collar			34,000			Brent			$—			$—						$45.00			$67.54
Apr. - June			2022			Costless Collar			9,000			Brent			$—			$—						$45.00			$75.07
NATURAL GAS
Apr. - Dec.			2021			Swap			245,000			Henry Hub			$—			$2.65						$—			$—
Apr. - Dec.			2021			Swap			50,000			Waha Hub			$—			$1.92						$—			$—
Apr. - Dec.			2021			Basis Swap(1)			250,000			Waha Hub			$(0.66)			$—						$—			$—
Jan. - Dec.			2022			Basis Swap(1)			190,000			Waha Hub			$(0.36)			$—						$—			$—
NATURAL GAS LIQUIDS
Apr. - Dec.			2021			Swap			2,000			Mont Belvieu Propane			$—			$29.40						$—			$—

(1) 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 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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Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

(2) The Company has rolling hedge basis swaps for the differential between the NYMEX prices between the calendar month average and the physical crude oil delivery month. The weighted average differential represents the amount of reduction to Cushing, Oklahoma oil price for the notional volumes covered by the rolling hedge basis swap contracts.

(3) Includes a rolling hedge basis swap contract for the differential between the NYMEX prices for WTI Cushing and WTI CMA calendar month average of each basis for a notional quantity of 4,000 barrels per day with a weighted average differential of $0.00.

Settlement Month

Settlement Year

Type of Contract

Bbls/Mcf Per Day

Index

Put Price

OIL

Jan. - Dec.

2022

Short Put

5,000

Brent

$35.00

Interest Rate Swaps

The Company has used interest rate swaps to reduce its exposure to variable rate interest payments associated with the Company’s revolving credit facility. The 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 interest rate swaps which resulted in cash received upon settlement of $80 million, net of fees. The interest 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 condensed consolidated statements of cash flow for the three months ended March 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 14—Fair Value Measurements for further details.

Gains and Losses on Derivative Instruments

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

			Three Months Ended March 31,
			2021						2020
			(In millions)
Gain (loss) on derivative instruments, net
Commodity contracts			$	(294)					$	604
Interest rate swaps			130						(62)
Total			$	(164)					$	542
Net cash received (paid) on settlements
Commodity contracts			$	(182)					$	87
Interest rate swaps(1)			80						—
Total			$	(102)					$	87

(1)The three months ended March 31, 2021 include cash received on contracts terminated prior to their contractual maturity of $80 million.

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Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

14.    FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments. The fair values of the Company’s 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. These valuations are Level 2 inputs.

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Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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 condensed consolidated balance sheets as of March 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 March 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			$	—		$	33		$	—		$	33		$	(33)		$	—
Non-current:
Derivative Instruments			$	—		$	8		$	—		$	8		$	(4)		$	4
Liabilities:
Current:
Derivative Instruments			$	—		$	637		$	—		$	637		$	(33)		$	604
Non-current:
Derivative Instruments			$	—		$	12		$	—		$	12		$	(4)		$	8

			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

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Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

			March 31, 2021												December 31, 2020
			Carrying												Carrying
			Value(1)						Fair Value						Value(1)						Fair Value
			(In millions)
Debt:
Revolving credit facility			$	52					$	52					$	23					$	23
4.625% Notes due 2021			$	191					$	192					$	191					$	193
5.375% Senior Notes due 2022(2)			$	26					$	26					$	—					$	—
7.320% Medium-term Notes, Series A, due 2022			$	21					$	21					$	21					$	22
0.900% Senior Notes due 2023			$	647					$	651					$	—					$	—
5.250% Senior Notes due 2023(2)			$	11					$	11					$	—					$	—
2.875% Senior Notes due 2024			$	993					$	1,058					$	993					$	1,053
4.750% Senior Notes due 2025			$	497					$	558					$	496					$	565
5.375% Senior Notes due 2025			$	432					$	447					$	799					$	824
3.250% Senior Notes due 2026			$	793					$	841					$	793					$	857
5.625% Senior Notes due 2026(2)			$	20					$	21					$	—					$	—
7.125% Medium-term Notes, Series B, due 2028			$	107					$	120					$	107					$	119
3.500% Senior Notes due 2029			$	1,188					$	1,249					$	1,187					$	1,286
3.125% Senior Notes due 2031			$	889					$	901					$	—					$	—
4.400% Senior Notes due 2051			$	640					$	666					$	—					$	—
Viper revolving credit facility			$	57					$	57					$	84					$	84
Viper's 5.375% Senior Notes due 2027			$	472					$	501					$	472					$	501
Rattler revolving credit facility			$	54					$	54					$	79					$	79
Rattler’s 5.625% Senior Notes due 2025			$	491					$	522					$	491					$	528
DrillCo Agreement			$	75					$	75					$	79					$	79

(1)The carrying value includes associated deferred loan costs and any remaining discount or premium, if any.

(2)These notes were issued by QEP prior to the QEP Merger and remained outstanding as of March 31, 2021 following the QEP Merger and the Company’s subsequent repurchase of a portion of these notes in its tender offers for these notes.

The fair values of the Company’s revolving credit facility, 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 March 31, 2021 quoted market price, a Level 1 classification in the fair value hierarchy.

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

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

15.    COMMITMENTS AND CONTINGENCIES

The Company is a party to various routine legal proceedings, disputes and claims arising in the course of its business, including those that arise from interpretation of federal and state laws and regulations affecting the crude oil and natural gas industry. 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.

During the three months ended March 31, 2021, the Company acquired certain contractual obligations in conjunction with the QEP Merger including an aggregate of approximately $68 million in various transportation, gathering and purchase commitments.

16.    SUBSEQUENT EVENTS

First Quarter 2021 Dividend Declaration

On April 29, 2021, the Board of Directors of the Company declared a cash dividend for the first quarter of 2021 of $0.40 per share of common stock, payable on May 20, 2021 to its stockholders of record at the close of business on May 13, 2021.

Commodity Contracts

Subsequent to March 31, 2021, the Company entered into new costless collars and basis swaps. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges noted in the table below. When aggregating multiple contracts, the weighted average contract price is disclosed. The following table presents the derivative contracts entered into by the Company between April 1, 2021 and April 30, 2021.

															Swaps						Collars
Settlement Month			Settlement Year			Type of Contract			Bbls/MMBtu Per Day			Index			Weighted Average Differential									Weighted Average Floor Price			Weighted Average Ceiling Price
OIL
Jan. - June			2022			Costless Collar			14,000			Argus WTI Houston			$—									$45.00			$69.98
Jan. - June			2022			Costless Collar			10,000			Brent			$—									$45.00			$74.82
NATURAL GAS
Jan. - Dec.			2022			Basis Swap			20,000			Waha Hub			$(0.23)									$—			$—

Divestitures

On May 3, 2021, the Company signed a definitive agreement to divest all of its Williston Basin assets acquired in the QEP Merger, consisting of approximately 95,000 net acres, for a purchase price of approximately $745 million, subject to certain closing adjustments. These assets have estimated full year 2021 net production of approximately 15 MBO/d (25  MBOE/d). This transaction is expected to close in the third quarter of 2021, subject to continued due diligence and closing conditions. The Company intends to use its net proceeds from this transaction toward debt reduction.

On April 28, 2021 and April 29, 2021, the Company signed definitive agreements to divest certain non-core Permian assets including 7,000 net acres of non-core Southern Midland Basin acreage in Upton county and approximately 1,300 net acres of non-core, non-operated Delaware Basin assets in Lea county, New Mexico for a combined gross purchase price of $87 million, subject to certain closing adjustments. These assets have estimated full year 2021 net production of approximately 900 BO/d (2,650 BOE/d) from 140 producing wells. These transactions are expected to close in the second quarter of 2021,

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

subject to continued diligence and closing conditions. The Company intends to use its net proceeds from these transactions toward debt reduction.

On April 30, 2021, each of Rattler and its joint venture partner Amarillo Midstream, LLC sold its interest in Amarillo Rattler to EnLink Midstream Operating, LP for aggregate total gross potential consideration of $75 million, consisting of $50 million at closing, $10 million upon the first anniversary of closing and up to $15 million in contingent earn-out payments over a three-year span based upon the Company’s development activity. Net of transaction expenses and working capital adjustments, Rattler received $24 million at closing, with an incremental $5 million due in April 2022 and could receive up to $7.5 million in contingent payments from 2023 to 2025.

17.    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 following tables summarize the results of the Company’s operating segments during the periods presented:

			Upstream						Midstream Operations						Eliminations						Total
Three Months Ended March 31, 2021:			(In millions)
Third-party revenues			$	1,172					$	12					$	—					$	1,184
Intersegment revenues			—						87						(87)						—
Total revenues			1,172						99						(87)						1,184
Depreciation, depletion, amortization and accretion			262						11						—						273
Impairment of midstream assets			—						3						—						3
Income (loss) from operations			552						38						(19)						571
Interest expense, net			(49)						(7)						—						(56)
Other income (expense)			(222)						(3)						(2)						(227)
Provision for (benefit from) income taxes			63						2						—						65
Net income (loss) attributable to non-controlling interest			(3)						6						—						3
Net income (loss) attributable to Diamondback Energy, Inc.			221						20						(21)						220
As of March 31, 2021:
Total assets			$	20,566					$	1,769					$	(339)					$	21,996

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

			Upstream						Midstream Operations						Eliminations						Total
Three Months Ended March 31, 2020:			(In millions)
Third-party revenues			$	883					$	16					$	—					$	899
Intersegment revenues			—						113						(113)						—
Total revenues			883						129						(113)						899
Depreciation, depletion, amortization and accretion			396						13						—						409
Impairment of oil and natural gas properties			1,009						—						—						1,009
Income (loss) from operations			(782)						61						(81)						(802)
Interest expense, net			(45)						(3)						—						(48)
Other income (expense)			534						—						(1)						533
Provision for (benefit from) income taxes			79						4						—						83
Net income (loss) attributable to non-controlling interest			(128)						41						(41)						(128)
Net income (loss) attributable to Diamondback Energy, Inc.			(244)						13						(41)						(272)
As of December 31, 2020:
Total assets			$	16,128					$	1,809					$	(318)					$	17,619

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

The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and notes thereto presented in this report as well as our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2020. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See “Part II. Item 1A. Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Overview

We operate 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) through our subsidiary, Rattler, the midstream operations segment, which is focused on ownership, operation, development and acquisition of midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin.

Recent Developments

First Quarter 2021 Acquisitions

On February 26, 2021, we completed the Guidon Acquisition, which included 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.

On March 17, 2021, we completed the acquisition of QEP pursuant to the Agreement and Plan of Merger, dated as of December 20, 2020 (the “Merger Agreement”), by and among Diamondback, Bohemia Merger Sub, Inc., a Delaware corporation and QEP. Pursuant to the Merger Agreement, at the effective time of the QEP Merger, Bohemia Merger Sub, Inc. merged with and into QEP, with QEP continuing as the surviving corporation and as a wholly owned subsidiary of Diamondback. The addition of QEP’s assets increased our net acreage in the Midland Basin by approximately 49,000 net acres. Under the terms of the Merger Agreement, we issued approximately 12.12 million shares of our common stock (valued at a price of $81.41 per share on the closing date) to the former QEP stockholders, with the total value of approximately $987 million.

See Note 4—Acquisitions for additional discussion of the Guidon Acquisition and the QEP Merger.

Recent and Pending Divestitures

On May 3, 2021, we signed a definitive agreement to divest all of our Williston Basin assets acquired in the QEP Merger, consisting of approximately 95,000 net acres, for a purchase price of approximately $745 million, subject to certain closing adjustments. This transaction is expected to close in the third quarter of 2021, subject to continued due diligence and closing conditions. We intend to use our net proceeds from this transaction toward debt reduction.

On April 28, 2021 and April 29, 2021, we signed definitive agreements to divest certain non-core Permian assets, including 7,000 net acres of non-core Southern Midland Basin acreage in Upton county and approximately 1,300 net acres of non-core, non-operated Delaware Basin assets in Lea county, New Mexico, for a combined gross purchase price of $87 million, subject to certain closing adjustments. These transactions are expected to close in the second quarter of 2021, subject to continued due diligence and closing conditions. We intend to use our net proceeds from these transactions toward debt reduction.

On April 30, 2021, each of Rattler and its joint venture partner Amarillo Midstream, LLC sold its interest in Amarillo Rattler to EnLink Midstream Operating, LP for aggregate total gross potential consideration of $75 million, consisting of $50 million at closing, $10 million upon the first anniversary of closing and up to $15 million in contingent earn-out payments over a three-year span based upon the Company’s development activity. Net of transaction expenses and working capital adjustments, Rattler received $24 million at closing, with an incremental $5 million due in April 2022 and could receive up to $7.5 million in contingent payments from 2023 to 2025.

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First Quarter 2021 Debt Transactions

On March 24, 2021, we completed a notes offering of our March 2021 Notes resulting in aggregate net proceeds of $2.18 billion. The net proceeds were primarily used to fund the repurchase of $1.65 billion in fair value carrying amount of the QEP Notes that remained outstanding at the effective time of the QEP Merger for total cash consideration of $1.7 billion, and $368 million principal amount of 2025 Senior Notes, for total cash consideration of $381 million. These refinancing transactions are expected to result in an estimated annual interest cost savings of approximately $40 million in addition to an estimated $60 to $80 million of previously announced expected annual cost synergies from the QEP Merger.

See Note 9—Debt for additional discussion of our 2021 debt transactions.

COVID-19 and Commodity Prices

In early March 2020, oil prices dropped sharply and continued to decline, briefly reaching negative levels as a result of multiple factors affecting the supply and demand in global oil and natural gas markets, including (i) actions taken by OPEC members and other exporting nations impacting commodity price and production levels and (ii) a significant decrease in demand due to the ongoing COVID-19 pandemic. However, certain restrictions on conducting business that were implemented in response to the COVID-19 pandemic have been lifted as improved treatments and vaccinations for COVID-19 have been rolled-out globally since late 2020. As a result, oil and natural gas market prices have improved in response to the increase in demand.

During 2020 and 2021, the posted NYMEX WTI price for crude oil ranged from $(37.63) to $66.09 per Bbl, and the NYMEX Henry Hub price of natural gas ranged from $1.48 to $3.35 per MMBtu. On April 12, 2021, the NYMEX WTI price for crude oil was $59.70 per Bbl and the NYMEX Henry Hub price of natural gas was $2.56 per MMBtu. Commodity prices have historically been volatile and we cannot predict events which may lead to future fluctuations in these prices.

As a result of the reduction in crude oil demand caused by factors discussed above, in 2020, we lowered our 2020 capital budgets and production guidance, however, we have restored curtailed production. Our results of operations may be further adversely impacted by any government rule, regulation or order that may impose production limits, as well as pipeline capacity and storage constraints, in the Permian Basin where we operate.

First Quarter 2021 Operating Highlights

•We recorded net income of $220 million for the first quarter ended March 31, 2021.

•Our average production was 307.4 MBOE/d during the first quarter of 2021 which includes the effect of approximately four to five days of lost total net production during February 2021 resulting from the recent winter storms in the Permian Basin. The Company expects to make up these production losses throughout the remainder of 2021.

•During the first quarter of 2021, we drilled 41 gross horizontal wells in the Midland Basin and eight gross horizontal wells in the Delaware Basin.

•We turned 67 gross operated horizontal wells (42 in the Midland Basin and 25 in the Delaware Basin) to production and had capital expenditures, excluding acquisitions, of $296 million during the first quarter of 2021.

•The average lateral length for the wells completed during the first quarter of 2021 was 10,331 feet.

•As of March 31, 2021, we had $1.9 billion of availability for future borrowings under our revolving credit facility and approximately $121 million of cash on hand.

•Our cash operating costs for the first quarter ended March 31, 2021 were $8.06 per BOE, including lease operating expenses of $3.69 per BOE, cash general and administrative expenses of $0.54 per BOE and production and ad valorem taxes and gathering and transportation expenses of $3.83 per BOE.

•On April 29, 2021, our board of directors declared a cash dividend for the first quarter of 2021 of $0.40 per share of common stock, payable on May 20, 2021 to our stockholders of record at the close of business of May 13, 2021.

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Upstream Segment

In our upstream segment, our activities are primarily directed at the horizontal development of the Wolfcamp and Spraberry formations in the Midland Basin and the Wolfcamp and Bone Spring formations in the Delaware Basin. We intend to continue to develop our reserves and increase production through development drilling and exploitation and exploration activities on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves. Also, in our upstream segment, our publicly-traded subsidiary, Viper, is focused on owning and acquiring mineral interests and royalty interests in oil and natural gas properties primarily in the Permian Basin and derives royalty income and lease bonus income from such interests.

As of March 31, 2021, we had approximately 554,594 net acres, which primarily consisted of approximately 275,113 net acres in the Midland Basin, 151,245 net acres in the Delaware Basin and 94,610 net acres in the Williston Basin. As discussed above, we recently entered into definitive agreements to divest (i) all of our Williston Basin net acres, (ii) 7,000 net acres of non-core Southern Midland Basin acreage in Upton county and (iii) approximately 1,300 net acres of non-core, non-operated Delaware Basin assets in Lea county, New Mexico for an aggregate purchase price of $832 million, subject to certain closing adjustments. These transactions are expected to close in the second and third quarters of 2021, subject to continued due diligence and closing conditions.

As of December 31, 2020, we had an estimated 10,413 gross horizontal locations that we believe to be economic at $60 per barrel WTI.

The following table sets forth the total number of operated horizontal wells drilled and completed during the three months ended March 31, 2021:

			Three Months Ended March 31, 2021
			Drilled												Completed(1)
Area			Gross						Net						Gross						Net
Midland Basin			41						40						42						37
Delaware Basin			8						7						25						23
Total			49						47						67						60

(1)The average lateral length for the wells completed during the first quarter of 2021 was 10,331 feet. Operated completions during the first quarter of 2021 consisted of 27 Wolfcamp A wells, eight Wolfcamp B wells, ten Lower Spraberry wells, seven Middle Spraberry wells, six Second Bone Springs wells, four Jo Mill wells, three Third Bone Springs wells, one Dean well and one Barnett well.

As of March 31, 2021, we operated the following wells:

			As of March 31, 2021
			Vertical Wells												Horizontal Wells												Total
Area			Gross						Net						Gross						Net						Gross						Net
Midland Basin			2,322						2,157						1,685						1,556						4,007						3,713
Delaware Basin			26						23						616						576						642						599
Other			—						—						397						345						397						345
Total			2,348						2,180						2,698						2,477						5,046						4,657

As of March 31, 2021, we held interests in 10,763 gross (4,815 net) wells, including wells that we do not operate. During the first quarter of 2021, we acquired interests in 1,671 gross (1,240 net) wells as part of the QEP Merger.

Our development program is focused entirely within the Permian Basin, where we continue to focus on long-lateral multi-well pad development. Our horizontal development consists of multiple targeted intervals, primarily within the Wolfcamp and Spraberry formations in the Midland Basin and the Wolfcamp and Bone Springs formations in the Delaware Basin.

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Midstream Operations

In our midstream operations segment, Rattler’s crude oil infrastructure assets consist of gathering pipelines and metering facilities, which collectively gather crude oil for its customers. Rattler’s facilities gather crude oil from horizontal and vertical wells in our ReWard, Spanish Trail, Pecos and Glasscock areas within the Permian Basin. Rattler’s natural gas gathering and compression system consists of gathering pipelines, compression and metering facilities, which collectively service the production from our Pecos area assets within the Permian Basin. Rattler’s water sourcing and distribution assets consists of water wells, hydraulic fracturing pits, pipelines and water treatment facilities, which collectively gather and distribute water from Permian Basin aquifers to the drilling and completion sites through buried pipelines and temporary surface pipelines. Rattler’s gathering and disposal system spans approximately 524 miles and consists of gathering pipelines along with produced water disposal wells and facilities which collectively gather and dispose of produced water from operations throughout our Permian Basin acreage.

We have entered into multiple fee-based commercial agreements with Rattler, each with an initial term ending in 2034, utilizing Rattler’s infrastructure assets or its planned infrastructure assets to provide an array of essential services critical to our upstream operations in the Delaware and Midland Basins. Our agreements with Rattler include substantial acreage dedications.

Results of Operations

The following table sets forth selected operating data for the three months ended March 31, 2021 and 2020:

			Three Months Ended March 31,
			2021						2020
Revenues (In millions):
Oil sales			$	944					$	827
Natural gas sales			104						4
Natural gas liquid sales			124						52
Total oil, natural gas and natural gas liquid revenues			$	1,172					$	883
Production Data:
Oil (MBbls)			16,578						18,325
Natural gas (MMcf)			34,109						32,120
Natural gas liquids (MBbls)			5,405						5,538
Combined volumes (MBOE)(1)			27,668						29,216
Daily oil volumes (BO/d)(2)			184,200						201,369
Daily combined volumes (BOE/d)(2)			307,422						321,057
Average Prices:
Oil ($ per Bbl)			$	56.94					$	45.10
Natural gas ($ per Mcf)			$	3.05					$	0.14
Natural gas liquids ($ per Bbl)			$	22.94					$	9.45
Combined ($ per BOE)			$	42.36					$	30.23
Oil, hedged ($ per Bbl)(3)			$	46.81					$	49.32
Natural gas, hedged ($ per MMBtu)(3)			$	2.64					$	0.42
Natural gas liquids, hedged ($ per Bbl)(3)			$	22.76					$	9.45
Average price, hedged ($ per BOE)(3)			$	35.75					$	33.19

(1)Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl.

(2)The volumes presented are based on actual results and are not calculated using the rounded numbers in the table above.

(3)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices and include gains and losses on cash settlements for matured commodity derivatives, which we do not designate for hedge accounting. Hedged prices exclude gains or losses resulting from the early settlement of commodity derivative contracts.

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Production Data

Substantially all of our revenues are generated through the sale of oil, natural gas and natural gas liquids production. The following tables set forth our production data for the three months ended March 31, 2021 and 2020:

			Three Months Ended March 31,
			2021						2020
Oil (MBbls)			60		%				63		%
Natural gas (MMcf)			21		%				18		%
Natural gas liquids (MBbls)			19		%				19		%
			100		%				100		%

			Three Months Ended March 31, 2021															Three Months Ended March 31, 2020
			Midland Basin			Delaware Basin			Other(1)			Total						Midland Basin			Delaware Basin			Other(2)			Total
Production Data:
Oil (MBbls)			9,840			6,436			302			16,578						10,511			7,760			54			18,325
Natural gas (MMcf)			18,457			15,055			597			34,109						15,833			16,147			140			32,120
Natural gas liquids (MBbls)			3,236			2,069			100			5,405						3,048			2,463			27			5,538
Total (MBoe)			16,152			11,014			502			27,668						16,198			12,914			104			29,216

(1)Includes the Eagle Ford Shale, Rockies and High Plains.

(2)Includes the Central Basin Platform, Eagle Ford Shale and Rockies.

Comparison of the Three Months Ended March 31, 2021 and 2020

Oil, Natural Gas and Natural Gas Liquids Revenues. Our revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average sales prices received for those volumes.

Our oil, natural gas and natural gas liquids revenues for the first quarter of 2021 increased by $289 million, or 33%, to $1,172 million from $883 million during the first quarter of 2020. The increase in average prices received during the three months ended March 31, 2021 as compared to the same period in 2020 contributed to $368 million of the total increase. The impact of higher pricing was partially offset by a 5.3% decrease in combined volumes sold primarily driven by the recent winter storms in the Permian Basin which caused the loss of approximately four to five days of total net production during February 2021. The production declines were slightly offset by additional production contributed during the first quarter of 2021 from the QEP Merger and Guidon Acquisition. The Company expects to make up weather related production losses throughout the remainder of 2021.

Average daily production sold decreased by 13,635 BOE/d to 307,422 BOE/d during the three months ended March 31, 2021 from 321,057 BOE/d during the three months ended March 31, 2020.

Lease Operating Expenses. The following table shows lease operating expenses for the three months ended March 31, 2021 and 2020:

			Three Months Ended March 31,
			2021												2020
			Amount						Per BOE						Amount						Per BOE
			(In millions, except per BOE amounts)
Lease operating expenses			$	102					$	3.69					$	127					$	4.35

Lease operating expenses for the three months ended March 31, 2021 as compared to the three months ended March 31, 2020 decreased by $25 million, or $0.66 per BOE. The decrease in lease operating expenses was primarily due to declining power generation costs which were partially offset by additional costs resulting from production associated with the acquisitions discussed in Note 4—Acquisitions.

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Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the three months ended March 31, 2021 and 2020:

			Three Months Ended March 31,
			2021												2020
			Amount						Per BOE						Amount						Per BOE
			(In millions, except per BOE amounts)
Production taxes			$	60					$	2.17					$	42					$	1.42
Ad valorem taxes			15						0.54						29						1.01
Total production and ad valorem expense			$	75					$	2.71					$	71					$	2.43
Production taxes as a % of oil, natural gas, and natural gas liquids revenue			5.1		%										4.8		%

In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes as a percentage of production revenues remained consistent for the three months ended March 31, 2021 compared to the same period in 2020.

Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. Ad valorem taxes for the three months ended March 31, 2021 as compared to the three months ended March 31, 2020 decreased by $14 million primarily due to lower overall valuations resulting from a decrease in commodity prices between valuation periods.

Gathering and Transportation Expense. The following table shows gathering and transportation expense for the three months ended March 31, 2021 and 2020:

			Three Months Ended March 31,
			2021												2020
			Amount						Per BOE						Amount						Per BOE
			(In millions, except per BOE amounts)
Gathering and transportation expense			$	31					$	1.12					$	36					$	1.23

For the three months ended March 31, 2021, the per BOE decrease for gathering and transportation expenses is primarily attributable to recording minimum volume commitment fees in 2020.

Depreciation, Depletion, Amortization and Accretion. The following table provides the components of our depreciation, depletion, amortization and accretion expense for the three months ended March 31, 2021 and 2020:

			Three Months Ended March 31,
			2021						2020
			(In millions, except BOE amounts)
Depletion of proved oil and natural gas properties			$	257					$	392
Depreciation of midstream assets			11						11
Depreciation of other property and equipment			3						4
Asset retirement obligation accretion			2						2
Depreciation, depletion and amortization expense			$	273					$	409
Oil and natural gas properties depletion rate per BOE			$	9.29					$	13.42

The decrease in depletion of proved oil and natural gas properties of $135 million for the three months ended March 31, 2021 as compared to the three months ended March 31, 2020 resulted largely from a reduction in the average depletion rate for our oil and natural gas properties in 2021, which stemmed from a decrease in the net book value of our properties due primarily to the full cost ceiling impairments recorded in 2020.

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Impairment of Oil and Natural Gas Properties. Pursuant to SEC guidance, we determined the fair value of the properties acquired in the QEP Merger and Guidon Acquisition clearly exceeded the related full cost ceiling limitation beyond a reasonable doubt and received a waiver from the SEC to exclude the acquired properties from the first quarter 2021 ceiling test calculation. As a result, no impairment expense was recorded for the three months ended March 31, 2021. The properties acquired in the QEP Merger and Guidon Acquisition had an unamortized cost at March 31, 2021 of $3.0 billion and $1.1 billion, respectively. Had we not received the waiver from the SEC, the impairment charge recorded would have been an additional $1.1 billion for the three months ended March 31, 2021.

As a result of the sharp decline in commodity prices during 2020, we recorded a non-cash ceiling test impairment for the three months ended March 31, 2020 of $1.0 billion, which is included in accumulated depletion, depreciation, amortization and impairment on our condensed consolidated balance sheet.

Impairment charges affect our results of operations but do not reduce our cash flow. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analysis in future periods. If the trailing 12-month commodity prices fall as compared to the commodity prices used in prior quarters, we may have material write-downs in subsequent quarters. See Note 6—Property and Equipment for further details regarding factors that impact the impairment of oil and natural gas properties.

General and Administrative Expenses. The following table shows general and administrative expenses for the three months ended March 31, 2021 and 2020:

			Three Months Ended March 31,
			2021												2020
			Amount						Per BOE						Amount						Per BOE
			(In millions, except per BOE amounts)
General and administrative expenses			$	15					$	0.54					$	15					$	0.51
Non-cash stock-based compensation			10						0.36						9						0.31
Total general and administrative expenses			$	25					$	0.90					$	24					$	0.82

Merger and Integration Expense. The following tables shows merger and integration expense for the three months ended March 31, 2021 and 2020:

			Three Months Ended March 31,
			2021						2020
			(In millions)
Merger and integration expense			$	75					$	—

Total merger and integration expense for the three months ended March 31, 2021 includes $67 million in costs incurred for the QEP Merger and $8 million in costs incurred for the Guidon Acquisition. The QEP Merger related expenses primarily consist of $38 million in severance costs and $23 million in banking, legal and advisory fees, and the Guidon Acquisition related expenses consist primarily of advisory fees. See Note 4—Acquisitions for further details regarding the QEP Merger and Guidon Acquisition.

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Net Interest Expense. The following table shows the components of net interest expense for the three months ended March 31, 2021 and 2020:

			Three Months Ended March 31,
			2021						2020
			(In millions)
Revolving credit agreements			$	3					$	7
Senior notes			61						48
Amortization of debt issuance costs and discounts			4						2
Other			4						4
Capitalized interest			(14)						(13)
Total			58						48
Less: interest income			2						—
Interest expense, net			$	56					$	48

Net interest expense increased by $8 million for the three months ended March 31, 2021 compared to the same period in 2020. The increase was primarily due to interest expense related to our May 2020 Notes, Rattler’s 5.625% Senior Notes due 2025, and to a lesser extent, interest expense incurred on the QEP Notes that remained outstanding following the QEP Merger completed in March 2021 and the newly issued March 2021 Notes, which increase was partially offset by interest cost savings on the repurchase of $368 million in outstanding principal of our 2025 Notes in March 2021, and a decrease in borrowings under our revolving credit agreements. See Note 9—Debt for further details regarding outstanding borrowings and interest expense.

Derivative Instruments. The following table shows the net gain (loss) on derivative instruments and the net cash receipts (payments) on settlements of derivative instruments for the three months ended March 31, 2021 and 2020:

			Three Months Ended March 31,
			2021						2020
			(In millions)
Gain (loss) on derivative instruments, net			$	(164)					$	542
Net cash received (paid) on settlements(1)			$	(102)					$	87

(1)The three months ended March 31, 2021 include cash received on interest rate swap contracts terminated prior to their contractual maturity of $80 million.

We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our condensed consolidated statements of operations under the line item captioned “Gain (loss) on derivative instruments, net.” As part of the QEP Merger, we received by novation from QEP certain derivative instruments which were included on our balance sheet as of March 31, 2021.

Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the three months ended March 31, 2021 and 2020:

			Three Months Ended March 31,
			2021						2020
			(In millions)
Provision for (benefit from) income taxes			$	65					$	83

The change in our income tax provision for the first quarter of 2021 compared to the same period in 2020 was primarily due to income tax expense resulting from recording a valuation allowance on Viper’s deferred tax assets for the three months ended March 31, 2020.

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Liquidity and Capital Resources

Historically, our primary sources of liquidity have been cash flows from operations, proceeds from our public equity offerings, borrowings under our revolving credit facility and proceeds from the issuance of our senior notes. Our primary uses of capital have been for the acquisition, development and exploration of oil and natural gas properties.

As we pursue our business and financial strategy, we regularly consider which capital resources, including cash flow and equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us. Continued prolonged volatility in the capital, financial and/or credit markets due to the COVID-19 pandemic, the depressed commodity markets and/or adverse macroeconomic conditions may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all.

Liquidity and Cash Flow

Our cash flows for the three months ended March 31, 2021 and 2020 are presented below:

			Three Months Ended March 31,
			2021						2020
			(In millions)
Net cash provided by (used in) operating activities			$	624					$	849
Net cash provided by (used in) investing activities			(587)						(923)
Net cash provided by (used in) financing activities			29						101
Net increase (decrease) in cash			$	66					$	27

Operating Activities

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

The decrease in operating cash flows for the three months ended March 31, 2021 compared to the same period in 2020 primarily resulted from (i) working capital changes, primarily due to the timing of collections of our oil and natural gas sales receivables and recording working capital assets and liabilities acquired in the QEP Merger during March 2021, (ii) a reduction of $265 million due to making net cash payments of $178 million on our derivative contracts in the first quarter of 2021 compared to receiving net cash of $87 million on our derivative contracts in the first quarter of 2020, and (iii) acquisition costs of $75 million incurred during the first quarter of 2021 for the QEP Merger and Guidon Acquisition. These net cash outflows were partially offset by an increase of $285 million in our total revenues and receipt of a $100 million refund of an income tax receivable related to the carryback of federal net operating losses and the accelerated refund of minimum tax credits allowed under the CARES Act in 2020.

Investing Activities

Net cash used in investing activities was $587 million compared to $923 million during the three months ended March 31, 2021 and 2020, respectively. The majority of our cash used for investing activities during 2021 was for the purchase and development of oil and natural gas properties and related assets including the acquisition of certain leasehold interests as part of the Guidon Acquisition. The majority of our net cash used in investing activities during the three months ended March 31, 2020 was incurred for drilling and completion costs in conjunction with our development program. Our capital expenditures for each period are discussed further below.

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Capital Expenditure Activities

Our capital expenditures excluding acquisitions and equity method investments (on a cash basis) were as follows for the specified period:

			Three Months Ended March 31,
			2021						2020
			(In millions)
Drilling, completions and non-operated additions to oil and natural gas properties(1)(2)			$	281					$	690
Infrastructure additions to oil and natural gas properties			8						56
Additions to midstream assets			7						44
Total			$	296					$	790

(1)During the three months ended March 31, 2021, in conjunction with our development program, we drilled 49 gross (47 net) operated horizontal wells, of which 41 gross (40 net) wells were in the Midland Basin and eight gross (seven net) wells were in the Delaware Basin, and turned 67 gross (60 net) operated horizontal wells to production, of which 42 gross (37 net) wells were in the Midland Basin and 25 gross (23 net) wells were in the Delaware Basin.

(2)During the three months ended March 31, 2020, in conjunction with our development program, we drilled 93 gross (85 net) operated horizontal wells, of which 55 gross (50 net) wells were in the Midland Basin and 38 gross (35 net) wells were in the Delaware Basin, and turned 80 gross (72 net) operated horizontal wells to production, of which 46 gross (42 net) wells were in the Delaware Basin and 34 gross (30 net) wells were in the Midland Basin.

Financing Activities

Net cash provided by financing activities for the three months ended March 31, 2021 and 2020 was $29 million and $101 million, respectively. During the three months ended March 31, 2021, the amount provided by financing activities was primarily attributable to $2.2 billion in proceeds from the March 2021 Notes and $76 million in proceeds that relate primarily to the early settlement of interest rate swaps that contained an other-than-insignificant financing element. These net increases in cash flows from financing activities were partially offset by $1.9 billion paid for the repurchase of a portion of the QEP Notes and 2025 Senior Notes, as well as $166 million of additional premiums paid in connection with the repurchases, $68 million of dividends paid to stockholders, $24 million of unit repurchases as part of the Viper and Rattler unit repurchase programs and $23 million of repayments under our credit facilities, net of borrowings.

The 2020 amount provided by financing activities was primarily attributable to $290 million of borrowings, net of repayments under our credit facilities and $16 million in proceeds from joint ventures, partially offset by $98 million of share repurchases as part of our previous stock repurchase program, $59 million of dividends to stockholders, $43 million of distributions to non-controlling interest and $5 million of cash paid for tax withholding on vested equity awards.

Indebtedness

At March 31, 2021, our debt, including the debt of Viper and Rattler, consists of approximately $7.5 billion in aggregate outstanding principal amount of senior notes (including $191 million due in 2021), $163 million in aggregate outstanding borrowings under revolving credit facilities and $75 million in outstanding amounts due under our DrillCo Agreement. Our revolving credit facilities and significant changes in our outstanding indebtedness during the three months ended March 31, 2021 are discussed further below. See Note 9—Debt for additional discussion of our outstanding debt at March 31, 2021.

Second Amended and Restated Credit Facility

As of March 31, 2021, the maximum credit amount available under our credit agreement was $2 billion, with $52 million in outstanding borrowings and $1.9 billion available for future borrowings. As of March 31, 2021, there was an aggregate of $3 million in letters of credit outstanding under our credit agreement. The weighted average interest rate on borrowings under the credit facility was 1.65% for the three months ended March 31, 2021.

As of March 31, 2021, we were in compliance with all financial maintenance covenants under the credit agreement.

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March 2021 Notes Offering

On March 24, 2021, we issued $650 million of our 2023 Notes, $900 million of our 2031 Notes and $650 million of our 2051 Notes and received proceeds of $2.18 billion, net of $24 million in debt issuance costs and discounts. 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 on March 24 and September 24, beginning on September 24, 2021.

QEP Notes and Repurchases of Notes

On March 17, 2021, in conjunction with the QEP Merger discussed in Note 4—Acquisitions, QEP’s outstanding debt had fair values consisting of $478 million of the QEP 2022 Notes, $673 million of the QEP 2023 Notes, and $558 million of the QEP 2026 Notes.

Subsequent to the QEP Merger, in March 2021, we repurchased pursuant to tender offers commenced by us 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, which resulted in a loss on extinguishment of debt during the three months ended March 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 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, we also repurchased an aggregate of $368 million principal amount of our 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, which resulted in a loss on extinguishment of debt during the three months ended March 31, 2021 of $14 million.

We 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, we 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 QEP indenture under which the QEP Notes were issued. We received the requisite number of consents and, on March 23, 2021, entered into a supplemental indenture relating to the QEP Notes adopting these amendments.

Viper’s Credit Agreement

The Viper credit agreement, as amended to date, or the Viper credit agreement, provides for a revolving credit facility in the maximum credit amount of $2 billion, with a borrowing base of $580 million as of March 31, 2021 based on Viper LLC’s oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be redetermined semi-annually in May and November. As of March 31, 2021, Viper LLC had $57 million of outstanding borrowings and $523 million available for future borrowings under the Viper credit agreement. The weighted average interest rate on borrowings under the Viper credit agreement was 1.88% for the three months ended March 31, 2021. The Viper credit agreement matures on November 1, 2022.

As of March 31, 2021, Viper LLC was in compliance with all financial maintenance covenants under the Viper credit agreement.

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Rattler’s Credit Agreement

The Rattler credit agreement, as amended to date, or the Rattler credit agreement, provides for a revolving credit facility in the maximum credit amount of $600 million, which is expandable to $1 billion upon Rattler’s election, subject to obtaining additional lender commitments and satisfaction of customary conditions. As of March 31, 2021, Rattler LLC had $54 million of outstanding borrowings and $546 million available for future borrowings under the Rattler credit agreement. The weighted average interest rate on borrowings under the Rattler credit agreement was 1.40% for the three months ended March 31, 2021. The Rattler credit agreement matures on May 28, 2024.

As of March 31, 2021, Rattler LLC was in compliance with all financial maintenance covenants under the Rattler credit agreement.

Capital Requirements and Sources of Liquidity

Our board of directors initially approved a 2021 capital budget for drilling and completion, midstream and infrastructure of approximately $1.4 billion to $1.6 billion. We have updated our 2021 capital budget to approximately $1.6 billion to $1.75 billion to give effect to the QEP Merger, representing an increase of 16% over our original 2021 capital budget. We estimate that, of these expenditures, approximately:

•$1.5 billion to $1.6 billion will be spent on drilling and completing 275 to 285 gross (250 to 259 net) horizontal wells across our operated leasehold acreage in the Northern Midland and Southern Delaware Basins, with an average lateral length of approximately 10,300 feet;

•$60 million to $80 million will be spent on midstream infrastructure, excluding joint venture investments; and

•$80 million to $90 million will be spent on infrastructure and other expenditures, excluding the cost of any leasehold and mineral interest acquisitions.

    We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.

During the first quarter of 2021, we spent $273 million on drilling and completion, $7 million on midstream, $8 million on non-operated properties and $8 million on infrastructure, for total capital expenditures, excluding acquisitions, of $296 million.

The amount and timing of our capital expenditures are largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. We are currently operating 11 drilling rigs and three completion crews. We currently continue to execute on our strategy to hold oil production flat while using cash flow from operations to reduce debt, strengthen our balance sheet and return capital to our stockholders. We will continue monitoring commodity prices and overall market conditions and can adjust our rig cadence up or down in response to changes in commodity prices and overall market conditions.

Based upon current oil and natural gas prices and production expectations for 2021, we believe that our cash flow from operations, cash on hand and borrowings under our revolving credit facility will be sufficient to fund our operations through the 12-month period following the filing of this report. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. Further, our 2021 capital expenditure budget does not allocate any funds for leasehold interest and property acquisitions.

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

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

Guarantor Financial Information

As of March 31, 2021, Diamondback O&G LLC is the sole guarantor under the indentures governing the December 2019 Notes, the May 2020 Notes, the 2025 Senior Notes and the March 2021 Notes.

Guarantees are “full and unconditional,” as that term is used in Regulation S-X, Rule 3-10(b)(3), except that such guarantees will be released or terminated in certain circumstances set forth in the December 2019 Notes Indenture and the 2025 Indenture, such as, with certain exceptions, (1) in the event Diamondback O&G LLC (or all or substantially all of its assets) is sold or disposed of, (2) in the event Diamondback O&G LLC ceases to be a guarantor of or otherwise be an obligor under certain other indebtedness, and (3) in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the relevant indenture.

Diamondback O&G LLC’s guarantees of the December 2019 Notes, the May 2020 Notes, the 2025 Senior Notes and the March 2021 Notes are senior unsecured obligations and rank senior in right of payment to any of its future subordinated indebtedness, equal in right of payment with all of its existing and future senior indebtedness, including its obligations under its revolving credit facility, and effectively subordinated to any of its existing and future secured indebtedness, to the extent of the value of the collateral securing such indebtedness.

The rights of holders of the Senior Notes against Diamondback O&G LLC may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law. Each guarantee contains a provision intended to limit Diamondback O&G LLC’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent conveyance. However, there can be no assurance as to what standard a court will apply in making a determination of the maximum liability of Diamondback O&G LLC. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished.

The following tables present summarized financial information for Diamondback Energy, Inc., as the parent, and Diamondback O&G LLC, as the guarantor subsidiary, on a combined basis after elimination of (i) intercompany transactions and balances between the parent and the guarantor subsidiary and (ii) equity in earnings from and investments in any subsidiary that is a non-guarantor. The information is presented in accordance with the requirements of Rule 13-01 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiary operated as an independent entity.

			March 31, 2021						December 31, 2020
Summarized Balance Sheets:			(In millions)
Assets:
Current assets			$	302					$	308
Property and equipment, net			$	8,108					$	6,934
Other noncurrent assets			$	10					$	6
Liabilities:
Current liabilities			$	769					$	355
Intercompany accounts payable, non-guarantor subsidiary			$	408					$	335
Long-term debt			$	6,132					$	4,293
Other noncurrent liabilities			$	916					$	886

			Three Months Ended March 31, 2021
Summarized Statement of Operations:			(In millions)
Revenues			$	650
Income (loss) from operations			$	328
Net income (loss)			$	85

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Contractual Obligations

In addition to the changes in debt discussed in “—Indebtedness” above and in Note 9—Debt included in the notes to the condensed consolidated financial statements included elsewhere in this report, we acquired certain contractual obligations during the three months ended March 31, 2021 in conjunction with the QEP Merger including an aggregate of approximately $68 million in various transportation, gathering and purchase commitments. There were no other significant changes in our contractual obligations from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2020.

Critical Accounting Policies and Estimates

There have been no changes in our critical accounting policies from those disclosed in our Annual Report on Form  10-K for the year ended December 31, 2020.

Off-Balance Sheet Arrangements

We had no material off-balance sheet arrangements as of March 31, 2021. Please read Note 15—Commitments and Contingencies included in the notes to the condensed consolidated financial statements included elsewhere in this report, for a discussion of our commitments and contingencies, which are not recognized in the balance sheets under GAAP.

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

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

We use derivatives, including swaps, basis swaps, puts, swaptions, roll swaps, and costless collars, to reduce price volatility associated with certain of our oil and natural gas sales.

At March 31, 2021, we had a net liability derivative position related to our commodity price derivatives of $608 million, related to our commodity price risk derivatives. Utilizing actual derivative contractual volumes under our commodity price derivatives as of March 31, 2021, a 10% increase in forward curves associated with the underlying commodity would have increased the net liability position to $670 million, an increase of $62 million, while a 10% decrease in forward curves associated with the underlying commodity would have decreased the net liability position to $546 million, a decrease of $62 million. However, any cash derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.

In our midstream operations business, we have indirect exposure to commodity price risk in that persistent low commodity prices may cause us or Rattler’s other customers to delay drilling or shut in production, which would reduce the volumes available for gathering and processing by our infrastructure assets. If we or Rattler’s other customers delay drilling or temporarily shut in production due to persistently low commodity prices or for any other reason, our revenue in the midstream operations segment could decrease, as Rattler’s commercial agreements do not contain minimum volume commitments.

For additional information on our open commodity derivative instruments at March 31, 2021, see Note 13—Derivatives.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are due to the concentration of receivables from the sale of our oil and natural gas production (approximately $531 million at March 31, 2021), and to a lesser extent, receivables resulting from joint interest receivables (approximately $68 million at March 31, 2021).

We do not require our customers to post collateral, and the failure or inability of our significant customers to meet their obligations to us due to their liquidity issues, bankruptcy, insolvency or liquidation may adversely affect our financial results.

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Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facility. The terms of our revolving credit facility provide for interest on borrowings at a floating rate equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.125% to 1.0% per annum in the case of the alternative base rate and from 1.125% to 2.0% per annum in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. Historically, we have at times used interest rate swaps and treasury locks to reduce our exposure to variable rate interest payments associated with our revolving credit facility.

For additional information on our variable interest rate debt at March 31, 2021, see Note 9—Debt.

ITEM 4.          CONTROLS AND PROCEDURES

Evaluation of Disclosure Control and Procedures

Under the direction of our Chief Executive Officer and Chief Financial Officer, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, or the Exchange Act, that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

As of March 31, 2021, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that as of March 31, 2021, our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

There have not been any changes in our internal control over financial reporting that occurred during the quarter ended March 31, 2021, that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

PART II

ITEM 1. LEGAL PROCEEDINGS

We are a party to various routine legal proceedings, disputes and claims arising in the ordinary course of our business, including those that arise from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry, personal injury claims, title disputes, royalty disputes, contract claims, contamination claims relating to oil and natural gas exploration and development and environmental claims, including claims involving assets previously sold to third parties and no longer part of our current operations. While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on us, cannot be predicted with certainty, we believe that none of these matters, if ultimately decided adversely, will have a material adverse effect on our financial condition, results of operations or cash flows. See Note 15—Commitments and Contingencies.

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ITEM 1A. RISK FACTORS

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

As of the date of this filing, we continue to be subject to the risk factors previously disclosed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on February 25, 2021, and in subsequent filings we make with the SEC. There have been no material changes in our risk factors from those described in our Annual Report on Form 10-K for the year ended December 31, 2020.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Unregistered Sales of Equity Securities

None.

Issuer Repurchases of Equity Securities

Our common stock repurchase activity for the three months ended March 31, 2021 was as follows:

Period						Total Number of Shares Purchased(1)						Average Price Paid Per Share(2)						Total Number of Shares Purchased as Part of Publicly Announced Plan						Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan
						($ In millions, except per share amounts, shares in thousands)
January 1, 2021 - January 31, 2021						—						$	—					—						$	—
February 1, 2021 - February 28, 2021						—						$	—					—						$	—
March 1, 2021 - March 31, 2021						185						$	76.24					—						$	—
Total						185						$	76.24					—

(1)Includes shares of common stock repurchased from employees in order to satisfy tax withholding requirements. Such shares are cancelled and retired immediately upon repurchase.

(2)The average price paid per share is net of any commissions paid to repurchase stock.

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ITEM 6.    EXHIBITS

EXHIBIT INDEX

Exhibit Number			Description
3.1			Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
3.2			Certificate of Amendment No. 1 of the Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on December 12, 2016).
3.3			Second Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on November 19, 2019).
4.1			Specimen certificate for shares of common stock, par value $0.01 per share, of the Company (incorporated by reference to Exhibit 4.1 to Amendment No. 4 to the Registration Statement on Form S-1, File No. 333-179502, filed by the Company with the SEC on August 20, 2012).
4.2			Registration Rights Agreement, dated as of February 26, 2021, by and among the Company, Guidon Operating LLC and Guidon Energy Holdings LP (incorporated by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-3, File No. 333-255731, filed by the Company with the SEC on May 3, 2021.
4.3			Letter Agreement, dated as of April 27, 2021, by and among the Company, Guidon Operating LLC and Guidon Energy Holdings LP relating to the Registration Rights Agreement referenced as Exhibit 4.2 hereto (incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement on Form S-3, File No. 333-255731, filed by the Company with the SEC on May 3, 2021).
4.4			Third Supplemental Indenture, dated as of March 24, 2021, among Diamondback Energy, Inc., Diamondback O&G LLC and Wells Fargo Bank, National Association, as trustee (including the forms of 2023 Notes, 2031 Notes and 2051 Notes) (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on March 24, 2021).
4.5			First Supplemental Indenture, dated as of March 23, 2021, among QEP Resources, Inc. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on March 24, 2021).
10.1			2021 Form of Time Vesting Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.4 to the Form 10-K, File No. 001-35700, filed by the Company with the SEC on February 25, 2021).
10.2			2021 Form of Performance Vesting Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.5 to the Form 10-K, File No. 001-35700, filed by the Company with the SEC on February 25, 2021).
10.3			Executive Annual Incentive Compensation Plan adopted in February 2021 (incorporated by reference to Exhibit 10.11 to the Form 10-K, File No. 001-35700, filed by the Company with the SEC on February 25, 2021).
22.1			List of Issuers and Guarantor Subsidiaries (incorporated by reference to Exhibit 22.1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on May 7, 2020).
31.1*			Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
31.2*			Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
32.1**			Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
32.2**			Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
101			The following financial information from the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2021, formatted in Inline XBRL: (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statement of Changes in Stockholders’ Equity, (iv) Condensed Consolidated Statements of Cash Flows and (v) Condensed Notes to Consolidated Financial Statements.
104			Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

______________

*			Filed herewith.
**			The certifications attached as Exhibit 32.1 and Exhibit 32.2 accompany this Quarterly Report on Form 10-Q pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

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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:			May 7, 2021			/s/ Travis D. Stice
						Travis D. Stice
						Chief Executive Officer
						(Principal Executive Officer)
Date:			May 7, 2021			/s/ Kaes Van’t Hof
						Kaes Van’t Hof
						Chief Financial Officer
						(Principal Financial Officer)

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