Diamondback Energy, Inc. - Quarter Report: 2020 March (Form 10-Q)

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, 2020



☐	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 May 1, 2020, the registrant had 157,815,843 shares of common stock outstanding.

DIAMONDBACK ENERGY, INC.

FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2020

TABLE OF CONTENTS



	Page
Glossary of Oil and Natural Gas Terms	ii
Glossary of Certain Other Terms	iv
Cautionary Statement Regarding Forward-Looking Statements	v

PART I. FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements (Unaudited)
Consolidated Balance Sheets	1
Consolidated Statements of Operations	3
Consolidated Statements of Stockholders’ Equity	4
Consolidated Statements of Cash Flows	5
Condensed Notes to Consolidated Financial Statements	7

Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operations	41

Item 3. Quantitative and Qualitative Disclosures about Market Risk	59

Item 4. Controls and Procedures	61

PART II. OTHER INFORMATION
Item 1. Legal Proceedings	62

Item 1A. Risk Factors	62

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	63

Item 6. Exhibits	64

Signatures	66

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GLOSSARY OF OIL AND NATURAL GAS TERMS

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



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

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Spacing	The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.
Working interest	An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

iii

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GLOSSARY OF CERTAIN OTHER TERMS

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



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, dated as of December 20, 2016, among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented.
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 relating to the December 2019 Notes, 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.
NYMEX	New York Mercantile Exchange.
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.
Rattler Offering	Rattler’s initial public offering.
Rattler’s Partnership Agreement	The first amended and restated agreement of limited partnership, dated May 28, 2019.
SEC	United States Securities and Exchange Commission.
Securities Act	The Securities Act of 1933, as amended.
2025 Senior Notes	The Company’s 5.375% senior unsecured notes due 2025 in the aggregate principal amount of $800 million.
Senior Notes	The 2025 Senior Notes and December 2019 Notes.
Viper	Viper Energy Partners LP, a Delaware limited partnership.
Viper’s General Partner	Viper Energy Partners GP LLC, a Delaware limited liability company and the General Partner of the Partnership.
Viper LLC	Viper Energy Partners LLC, a Delaware limited liability company and a subsidiary of the Partnership.
Viper LTIP	Viper Energy Partners LP Long Term Incentive Plan.
Viper Offering	Viper’s initial public offering.
Viper’s Partnership Agreement	The second amended and restated agreement of limited partnership, dated May 9, 2018, as amended as of May 10, 2018.
Wells Fargo	Wells Fargo Bank, National Association.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act, and Section 21E of the Exchange Act. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed in this report and detailed under Part II, Item 1A. Risk Factors in this report and our Annual Report on Form 10–K for the year ended December 31, 2019 could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted or implied in such forward-looking statements.

Forward-looking statements may include statements about our:


•	the volatility of realized oil and natural gas prices and the extent and duration of price reductions and increased production by OPEC members and other oil exporting nations;


•	the threat, occurrence, potential duration or other implications of epidemic or pandemic diseases, including the recent outbreak of a novel strain of coronavirus, or COVID-19, or any government responses to such occurrence or threat;


•	any impact of the ongoing COVID-19 pandemic on the health and safety of our employees;


•	logistical challenges and the supply chain disruptions;


•	general economic, business or industry conditions;


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


•	U.S. and global economic conditions and political and economic developments, including the outcome of the U.S. presidential election and resulting energy and environmental 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;


•	regional supply and demand factors, 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 integrate acquisitions of properties or businesses;


•	competition in the oil and natural gas industry;


•	title defects in our oil and natural gas properties;


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

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•	the availability or cost of rigs, equipment, raw materials, supplies, oilfield services or personnel;


•	restrictions on the use of water;


•	the availability of transportation, pipeline and storage facilities;


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


•	federal and state legislative and regulatory initiatives relating to hydraulic fracturing;


•	future operating results;


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


•	operating hazards;


•	our ability to keep up with technological advancements.


•	capital expenditure plans;


•	other plans, objectives, expectations and intentions.

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

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PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)



Diamondback Energy, Inc. and Subsidiaries
Consolidated Balance Sheets
(Unaudited)


	March 31,			December 31,
	2020			2019
	(In millions, except par values and share data)
Assets
Current assets:
Cash and cash equivalents	$	149		$	123
Restricted cash	6			5
Accounts receivable:
Joint interest and other, net	178			186
Oil and natural gas sales, net	225			429
Inventories	36			37
Derivative instruments	534			46
Prepaid expenses and other current assets	140			43
Total current assets	1,268			869
Property and equipment:
Oil and natural gas properties, full cost method of accounting ($8,488 million and $9,207 million excluded from amortization at March 31, 2020 and December 31, 2019, respectively)	26,719			25,782
Midstream assets	987			931
Other property, equipment and land	130			125
Accumulated depletion, depreciation, amortization and impairment	(6,416		)	(5,003		)
Net property and equipment	21,420			21,835
Equity method investments	502			479
Derivative instruments	30			7
Deferred tax asset, net	—			142
Investment in real estate, net	107			109
Other assets	59			90
Total assets	$	23,386		$	23,531

See accompanying notes to consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Consolidated Balance Sheets-(Continued)

(Unaudited)



	March 31,		December 31,
	2020		2019
	(In millions, except par values and share data)
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable-trade	$	245	$	179
Accrued capital expenditures	490		475
Other accrued liabilities	287		304
Revenues and royalties payable	292		278
Derivative instruments	16		27
Total current liabilities	1,330		1,263
Long-term debt	5,677		5,371
Derivative instruments	66		—
Asset retirement obligations	99		94
Deferred income taxes	1,888		1,886
Other long-term liabilities	10		11
Total liabilities	9,070		8,625
Commitments and contingencies (Note 18)
Stockholders’ equity:
Common stock, $0.01 par value, 200,000,000 shares authorized, 157,815,843 issued and outstanding at March 31, 2020; 200,000,000 shares authorized, 159,002,338 issued and outstanding at December 31, 2019	2		2
Additional paid-in capital	12,265		12,357
Retained earnings	559		890
Total Diamondback Energy, Inc. stockholders’ equity	12,826		13,249
Non-controlling interest	1,490		1,657
Total equity	14,316		14,906
Total liabilities and equity	$	23,386	$	23,531

See accompanying notes to consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

(Unaudited)



	Three Months Ended March 31,
	2020			2019
	(In millions, except per share amounts, shares in thousands)
Revenues:
Oil sales	$	827		$	743
Natural gas sales	4			29
Natural gas liquid sales	52			70
Lease bonus	—			1
Midstream services	14			19
Other operating income	2			2
Total revenues	899			864
Costs and expenses:
Lease operating expenses	127			109
Production and ad valorem taxes	71			55
Gathering and transportation	36			12
Midstream services	23			17
Depreciation, depletion and amortization	407			322
Impairment of oil and natural gas properties	1,009			—
General and administrative expenses	24			27
Asset retirement obligation accretion	2			2
Other operating expense	2			1
Total costs and expenses	1,701			545
(Loss) income from operations	(802		)	319
Other income (expense):
Interest expense, net	(48		)	(46		)
Other income, net	1			1
Gain (loss) on derivative instruments, net	542			(268		)
(Loss) gain on revaluation of investment	(10		)	4
Total other income (expense), net	485			(309		)
(Loss) income before income taxes	(317		)	10
Provision for (benefit from) income taxes	83			(33		)
Net (loss) income	(400		)	43
Net (loss) income attributable to non-controlling interest	(128		)	33
Net (loss) income attributable to Diamondback Energy, Inc.	$	(272	)	$	10
Earnings per common share:
Basic	$	(1.72	)	$	0.06
Diluted	$	(1.72	)	$	0.06
Weighted average common shares outstanding:
Basic	158,291			164,852
Diluted	158,494			165,061
Dividends declared per share	$	0.3750		$	0.1875

See accompanying notes to consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Stockholders’ Equity

(Unaudited)



	Common Stock				Additional Paid-in Capital			Retained Earnings (Accumulated Deficit)			Non-Controlling Interest			Total
	Shares		Amount
	($ in 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
Repurchased shares for tax withholding			—		(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
Change in ownership of consolidated subsidiaries, net			—		—			—			—			—
Net loss			—		—			(272		)	(128		)	(400		)
Balance March 31, 2020	157,815		$	2	$	12,265		$	559		$	1,490		$	14,316



	Common Stock				Additional Paid-in Capital			Retained Earnings (Accumulated Deficit)			Non-Controlling Interest			Total
	Shares		Amount		Additional Paid-in Capital			Retained Earnings (Accumulated Deficit)			Non-Controlling Interest			Total
	($ in millions, shares in thousands)
Balance December 31, 2018	164,273		$	2	$	12,936		$	762		$	467		$	14,167
Net proceeds from issuance of common units - Viper Energy Partners LP			—		—			—			341			341
Stock-based compensation			—		19			—			—			19
Repurchased shares for tax withholding	(125	)	—		(13		)	—			—			(13		)
Distribution to non-controlling interest			—		—			—			(26		)	(26		)
Dividend paid			—		—			(20		)	—			(20		)
Exercise of stock options and vesting of restricted stock units	468		—		—			—			—			—
Change in ownership of consolidated subsidiaries, net			—		77			—			(74		)	3
Net income			—		—			10			33			43
Balance March 31, 2019	164,616		$	2	$	13,019		$	752		$	741		$	14,514

See accompanying notes to consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(Unaudited)



	Three Months Ended March 31,
	2020			2019

	(In millions)
Cash flows from operating activities:
Net (loss) income	$	(400	)	$	43
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Provision for (benefit from) deferred income taxes	83			(33		)
Impairment of oil and natural gas properties	1,009			—
Asset retirement obligation accretion	2			2
Depreciation, depletion and amortization	407			322
Amortization of debt issuance costs	2			1
Change in fair value of derivative instruments	(455		)	285
Loss (gain) on revaluation of investment	10			(4		)
Equity-based compensation expense	9			14
Changes in operating assets and liabilities:
Accounts receivable	175			(63		)
Inventories	1			(4		)
Prepaid expenses and other	(4		)	(9		)
Accounts payable and accrued liabilities	(35		)	(190		)
Accrued interest	31			5
Revenues and royalties payable	14			8
Net cash provided by operating activities	849			377
Cash flows from investing activities:
Drilling, completions and non-operated additions to oil and natural gas properties	(690		)	(533		)
Infrastructure additions to oil and natural gas properties	(56		)	(36		)
Additions to midstream assets	(44		)	(58		)
Purchase of other property, equipment and land	(5		)	(4		)
Acquisitions of leasehold interests	(40		)	(75		)
Acquisitions of mineral interests	(65		)	(82		)
Contributions to equity method investments	(33		)	(149		)
Distributions from equity method investments	10			—
Net cash used in investing activities	(923		)	(937		)
Cash flows from financing activities:
Proceeds from borrowings under credit facility	430			484
Repayments under credit facility	(140		)	(314		)
Proceeds from joint venture	16			23
Debt issuance costs	—			(3		)
Proceeds from public offerings	—			341
Proceeds from exercise of stock options	1			—
Repurchased shares for tax withholdings	(5		)	(13		)
Repurchased shares as part of share buyback	(98		)	—
Distribution equivalent rights	(1		)	—
Dividends to stockholders	(59		)	(21		)
Distributions to non-controlling interest	(43		)	(26		)
Net cash provided by financing activities	101			471
Net increase (decrease) in cash and cash equivalents	27			(89		)

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Diamondback Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows - Continued

(Unaudited)



	Three Months Ended March 31,
	2020		2019

	(In millions)
Cash and cash equivalents at beginning of period	128		215
Cash and cash equivalents at end of period	$	155	$	126
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest	$	16	$	17
Supplemental disclosure of non-cash transactions:
Change in accrued capital expenditures	$	15	$	(10	)
Capitalized stock-based compensation	$	6	$	6
Asset retirement obligations acquired	$	—	$	3

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported in the Consolidated Balance Sheets that sum to the total of the same such amounts shown above:



	March 31, 2020
	(In millions)
Cash and cash equivalents	$	149
Restricted cash	6
Total cash, cash equivalents and restricted cash shown in statement of cash flows	$	155

See accompanying notes to 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 gas company currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. Diamondback was incorporated in Delaware on December 30, 2011.

The wholly-owned subsidiaries of Diamondback, as of March 31, 2020, include Diamondback E&P LLC, a Delaware limited liability company, Diamondback O&G LLC, a Delaware limited liability company, Viper Energy Partners GP LLC, a Delaware limited liability company, Rattler Midstream GP LLC, a Delaware limited liability company, and Energen Corporation, an Alabama corporation (“Energen”). The consolidated subsidiaries include these wholly-owned subsidiaries as well as Viper Energy Partners LP, a Delaware limited partnership (“Viper”), Viper’s subsidiary Viper Energy Partners LLC, a Delaware limited liability company (“Viper LLC”), Rattler Midstream LP, a Delaware limited partnership (“Rattler”), Rattler Midstream Operating LLC, a Delaware limited liability company (“Rattler LLC”), Rattler LLC’s wholly-owned subsidiary Tall City Towers LLC, a Delaware limited liability company (“Tall City”), and Energen’s wholly-owned subsidiaries Energen Resources Corporation, an Alabama corporation, and EGN Services, Inc., an Alabama corporation.

Basis of Presentation

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

Viper is consolidated in the financial statements of the Company. As of March 31, 2020, the Company owned approximately 58% of Viper’s total units outstanding. The Company’s wholly-owned subsidiary, Viper Energy Partners GP LLC, is the general partner of Viper.

Rattler is consolidated in the financial statements of the Company. As of March 31, 2020, the Company owned approximately 71% of Rattler’s total units outstanding. The Company’s wholly-owned subsidiary, Rattler Midstream GP LLC, is the general partner of Rattler.

These financial statements have been prepared by the Company without audit, pursuant to the rules and regulations of the SEC. They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been omitted pursuant to such rules and regulations, although the Company believes the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10–Q should be read in conjunction with the Company’s most recent Annual Report on Form 10–K for the fiscal year ended December 31, 2019, which contains a summary of the Company’s significant accounting policies and other disclosures.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

Certain amounts included in or affecting the Company’s consolidated financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates.

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Making accurate estimates and assumptions are particularly difficult as the oil and gas industry experiences challenges resulting from negative pricing pressure from the effects of a decline in worldwide economic conditions. The decline in worldwide economic conditions is the result of a global COVID-19 pandemic announced in March 2020, which has reduced economic activity and resulted in a significant decline in the short term demand for oil and gas production. Companies in the oil and gas industry are beginning to change near term business plans in response to changing market conditions. The aforementioned circumstances generally increases the estimation uncertainty in our accounting estimates, particularly the accounting estimates 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.

Accounts Receivable

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

The Company adopted Accounting Standards Update (“ASU”) 2016-13 and the subsequent applicable modifications to the rule on January 1, 2020. Accounts receivable are stated at amounts due from joint interest owners or purchasers, net of an allowance for expected losses as estimated by the Company. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable from joint interest owners or purchasers outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance for each type of receivable by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for expected losses. The adoption of ASU 2016-13 did not result in a material change to the Company’s allowance. At March 31, 2020, the Company recorded an allowance for doubtful accounts of $1 million related to joint interest and other receivables and $1 million related to oil and natural gas sales receivables.

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Condensed Notes to Consolidated Financial Statements-(Continued)

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Recent Accounting Pronouncements

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



Standard	Description	Date of Adoption	Effect on Financial Statements or Other Significant Matters
Recently Adopted Pronouncements
ASU 2016-13, “Financial Instruments - Credit Losses”	This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash.	Q1 2020	The Company adopted this update effective January 1, 2020. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity since it does not have a history of credit losses.
ASU 2018-13, “Fair Value Measurement (Topic 820) - Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement”	This update modifies the fair value measurement disclosure requirements specifically related to Level 3 fair value measurements and transfers between levels.	Q1 2020	The Company adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity since it does not have transfers between fair value levels.
ASU 2018-15, “Intangibles - Goodwill and Other - Internal - Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract”	This update requires the capitalization of implementation costs incurred in a hosting arrangement that is a service contract for internal-use software. Training and certain data conversion costs cannot be capitalized. The entity is required to expense the capitalized implementation costs over the term of the hosting agreement.	Q1 2020	The Company adopted this update prospectively effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.
ASU 2019-05, “Financial Instruments-Credit Losses (Topic 326)”	This update allows a fair value option to be elected for certain financial assets, other than held-to-maturity debt securities, that were previously required to be measured at amortized cost basis.	Q1 2020	The Company adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity since it does not have any cost method investments.
ASU 2020-04, “Rate Reform (Topic 848)”	This update provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions that reference LIBOR.	Q1 2020	The Company adopted this update upon issuance and elected to use the optional expedient for contracts and hedging that reference LIBOR. The amendments in this update expire on December 31, 2022. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.
Pronouncements Not Yet Adopted
ASU 2019-12, “Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes”	This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance.	Q1 2021	This update is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Company does not believe that the adoption of this update will have an impact on its financial position, results of operations or liquidity.

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3. REVENUE FROM CONTRACTS WITH CUSTOMERS

Revenue from Contracts with Customers

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

Oil sales

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

Natural gas and natural gas liquids sales

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

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

Midstream Revenue

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

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Transaction price allocated to remaining performance obligations

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

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

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

Contract balances

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

Prior-period performance obligations

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the three months ended March 31, 2020, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Company believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the revenue related to expected sales volumes and prices for those properties are estimated and recorded.

4. VIPER ENERGY PARTNERS LP

Viper is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “VNOM”. Viper was formed by Diamondback on February 27, 2014, to, among other things, own, acquire and exploit oil and natural gas properties in North America. Viper is currently focused on owning and acquiring mineral interests and royalty interests in oil and natural gas properties in the Permian Basin and the Eagle Ford Shale. Viper Energy Partners GP LLC, a fully-consolidated subsidiary of Diamondback, serves as the general partner of Viper. As of March 31, 2020, the Company owned approximately 58% of Viper’s total units outstanding.

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Partnership Agreement

The second amended and restated agreement of limited partnership, dated as of May 9, 2018, as amended as of May 10, 2018 (the “Viper Partnership Agreement”), requires Viper to reimburse Viper’s General Partner for all direct and indirect expenses incurred or paid on Viper’s behalf and all other expenses allocable to Viper or otherwise incurred by Viper’s General Partner in connection with operating Viper’s business. The Viper Partnership Agreement does not set a limit on the amount of expenses for which Viper’s General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for Viper or on its behalf and expenses allocated to Viper’s General Partner by its affiliates. Viper’s General Partner is entitled to determine the expenses that are allocable to Viper. For each of the three months ended March 31, 2020 and 2019, Viper’s General Partner allocated $1 million to Viper.

Tax Sharing

In connection with the closing of the Viper Offering, Viper entered into a tax sharing agreement with Diamondback, dated June 23, 2014, pursuant to which Viper agreed to reimburse Diamondback for its share of state and local income and other taxes for which Viper’s results are included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on June 23, 2014. The amount of any such reimbursement is limited to the tax Viper would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its combined or consolidated group, of which Viper may be a member for this purpose, to owe less or no tax. In such a situation, Viper agreed to reimburse Diamondback for the tax Viper would have owed had the tax attributes not been available or used for Viper’s benefit, even though Diamondback had no cash tax expense for that period. For the three months ended March 31, 2020 and 2019, Viper accrued a minimal amount of state income tax expense for its share of Texas margin tax for which Viper’s results are included in a combined tax return filed by Diamondback.

Viper LLC’s Revolving Credit Facility

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

5. RATTLER MIDSTREAM LP

Rattler is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “RTLR.” Rattler was formed by Diamondback in July 2018 to own, operate, develop and acquire midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. Rattler Midstream GP LLC (“Rattler’s General Partner”), a wholly-owned subsidiary of Diamondback, serves as the general partner of Rattler. As of March 31, 2020, Diamondback owned approximately 71% of Rattler’s total units outstanding.

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

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

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Diamondback has also entered into the following agreements with Rattler:

Rattler’s Partnership Agreement

In connection with the closing of the Rattler Offering, Rattler’s General Partner and Energen Resources Corporation entered into the first amended and restated agreement of limited partnership of Rattler, dated May 28, 2019 (the “Rattler Partnership Agreement”). The Rattler Partnership Agreement requires Rattler to reimburse Rattler’s General Partner for all direct and indirect expenses incurred or paid on Rattler’s behalf and all other expenses allocable to Rattler or otherwise incurred by Rattler’s General Partner in connection with operating Rattler’s business. The Rattler Partnership Agreement does not set a limit on the amount of expenses for which its general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for Rattler or on its behalf and expenses allocated to Rattler’s General Partner by its affiliates. Rattler’s General Partner is entitled to determine the expenses that are allocable to Rattler. For the three months ended March 31, 2020, the General Partner allocated $0.1 million of such expenses to Rattler.

Rattler’s Services and Secondment Agreement

In connection with the closing of the Rattler Offering, Rattler entered into a services and secondment agreement with Diamondback, Diamondback E&P LLC, Rattler’s General Partner and Rattler LLC, dated as of May 28, 2019 (the “Services and Secondment Agreement”). Pursuant to the Services and Secondment Agreement, Diamondback and its subsidiaries second certain operational, construction, design and management employees and contractors of Diamondback to Rattler’s General Partner, Rattler and its subsidiaries, providing management, maintenance and operational functions with respect to Rattler’s assets. The Services and Secondment Agreement requires Rattler’s General Partner and Rattler to reimburse Diamondback for the cost of the seconded employees and contractors, including their wages and benefits. For the three months ended March 31, 2020, Rattler’s General Partner and Rattler paid Diamondback $2 million under the Services and Secondment Agreement.

Rattler’s Tax Sharing Agreement

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

For the three months ended March 31, 2020, Rattler accrued state income tax expense of $0.1 million of Texas margin tax and the portion attributable to Rattler is included in a combined tax return filed by Diamondback.

Other Agreements

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

6. REAL ESTATE ASSETS

The following schedules present the cost and related accumulated depreciation or amortization (as applicable) of the Company’s real estate assets including intangible lease assets:

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Condensed Notes to Consolidated Financial Statements-(Continued)

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	Estimated Useful Lives	March 31, 2020			December 31, 2019
	(Years)	(in millions)
Buildings	20-30	$	102		$	102
Tenant improvements	15	5			5
Land	N/A	2			2
Land improvements	15	1			1
Total real estate assets		110			110
Less: accumulated depreciation		(10		)	(9		)
Total investment in land and buildings, net		$	100		$	101



	Weighted Average Useful Lives	March 31, 2020			December 31, 2019
	(Months)	(in millions)
In-place lease intangibles	45	$	11		$	11
Less: accumulated amortization		(6		)	(6		)
In-place lease intangibles, net		5			5

Above-market lease intangibles	45	3			4
Less: accumulated amortization		(1		)	(1		)
Above-market lease intangibles, net		2			3
Total intangible lease assets, net		$	7		$	8

7. PROPERTY AND EQUIPMENT

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

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Condensed Notes to Consolidated Financial Statements-(Continued)

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	March 31,			December 31,
	2020			2019

	(in millions)
Oil and natural gas properties:
Subject to depletion	$	18,231		$	16,575
Not subject to depletion	8,488			9,207
Gross oil and natural gas properties	26,719			25,782
Accumulated depletion	(3,387		)	(2,995		)
Accumulated impairment	(2,943		)	(1,934		)
Oil and natural gas properties, net	20,389			20,853
Midstream assets	987			931
Other property, equipment and land	130			125
Accumulated depreciation	(86		)	(74		)
Total property and equipment, net	$	21,420		$	21,835

Balance of costs not subject to depletion:
Incurred in 2020	$	59
Incurred in 2019	604
Incurred in 2018	5,398
Incurred in 2017	2,124
Incurred in 2016	303
Total not subject to depletion	$	8,488

The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. Costs, including related employee costs, associated with production and operation of the properties are charged to expense as incurred. All other internal costs not directly associated with exploration and development activities are charged to expense as they are incurred. Capitalized internal costs were approximately $14 million and $13 million for the three months ended March 31, 2020 and 2019, respectively. Costs associated with unevaluated properties are excluded from the full cost pool until the Company has made a determination as to the existence of proved reserves. The inclusion of the Company’s unevaluated costs into the amortization base is expected to be completed within five years. Acquisition costs not currently being amortized are primarily related to unproved acreage that the Company plans to prove up through drilling. The Company has no plans to let any of the acreage, associated with acquisition costs not currently being amortized, expire based on current drilling plans. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas.

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

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and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required.

As a result of the sharp decline in commodity prices during the first quarter of 2020, the Company recorded a non-cash ceiling test impairment for the three months ended March 31, 2020 of $1.0 billion which was included in accumulated depletion. The impairment charge affected the Company’s results of operations but did not reduce its cash flow. In addition to commodity prices, the Company’s production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine its actual ceiling test calculation and impairment analysis in future periods. If the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters, the Company will have material write downs in subsequent quarters. No impairment on proved oil and natural gas properties was recorded for the three months ended March 31, 2019.

The Company evaluates its long-lived assets (primarily comprised of midstream assets) for potential impairment whenever events or circumstances indicate it is more likely than not that the carrying amount of the asset, or set of assets, is greater than the fair value. An impairment involves comparing the estimated future undiscounted cash flows of an asset or set of assets with the carrying amount. If the carrying amount of the asset or set of assets exceeds the estimated undiscounted cash flows, then an impairment charge is recorded for the difference between the estimated fair value of the asset or set of assets and its carrying value. Given the rate of change impacting the oil and gas industry described above, it is possible that circumstances requiring additional impairment testing will occur in future interim periods, which could result in potentially material impairment charges being recorded.

At March 31, 2020, $228 million in exploration costs and development costs and $111 million in capitalized interest was not subject to depletion. At December 31, 2019, $228 million in exploration costs and development costs and $118 million in capitalized interest was not subject to depletion.

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8. 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,
	2020		2019

	(in millions)
Asset retirement obligations, beginning of period	$	94	$	136
Additional liabilities incurred	4		1
Liabilities acquired	—		3
Liabilities settled	—		(2		)
Accretion expense	2		2
Revisions in estimated liabilities	—		—
Asset retirement obligations, end of period	100		140
Less current portion	1		—
Asset retirement obligations - long-term	$	99	$	140

The Company’s asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The Company estimates the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance. The current portion of the asset retirement obligation liability is included in other accrued liabilities in the Company’s consolidated balance sheets.

9. 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, 2020		December 31, 2019
			(in millions)
EPIC Crude Holdings, LP	10	%	$	117	$	109
Gray Oak Pipeline, LLC	10	%	122		116
Wink to Webster Pipeline LLC	4	%	45		34
OMOG JV LLC	60	%	216		219
Amarillo Rattler, LLC	50	%	2		1
			$	502	$	479

Income (loss) from equity method investees was not material for the three months ended March 31, 2020 or 2019.

On February 1, 2019, Rattler LLC acquired a 10% equity interest in EPIC Crude Holdings, LP (“EPIC”), which owns and operates a pipeline (the “EPIC pipeline”) that transports crude and NGL across Texas for delivery into the Corpus Christi market. The EPIC pipeline became fully operational in April 2020.

On February 15, 2019, Rattler LLC acquired a 10% equity interest in Gray Oak Pipeline, LLC (“Gray Oak”), which owns and operates a pipeline (the “Gray Oak pipeline”) that transports crude from the Permian to Corpus Christi on the Texas Gulf Coast. The Gray Oak pipeline became fully operational in April 2020.

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On March 29, 2019, Rattler LLC executed a short-term promissory note to Gray Oak. The note allows for borrowing by Gray Oak of up to $123 million at 2.52% interest rate with a maturity date of March 31, 2022. The short-term promissory note was repaid on May 31, 2019. During the three months ended March 31, 2020, there were no borrowings or repayments under this note. There were no outstanding loans at March 31, 2020.

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

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

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

On December 20, 2019, Rattler LLC acquired a 50% equity interest in Amarillo Rattler, LLC, which currently owns and operates the Yellow Rose gas gathering and processing system with estimated total processing capacity of 40,000 Mcf/d and over 84 miles of gathering and regional transportation pipelines in Dawson, Martin and Andrews Counties, Texas. This joint venture also intends to construct and operate a new 60,000 Mcf/d cryogenic natural gas processing plant in Martin County, Texas as well as incremental gas gathering and compression and regional transportation pipelines. Although Rattler’s equity interest is 50%, the investment is accounted for as an equity method investment as Rattler does not control operating activities and substantive participating rights exist with the controlling investor.

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. No impairments were recorded for Rattler’s equity method investments for the three months ended March 31, 2020 or 2019. Rattler’s investees all serve customers in the oil and gas industry, which has begun to experience 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.

During the three months ended March 31, 2020, $0.3 million of capitalized interest was related to equity method investments that have not yet begun operations. There was no capitalized interest during the three months ended March 31, 2019.

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10. DEBT

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



	March 31,			December 31,
	2020			2019

	(in millions)
4.625% Notes due 2021	$	400		$	399
7.320% Medium-term Notes, Series A, due 2022	20			21
2.875% Senior Notes due 2024	1,000			1,000
5.375% Senior Notes due 2025	800			800
3.250% Senior Notes due 2026	800			800
7.350% Medium-term Notes, Series A, due 2027	10			11
7.125% Medium-term Notes, Series B, due 2028	100			108
3.500% Senior Notes due 2029	1,200			1,200
DrillCo Agreement	55			39
Unamortized debt issuance costs	(19		)	(19		)
Unamortized discount costs	(31		)	(31		)
Unamortized premium costs	18			9
Revolving credit facility	199			13
Viper revolving credit facility	174			97
Viper 5.375% Senior Notes due 2027	500			500
Rattler revolving credit facility	451			424
Total long-term debt	$	5,677		$	5,371

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

Diamondback Notes

2025 Senior Notes

On December 20, 2016, Diamondback Energy, Inc. issued $500 million in aggregate principal amount of 5.375% senior notes due 2025 (the “existing 2025 notes”), under an indenture among us, the subsidiary guarantors party thereto and Wells Fargo, as the trustee (the “2025 indenture”). On January 29, 2018, Diamondback Energy, Inc. issued $300 million aggregate principal amount of new 5.375% senior notes due 2025 as additional notes under the 2025 indenture (the “new 2025 notes” and, together with the existing 2025 notes, the 2025 senior notes).

The 2025 senior notes bear interest at a rate of 5.375% per annum, payable semi-annually, in arrears on May 31 and November 30 of each year and will mature on May 31, 2025. Diamondback Energy, Inc.’s existing and future restricted subsidiaries that guarantee this revolving credit facility also guarantee the 2025 senior notes. The 2025 senior notes are not and will not be guaranteed by any of Diamondback Energy, Inc.’s unrestricted subsidiaries. Currently, the 2025 senior notes are not guaranteed by any of the Company’s subsidiaries other than Diamondback O&G LLC.

The Company may on any one or more occasions redeem some or all of the 2025 senior notes at any time on or after May 31, 2020 at the redemption prices (expressed as percentages of principal amount) of 104.031% for the 12-month period beginning on May 31, 2020, 102.688% for the 12-month period beginning on May 31, 2021, 101.344% for the 12-month period beginning on May 31, 2022 and 100.000% beginning on May 31, 2023 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to May 31, 2020, the Company may on any one or more occasions redeem all or a portion of the 2025 senior notes at a price equal to 100% of the principal amount of the 2025 senior notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to May 31, 2020, the Company may on any one or more occasions redeem

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the 2025 senior notes in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2025 senior notes issued prior to such date at a redemption price of 105.375%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings.

The 2025 indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit Diamondback Energy, Inc.’s ability and the ability of its restricted subsidiaries to incur or guarantee additional indebtedness or issue certain redeemable or preferred equity, make certain investments, declare or pay dividends or make distributions on equity interests or redeem, repurchase or retire equity interests or subordinated indebtedness, transfer or sell assets, agree to payment restrictions affecting its restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens and designate certain of its subsidiaries as unrestricted subsidiaries. These covenants are subject to numerous exceptions, some of which are material. Certain of these covenants are subject to termination upon the occurrence of certain events.

December 2019 Notes Offering

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

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

The Company may redeem (i) the 2024 notes in whole or in part at any time prior to November 1, 2024 (one month prior to the maturity date of the 2024 notes), (ii) the 2026 notes in whole or in part at any time prior to October 1, 2026 (two months prior to the maturity date of the 2026 notes) and (iii) the 2029 notes in whole or in part at any time prior to September 1, 2029 (three months prior to the maturity date of the 2029 notes) (each such date, a “par call date”), in each case at a redemption price equal to 100% of the principal amount of such notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. If the December 2019 Notes are redeemed on or after their respective par call dates, in each case, such December 2019 Notes will be redeemed at a redemption price equal to 100% of the principal amount of the December 2019 Notes to be redeemed plus interest accrued thereon to but not including the redemption date.

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

The December 2019 Notes Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit Diamondback Energy, Inc.’s ability and the ability of certain of its subsidiaries to incur liens securing funded indebtedness and on Diamondback Energy, Inc.’s ability to consolidate, merge or sell, convey, transfer or lease all or substantially all of its assets.

Second Amended and Restated Credit Facility

Diamondback O&G LLC, as borrower, and Diamondback Energy, Inc., as parent guarantor, entered into the second amended and restated credit agreement, dated November 1, 2013, as amended, with a syndicate of banks, including Wells Fargo, as administrative agent, and its affiliate Wells Fargo Securities, LLC, as sole book runner and lead arranger. On June 28, 2019, the credit agreement was amended pursuant to an eleventh amendment, which implemented certain changes to the credit facility for the period on and after the date on which our unsecured debt achieves an investment grade rating from two rating agencies and certain other conditions in the credit agreement are satisfied, which changes became effective on November 20, 2019. As of March 31, 2020, the maximum credit amount

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available under the credit agreement is $2.0 billion. As of March 31, 2020, Diamondback Energy, Inc. had approximately $199 million of outstanding borrowings under its revolving credit facility and $1.8 billion available for future borrowings under the revolving credit facility. The next regularly scheduled annual redetermination of the borrowing base is scheduled for the fall of 2020.

Diamondback O&G LLC is the borrower under the credit agreement, and, as of March 31, 2020, the credit agreement is guaranteed by Diamondback Energy, Inc. None of Diamondback Energy, Inc.’s other subsidiaries are guarantors under the revolving credit facility.

The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by us that is equal to the alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5%, and 3 month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin 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 pricing level, which in turn depends on the rating agencies’ ratings of our unsecured debt. We are obligated to pay a quarterly commitment fee ranging from 0.125% to 0.350% per year on the unused portion of the commitment, based on the pricing level, which in turn depends on the rating agencies’ ratings of our unsecured debt.

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

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

As of March 31, 2020 and December 31, 2019, the Company was in compliance with all financial covenants under the revolving credit facility, as then in effect. The lenders may accelerate all of the indebtedness under the revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control.

Energen’s Notes

At the effective time of the merger with Energen, Energen became Diamondback Energy, Inc.’s wholly owned subsidiary and remained the issuer of an aggregate principal amount of $530 million in notes (the “Energen Notes”), issued under an indenture dated September 1, 1996 with The Bank of New York as Trustee (the “Energen Indenture”). As of March 31, 2020, the Energen Notes consist of: (1) $400 million aggregate principal amount of 4.625% senior notes due on September 1, 2021, (2) $100 million of 7.125% notes due on February 15, 2028, (3) $20 million of 7.32% notes due on July 28, 2022, and (4) $10 million of 7.35% notes due on July 28, 2027.

The Energen Notes are the senior unsecured obligations of Energen and, post-merger, Energen, as a wholly owned subsidiary, continues to be the sole issuer and obligor under the Energen Notes. The Energen Notes rank equally in right of payment with all other senior unsecured indebtedness of Energen if any, and are effectively subordinated to Energen’s senior secured indebtedness, if any, to the extent of the value of the collateral securing such indebtedness. Neither we nor any of our subsidiaries guarantee the Energen Notes.

The Energen Indenture contains certain covenants that, subject to certain exceptions and qualifications, limit Energen’s ability to incur or suffer to exist liens, to enter into sale and leaseback transactions, to consolidate with or merge into any other entity, and to convey, transfer or lease its properties and assets substantially as an entirety to any person or entity.

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(Unaudited)

Viper’s Credit Agreement

On July 20, 2018, Viper LLC, as borrower, entered into an amended and restated credit agreement with Viper, as guarantor, Wells Fargo, as administrative agent, and the other lenders. The credit agreement, as amended (the “Viper credit agreement”), provides for a revolving credit facility in the maximum credit amount of $2 billion and a borrowing base based on Viper LLC’s oil and natural gas reserves and other factors (the “borrowing base”) of $775 million, subject to scheduled semi-annual and other elective borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and November 1st. In addition, Viper LLC and Wells Fargo each may request up to three interim redeterminations of the borrowing base during any 12-month period. As of March 31, 2020, the borrowing base was set at $775 million, and Viper LLC had $174 million of outstanding borrowings and $601 million available for future borrowings under the Viper credit agreement. In connection with the regularly scheduled (semi-annual) spring 2020 redetermination, the administrative agent under the Viper credit agreement has recommended that the borrowing base be decreased under the Viper credit agreement to $580 million effective mid-May 2020. The decrease is subject to approval by the requisite lenders under the Viper credit agreement. Under the new expected borrowing base, Viper LLC would have had $407 million of availability for future borrowings under the Viper credit agreement as of March 31, 2020. Neither Diamondback Energy, Inc. nor any of its other subsidiaries guarantee the Viper credit agreement.

The outstanding borrowings under the Viper credit agreement bear interest at a per annum rate elected by Viper LLC that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.75% to 1.75% per annum in the case of the alternate base rate and from 1.75% to 2.75% per annum in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the lesser of the maximum credit amount and the borrowing base. Viper LLC is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally prepaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (i) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (ii) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (iii) at the maturity date of November 1, 2022. The loan is secured by substantially all of the assets of Viper and Viper LLC.

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



Financial Covenant	Required Ratio
Ratio of total net debt to EBITDAX, as defined in the Viper credit agreement	Not greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined the Viper credit agreement	Not less than 1.0 to 1.0

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $1.0 billion in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. The covenant limiting dividends and distributions includes an exception allowing Viper LLC to make distributions if no default, event of default or borrowing base deficiency exists.

As of March 31, 2020 and December 31, 2019, Viper and Viper LLC were in compliance with all financial maintenance covenants under the Viper credit agreement, as then in effect. The lenders may accelerate all of the indebtedness under the Viper credit agreement upon the occurrence and during the continuance of any event of default. The Viper credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control.

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Viper’s Notes

On October 16, 2019, Viper completed an offering in which it issued its 5.375% Senior Notes due 2027 in aggregate principal amount of $500 million (the “Viper Notes”). Viper received gross proceeds of $500 million from the such offering, which it loaned to Viper LLC.

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

Viper LLC guarantees the Viper Notes pursuant to the Viper Indenture. Neither Diamondback Energy, Inc. nor any of its other subsidiaries guarantee the Viper Notes.

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

Rattler’s Credit Agreement

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

The Rattler credit agreement provides for a revolving credit facility in the maximum credit amount of $600 million. Loan principal may be optionally prepaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid at the maturity date of May 28, 2024. The Rattler credit agreement is guaranteed by Rattler, Tall City, Rattler OMOG LLC and Rattler Ajax Processing LLC and is secured by substantially all of the assets of Rattler LLC and the guarantors. As of March 31, 2020, Rattler LLC had $451 million of outstanding borrowings and $149 million available for future borrowings under the Rattler credit agreement.

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

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

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(Unaudited)

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



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

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

As of March 31, 2020 and December 31, 2019, Rattler and Rattler LLC were in compliance with all financial maintenance covenants under the Rattler credit agreement. The lenders may accelerate all of the indebtedness under the Rattler credit agreement upon the occurrence and during the continuance of any event of default. The Rattler credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change in control.

Alliance with Obsidian Resources, L.L.C.

Diamondback O&G LLC entered into a participation and development agreement (the “DrillCo Agreement”), dated September 10, 2018, with Obsidian Resources, L.L.C. (“CEMOF”) to fund oil and natural gas development. Funds managed by CEMOF and its affiliates have agreed to commit to funding certain costs out of CEMOF’s net production revenue and, for a period of time, to the extent not funded by such revenue, up to an additional $300 million, to fund drilling programs on locations provided by the Company. Subject to adjustments depending on asset characteristics and return expectations of the selected drilling plan, CEMOF will fund up to 85% of the costs associated with new wells drilled under the DrillCo Agreement and is expected to receive an 80% working interest in these wells until it reaches certain payout thresholds equal to a cumulative 9% and then 13% internal rate of return. Upon reaching the final internal rate of return target, CEMOF’s interest will be reduced to 15%, while the Company’s interest will increase to 85%. As of March 31, 2020 and December 31, 2019, CEMOF’s return related to this alliance was $55 million and $39 million, respectively. As of March 31, 2020, thirteen joint wells have been drilled and completed.

11. CAPITAL STOCK AND EARNINGS PER SHARE

Diamondback did not complete any equity offerings during the three months ended March 31, 2020 and March 31, 2019.

Rattler’s Initial Public Offering

Please see Note 5—Rattler Midstream LP for information regarding the Rattler Offering.

Stock Repurchase Program

In May 2019, the Company’s board of directors approved a stock repurchase program to acquire up to $2 billion of the Company’s outstanding common stock through December 31, 2020. Purchases under the repurchase program may be made from time to time in open market or privately negotiated transactions, and are subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program does not require the Company to acquire any specific number of shares. This repurchase program may be suspended from time to time, modified, extended or discontinued by the board of directors at any time. During the three months ended

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March 31, 2020, the Company repurchased approximately $98 million of common stock under this repurchase program. As of March 31, 2020, $1.3 billion remained available for use to repurchase shares under the Company's common stock repurchase program, although the Company has suspended this program to preserve liquidity.

Earnings Per Share

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

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



	Three Months Ended March 31,
	2020			2019
	($ in millions, except per share amounts, shares in thousands)
Net (loss) income attributable to common stock	$	(272	)	$	10
Weighted average common shares outstanding:
Basic weighted average common units outstanding	158,291			164,852
Effect of dilutive securities:
Potential common shares issuable	203			209
Diluted weighted average common shares outstanding	158,494			165,061
Basic net (loss) income attributable to common stock	$	(1.72	)	$	0.06
Diluted net (loss) income attributable to common stock	$	(1.72	)	$	0.06

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



	Three Months Ended March 31,
	2020	2019
	(in thousands)
Restricted stock units	318	31

12. EQUITY-BASED COMPENSATION

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



	Three Months Ended March 31,
	2020		2019
	(in millions)
General and administrative expenses	$	9	$	14
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties	6		6

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Restricted Stock Units

The following table presents the Company’s restricted stock units activity under the Equity Plan during the three months ended March 31, 2020:



	Restricted Stock Awards & Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2019	505,867		$	96.01
Granted	159,116		$	62.82
Vested	(104,640	)	$	80.75
Forfeited	(13,610	)	$	99.72
Unvested at March 31, 2020	546,733		$	89.18

The aggregate fair value of restricted stock units that vested during the three months ended March 31, 2020 and 2019 was $8 million and $13 million, respectively. As of March 31, 2020, the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $38 million. Such cost is expected to be recognized over a weighted-average period of 2.1 years.

During the three months ended March 31, 2020, the Company modified certain of the restricted stock units to include dividend equivalent rights during the vesting period. This modification effected 765 awards and resulted in no incremental compensation costs to be recognized.

Performance Based Restricted Stock Units

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

In March 2020, eligible employees received performance restricted stock unit awards totaling 225,047 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2020 to December 31, 2022 and cliff vest at December 31, 2022.

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

The following table presents a summary of the grant-date fair values of performance restricted stock units granted and the related assumptions for the March 2020 awards.



	2020
Grant-date fair value	$	70.17
Risk-free rate	0.86		%
Company volatility	36.70		%

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The following table presents the Company’s performance restricted stock units activity under the Equity Plan for the three months ended March 31, 2020:



	Performance Restricted Stock Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2019	271,819		$	147.07
Granted	272,601		$	85.73
Vested	(47,554	)	$	89.27
Forfeited	(8,396	)	$	170.45
Unvested at March 31, 2020⁽¹⁾	488,470		$	110.33


(1)	A maximum of 976,940 units could be awarded based upon the Company’s final TSR ranking.

As of March 31, 2020, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $35 million. Such cost is expected to be recognized over a weighted-average period of 2.5 years.

Stock Appreciation Rights

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

The following table presents a summary of stock appreciation rights activity during the three months ended March 31, 2020:



	Shares		Weighted Average Exercise Price
Outstanding at December 31, 2019	42,547		$	90.89
Exercised	(4,213	)	$	72.67
Expired	(970	)	$	72.48
Outstanding at March 31, 2020	37,364		$	93.42

Stock Options

In connection with the Energen Merger, each option to purchase shares of Energen common stock that was outstanding immediately prior to the effective time of the Merger was converted into a fully vested option to purchase such number of whole shares of Diamondback common stock (rounded down to the nearest whole share) equal to the product of (A) the total number of shares of Energen common stock subject to such option immediately prior to the effective time of the Merger multiplied by (B) the exchange ratio, at an exercise price per share of Diamondback common stock (rounded up to the nearest whole cent) equal to the quotient of (A) the exercise price per share of Energen common stock of such option immediately prior to the effective time of the Merger divided by (B) the exchange ratio. The exercise price of stock options granted may not be less than the market value of the stock at the date of grant.

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Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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



			Weighted Average
			Exercise		Remaining	Intrinsic
	Options		Price		Term	Value
					(in years)	(in millions)
Outstanding at December 31, 2019	216,343		$	89.90
Exercised	(11,338	)	$	72.48
Outstanding at March 31, 2020	205,005		$	91.58	1.51	$	—

Vested and Expected to vest at March 31, 2020	205,005		$	91.58	1.51	$	—
Exercisable at March 31, 2020	205,005		$	91.58	1.51	$	—

Viper Phantom Units

Under the Viper Energy Partners LP Long Term Incentive Plan (“Viper LTIP”), the Board of Directors of the General Partner is authorized to issue phantom units to eligible employees. Viper estimates the fair value of phantom units as the closing price of Viper’s common units on the grant date of the award, which is expensed over the applicable vesting period. Upon vesting the phantom units entitle the recipient one common unit of Viper for each phantom unit.

The following table presents the phantom unit activity under the Viper LTIP for the three months ended March 31, 2020:



	Phantom Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2019	95,248		$	26.87
Vested	(42,814	)	$	23.24
Unvested at March 31, 2020	52,434		$	29.83

The aggregate fair value of phantom units that vested during the three months ended March 31, 2020 was $1 million. As of March 31, 2020, the unrecognized compensation cost related to unvested phantom units was $1 million. Such cost is expected to be recognized over a weighted-average period of 1.4 years.

During the three months ended March 31, 2020, the Partnership modified certain of the Phantom Units to include distribution equivalent rights during the vesting period. This modification effected 21 awards and resulted in no incremental compensation costs to be recognized.

Rattler Long-Term Incentive Plan

On May 22, 2019, the board of directors of Rattler’s General Partner adopted the Rattler Midstream LP Long Term Incentive Plan (“Rattler LTIP”), for employees, consultants and directors of Rattler’s General Partner and any of its affiliates, including Diamondback, who perform services for Rattler. The Rattler LTIP provides for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards.

Under the Rattler LTIP, the board of directors of Rattler’s General Partner is authorized to issue phantom units to eligible employees and non-employee directors. Rattler estimates the fair value of phantom units as the closing price of Rattler’s common units on the grant date of the award, which is expensed over the applicable vesting period. Upon vesting the phantom units entitle the recipient to one common unit of Rattler for each phantom unit. The recipients are

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(Unaudited)

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, 2020:



	Phantom Units		Weighted Average Grant-Date Fair Value
Unvested at December 31, 2019	2,226,895		$	19.14
Granted	20,910		$	13.85
Forfeited	(569	)	$	15.57
Unvested at March 31, 2020	2,247,236		$	19.09

As of March 31, 2020, the unrecognized compensation cost related to unvested phantom units was $36 million. Such cost is expected to be recognized over a weighted-average period of 4.1 years.

13. RELATED PARTY TRANSACTIONS

Lease Bonus - Viper

During the three months ended March 31, 2020, the Company paid Viper $0.3 million in lease bonus payments to extend the term of one lease and $1.3 million in lease bonus payments for one new lease. During the three months ended March 31, 2019, the Company’s lease bonus payments to Viper were immaterial.

Rattler Offering

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

14. INCOME TAXES

The Company’s effective income tax rates were (26.1)% and (301.7)% for the three months ended March 31, 2020 and 2019, respectively. 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 consist 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 projected 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 negative evidence including Viper’s recent cumulative losses projected for the year ending December 31, 2020, and 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.

Total income tax expense for the three months ended March 31, 2019 differed from amounts computed by applying the federal statutory rate to pre-tax income primarily due to (i) the revision of estimated deferred taxes recognized by Viper as a result of its change in tax status, (ii) state income taxes and (iii) the impact of permanent differences between book and taxable income. Based on information available as of March 31, 2019 regarding

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(Unaudited)

unitholders’ tax basis, Viper revised its estimate of deferred taxes on Viper’s investment in Viper LLC on the date of the tax status change, resulting in discrete deferred tax benefit of $35 million for the three months ended March 31, 2019.

The CARES Act was enacted on March 27, 2020. This legislation included a number of provisions applicable to U.S. income taxes for corporations, including providing for carryback of certain net operating losses, accelerated refund of minimum tax credits, and modifications to the rules limiting the deductibility of business interest expense. The Company has considered the impact of this legislation in the period of enactment, resulting in discrete income tax benefit for the three months ended March 31, 2020 related to the anticipated 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’s current federal taxes receivable total approximately $101 million as of March 31, 2020.

As discussed further in Note 5, on May 28, 2019, Rattler completed its initial public offering. Even though Rattler is organized as a limited partnership under state law, Rattler is subject to U.S. federal and state income tax at corporate rates, subsequent to the effective date of Rattler’s election to be treated as a corporation for U.S. federal income tax purposes. As such, Rattler’s provision for income taxes is included in the Company’s consolidated financial statements and to the extent applicable, in net income attributable to the non-controlling interest.

15. DERIVATIVES

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

Diamondback Commodity Contracts

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

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

The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing (Cushing and Magellan East Houston) and ICE Brent pricing, and with natural gas derivative settlements based on the New York Mercantile Exchange Henry Hub and Waha Hub pricing, liquids derivative settlements based on Mt. Belvieu pricing and diesel fuel settlements based on Gulf Coast ultra low sulfur diesel pricing.

By using derivative instruments to economically hedge exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are participants in the secured second amended and restated

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(Unaudited)

credit agreement, which is secured by substantially all of the assets of the guarantor subsidiaries; therefore, the Company is not required to post any collateral. The Company does not require collateral from its counterparties. The Company has entered into derivative instruments only with counterparties that are also lenders in our credit facility and have been deemed an acceptable credit risk.

As of March 31, 2020, the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.



	2020				2021
	Volume (Bbls/MMBtu/Gallons)	Fixed Price Swap (per Bbl/MMBtu/Gallon)			Volume (Bbls/MMBtu/Gallons)	Fixed Price Swap (per Bbl/MMBtu/Gallon)
Oil Swaps - WTI Cushing	3,114,000	$	46.33		—	$	—
Oil Swaps - WTI Magellan East Houston	1,100,000	$	61.95		1,825,000	$	37.78
Oil Swaps - BRENT	7,292,000	$	48.80		3,816,000	$	43.26
Oil Swaption - BRENT	—	$	—		2,024,000	$	44.77
Oil Basis Swaps - WTI Cushing	11,125,000	$	(1.21	)	—	$	—
Oil Rolling Hedge - WTI Cushing	5,500,000	$	0.44		—	$	—
Natural Gas Swaps - Henry Hub	8,190,000	$	2.55		14,600,000	$	2.47
Natural Gas Swaps - Waha Hub	16,500,000	$	1.51		—	$	—
Natural Gas Basis Swaps - Waha Hub	33,000,000	$	(1.46	)	62,050,000	$	(0.71	)
Diesel Price Swaps	275,000,000	$	1.60		—	$	—



Oil Swaption - WTI Magellan East Houston	2020
Volume (Bbl)	2,750,000
Swap price (per Bbl)	$	55.00
Put price (per Bbl)	$	40.00



Oil Options - WTI Cushing	2020
Volume (Bbl)	1,292,500
Long Put Price (per Bbl)	$	46.51



Oil Put Spread - WTI Magellan East Houston	2020
Volume (Bbl)	1,045,000
Floor price (per Bbl)	$	50.00
Short Put price (per Bbl)	$	25.00



Gas Swap Double-Up - Waha Hub	2020
Volume (Mcf)	8,250,000
Swap price (per Mcf)	$	1.70
Option price (per Mcf)	$	1.70

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Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)



	2020						2021
Oil Costless Collars	WTI Cushing		Brent		WTI Magellan East Houston		Brent
Volume (Bbls)	10,182,975		17,750,750		1,092,000		21,717,500
Floor price (per Bbl)	$	38.10	$	37.64	$	39.00	$	39.45
Ceiling price (per Bbl)	$	45.02	$	46.66	$	49.00	$	48.16

Interest Rate Swaps and Treasury Locks

The Company has used interest rate swaps and treasury locks to reduce the Company’s exposure to variable rate interest payments associated with the Company’s revolving credit facility. The interest rate swaps and treasury locks have not been designated as hedging instruments and as a result, the Company recognizes all changes in fair value immediately in earnings.

The following table summarizes the Company’s interest rate swaps and treasury locks as of March 31, 2020:



Type	Effective Date	Termination Date	Notional Amount (in millions)		Interest Rate
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.551	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.5575	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.297	%
Interest Rate Swap	December 31, 2020	December 31, 2030	$	250	1.195	%

Viper Commodity Contracts

Viper uses fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options to reduce price volatility associated with certain of its royalty income. With respect to Viper’s fixed price swap contracts and fixed price basis swap contracts, the counterparty is required to make a payment to Viper if the settlement price for any settlement period is less than the swap or basis price, and Viper is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap or basis price. Viper has fixed price basis swaps for the spread between the Cushing crude oil price and the Midland crude oil price as well as the spread between the Henry Hub natural gas price and the Waha Hub natural gas price.

Under Viper’s costless collar contracts, each collar has an established floor price and ceiling price. When the settlement price is below the floor price, the counterparty is required to make a payment to Viper and when the settlement price is above the ceiling price, Viper is required to make a payment to the counterparty. When the settlement price is between the floor and the ceiling, there is no payment required.

Viper’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing (Cushing and Midland-Cushing) and with natural gas derivative settlements based on the New York Mercantile Exchange Henry Hub and Waha Hub pricing.

By using derivative instruments to economically hedge exposure to changes in commodity prices, Viper 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 Viper, which creates credit risk. Viper’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, Viper is not required to post any collateral. Viper does not require collateral from its counterparties. Viper has entered into derivative instruments only with counterparties that are also lenders in our 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, 2020, Viper had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.



	2020
Swaps	Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)
Oil Swaps - WTI Cushing	275,000	$	27.45
Oil Basis Swaps - WTI (Midland-Cushing)	1,100,000	$	(2.60	)
Natural Gas Basis Swaps - Waha Hub	6,875,000	$	(2.07	)



Collars - WTI (Cushing)	2020		2021
Volume (Bbls)	3,850,000		3,650,000
Floor price (per Bbl)	$	28.86	$	30.00
Ceiling price (per Bbl)	$	32.33	$	43.05

Balance sheet offsetting of derivative assets and liabilities

The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions that are with the same counterparty and are subject to contractual terms which provide for net settlement.

The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under master netting arrangements with counterparties and the resulting net amounts presented in the Company’s consolidated balance sheets as of March 31, 2020 and December 31, 2019:



	March 31, 2020			December 31, 2019
	(in millions)
Gross amounts of assets presented in the Consolidated Balance Sheet	$	818		$	71
Amounts netted in the Consolidated Balance Sheet	(254		)	(18		)
Net amounts of assets presented in the Consolidated Balance Sheet	$	564		$	53

Gross amounts of liabilities presented in the Consolidated Balance Sheet	$	336		$	45
Amounts netted in the Consolidated Balance Sheet	(254		)	(18		)
Net amounts of liabilities presented in the Consolidated Balance Sheet	$	82		$	27

The net amounts are classified as current or noncurrent based on their anticipated settlement dates. The net fair value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:



	March 31, 2020		December 31, 2019
	(in millions)
Current assets: derivative instruments	$	534	$	46
Noncurrent assets: derivative instruments	30		7
Total assets	$	564	$	53
Current liabilities: derivative instruments	$	16	$	27
Noncurrent liabilities: derivative instruments	66		—
Total liabilities	$	82	$	27

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Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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



	Three Months Ended March 31,
	2020			2019
	(in millions)
Change in fair value of open non-hedge derivative instruments
Commodity contracts	$	517		$	(285	)
Interest rate swaps	(62		)	—
Total	$	455		$	(285	)

Gain on settlement of non-hedge derivative instruments
Commodity contracts	87			17
Total	$	87		$	17

Gain (loss) on derivative instruments, net	$	542		$	(268	)

16. FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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

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Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s derivative instruments and Viper’s cost method investment. The fair value of Viper’s investment is determined using quoted market prices. These valuations are Level 1 inputs. The fair values of the Company’s fixed price swaps, fixed price basis swaps and costless collars are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs.

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of March 31, 2020 and December 31, 2019:



	March 31, 2020						December 31, 2019
	Level 1		Level 2		Level 3		Level 1		Level 2		Level 3
	(in millions)
Assets:
Investment	$	9	$	—	$	—	$	19	$	—	$	—
Derivative Instruments	—		564		—		—		53		—
Liabilities:
Derivative Instruments	$	—	$	82	$	—	$	—	$	27	$	—

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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 consolidated balance sheets:



	March 31, 2020				December 31, 2019
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
	(in millions)
Debt:
Revolving credit facility	$	199	$	199	$	13	$	13
4.625% Notes due 2021	$	399	$	369	$	399	$	411
7.320% Medium-term Notes, Series A, due 2022	$	21	$	19	$	21	$	22
2.875% Senior Notes due 2024⁽¹⁾	$	992	$	720	$	992	$	1,012
5.375% Senior Notes due 2025⁽¹⁾	$	799	$	587	$	799	$	840
3.250% Senior Notes due 2026⁽¹⁾	$	792	$	568	$	792	$	812
7.350% Medium-term Notes, Series A, due 2027	$	11	$	9	$	11	$	12
7.125% Medium-term Notes, Series B, due 2028	$	107	$	67	$	108	$	116
3.500 Senior Notes due 2029⁽¹⁾	$	1,187	$	851	$	1,186	$	1,226
Viper revolving credit facility	$	174	$	174	$	97	$	97
Viper's 5.375% Senior Notes due 2027	$	490	$	420	$	490	$	521
Rattler revolving credit facility	$	451	$	451	$	424	$	424
DrillCo Agreement	$	55	$	55	$	39	$	39


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

The fair value of the revolving credit facility, the Viper credit agreement and the Rattler credit agreement approximates their carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Senior Notes and the Energen Notes was determined using the March 31, 2020 quoted market price, a Level 1 classification in the fair value hierarchy.

17. LEASES

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

The Company adopted ASU 2016-02, ASU 2018-11 and ASU 2019-01 on January 1, 2019 using the optional transition method of adoption. The Company elected a package of practical expedients that together allows an entity to not reassess (i) whether a contract is or contains a lease, (ii) lease classification and (iii) initial direct costs. In addition, the Company elected the following practical expedients: (i) to not reassess certain land easements; (ii) to not apply the recognition requirements under the standard to short-term leases; (iii) to not reassess lease terms on leases entered into prior to the effective date of adoption; and (iv) lessor accounting policy election to exclude lessor costs paid directly by the lessee.

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

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

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(Unaudited)

The following table summarizes operating lease costs for the three months ended March 31, 2020 and 2019:



	Three Months Ended March 31,
	2020		2019
	(in millions)
Operating lease costs	$	5	$	4

For the three months ended March 31, 2020 and 2019, cash paid for operating lease liabilities, and reported in cash flows provided by operating activities on the Company's Statement of Condensed Consolidated Cash Flows, was $5 million and $5 million, respectively. During the three months ended March 31, 2020, the Company recorded an additional $8 million of right-of-use assets in exchange for new lease liabilities.

The operating lease right-of-use assets were reported in other assets and the current and noncurrent portions of the operating lease liabilities were reported in other accrued liabilities and other long-term liabilities, respectively, on the Condensed Consolidated Balance Sheet. As of March 31, 2020, the operating right-of-use assets were $18 million and operating lease liabilities were $18 million, of which $12 million was classified as current. As of March 31, 2020, the weighted average remaining lease term was 1.8 years and the weighted average discount rate was 9.3%.

Schedule of Operating Lease Liability Maturities. The following table summarizes undiscounted cash flows owed by the Company to lessors pursuant to contractual agreements in effect as of March 31, 2020:



	As of March 31, 2020
	(in millions)
2020	$	11
2021	6
2022	3
2023	—
2024	—
Thereafter	—
Total lease payments	20
Less: interest	2
Present value of lease liabilities	$	18

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

18. COMMITMENTS AND CONTINGENCIES

The Company is a party to various legal proceedings, disputes and claims arising in the course of its business, including those that arise from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on the Company, cannot be predicted with certainty, the Company believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Company’s financial condition, cash flows or results of operations. The Company’s assessment is based on information known about the pending matters and its experience in contesting, litigating and settling similar matters. Actual outcomes could differ materially from the Company’s assessment. The Company records reserves for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

19. SUBSEQUENT EVENTS

First Quarter 2020 Dividend Declaration

On May 1, 2020, the Board of Directors of the Company declared a cash dividend for the first quarter of 2020 of $0.3750 per share of common stock, payable on May 21, 2020 to its stockholders of record at the close of business on May 14, 2020.

Viper Credit Agreement

In connection with the regularly scheduled (semi-annual) spring 2020 redetermination, the administrative agent under the Viper Credit Agreement recommended that the borrowing base be decreased under the Viper credit agreement to $580 million effective mid-May 2020. The decrease is subject to approval by the requisite lenders under the Viper credit agreement. Under the new expected borrowing base, Viper LLC would have had $407 million of availability for future borrowings under the Viper credit agreement as of March 31, 2020.

Commodity Contracts

Subsequent to March 31, 2020, the Company entered into new fixed price basis swaps. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on Crude Oil Brent.

The following tables present the derivative contracts entered into by the Company subsequent to March 31, 2020. When aggregating multiple contracts, the weighted average contract price is disclosed.



	March 2020 - December 2020
	Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)
Oil Rolling Hedge - WTI	27,500,000	(1.35		)
Natural Gas Swaps - Henry Hub	5,520,000	$	2.40
Oil Basis Swaps - WTI Midland	1,712,000	$	(1.31	)



	January 2021 - December 2021
	Volume (Bbls/MMBtu)	Fixed Price Swap (per Bbl/MMBtu)
Natural Gas Swaps - Henry Hub	29,200,000	2.62
Natural Gas Swaps - Waha Hub	1,095,000	0.70
Natural Gas Basis Swaps - Waha Hub	10,950,000	(0.56	)



	January 2021 - December 2021
Oil Costless Collar	WTI
Volume (Bbls)	730,000
Floor price (per Bbl)	$	25.00
Ceiling price (per Bbl)	$	38.40

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)

Current Commodity Environment

Oil prices dropped sharply in early March 2020, and then continued to decline reaching levels below zero dollars per barrel. This was a result of multiple factors affecting supply and demand in global oil and natural gas markets, including the announcement of price reductions and production increases by OPEC members and other oil exporting nations and the ongoing COVID-19 pandemic. Oil and natural gas prices are expected to continue to be volatile as a result of the changes in oil and natural gas production, inventories and industry demand, as well as national and international economic performance. The Company cannot predict when prices will improve and stabilize.

20. BUSINESS SEGMENTS

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

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



	Upstream			Midstream Services			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 and amortization	394			13			—			407
Impairment of oil and natural gas properties	1,009			—			—			1,009
(Loss) income from operations	(782		)	61			(81		)	(802		)
Interest expense, net	(45		)	(3		)	—			(48		)
Other income (expense)	489			(3		)	(1		)	485
Provision for income taxes	79			4			—			83
Net (loss) income attributable to non-controlling interest	(128		)	41			(41		)	(128		)
Net (loss) income attributable to Diamondback Energy	(244		)	13			(41		)	(272		)
As of March 31, 2020:
Total assets	$	21,875		$	1,676		$	(165	)	$	23,386

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Diamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)

(Unaudited)



	Upstream			Midstream Services		Eliminations			Total
Three Months Ended March 31, 2019:	(in millions)
Third-party revenues	$	843		$	21	$	—		$	864
Intersegment revenues	—			74		(74		)	—
Total revenues	843			95		(74		)	864
Depreciation, depletion and amortization	312			10		—			322
Income from operations	300			50		(31		)	319
Interest expense, net	(46		)	—		—			(46		)
Other income (expense)	(308		)	—		(1		)	(309		)
Provision for (benefit from) income taxes	(44		)	11		—			(33		)
Net income attributable to non-controlling interest	33			—		—			33
Net income attributable to Diamondback Energy	3			39		(32		)	10
As of December 31, 2019:
Total assets	$	22,125		$	1,636	$	(230	)	$	23,531

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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, 2019. 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 business segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas and (ii) through our publicly-traded subsidiary, Rattler, the midstream operations segment, which is focused on ownership, operation, development and acquisition of the midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin.

2020 Recent Developments

COVID-19 and Recent Collapse in Commodity Prices

On March 11, 2020, the World Health Organization characterized the global outbreak of the novel strain of coronavirus, COVID-19, as a “pandemic.” To limit the spread of COVID-19, governments have taken various actions including the issuance of stay-at-home orders and social distancing guidelines, causing some businesses to suspend operations and a reduction in demand for many products from direct or ultimate customers. Such actions have resulted in a swift and unprecedented reduction in international and U.S. economic activity which, in turn, has adversely affected the demand for oil and natural gas and caused significant volatility and disruption of the financial markets.

In early March 2020, oil prices dropped sharply, and then continued to decline reaching levels below zero dollars per barrel. This was a result of multiple factors affecting supply and demand in global oil and natural gas markets, including the announcement of price reductions and production increases by OPEC members and other exporting nations and the ongoing COVID-19 pandemic. Commodity prices are expected to continue to be volatile as a result of changes in oil and natural gas production, inventories and demand, as well as national and international economic performance. We cannot predict when prices will improve and stabilize.

As a result of the sharp decline in commodity prices during the first quarter of 2020, we recorded a non-cash ceiling test impairment for the three months ended March 31, 2020 of $1.0 billion. The impairment charge adversely affected our results of operations but did not reduce our cash flows. If the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters, we will have material write downs in subsequent quarters. Our production, proved reserves and cash flows will also be adversely impacted. 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.

Our Response to the Commodity Price Volatility and Impact of COVID-19


•	We have taken swift and decisive actions to protect the health and safety of our employees and preserve the strength of our organization during the COVID-19 pandemic and the depressed commodity price markets.


•	We immediately responded to the sharp drop in commodity prices in early March 2020 by ceasing all completion operations for a minimum of one month.


•	We have hedged approximately 100% of our remaining expected 2020 oil production, including basis differentials and a majority of WTI contract exposure and removed all three-way collar hedge exposure to maximize downside protection.


•	We have hedged approximately 50% of our expected 2021 oil production in the form of swaps and two-way collars.

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•	We plan to voluntarily curtail 10% to 15% of our expected May 2020 oil production in areas where we can manage production economically and without the addition of material operating expense, and will continue to monitor whether additional strategic curtailments are warranted in June 2020 and in future periods.


•	We immediately reduced our full year 2020 capital budget by over 40%, while high-grading our operating plan to acreage with the highest returns where we own mineral and royalty interests and have low required midstream or infrastructure expenditures.


•	We plan to average less than one completion crew in the second quarter of 2020 to meet our leasehold obligations and will assess bringing completion crews back to work in the third quarter of 2020 depending on the commodity price environment.


•	We expect to complete less than 10% of our estimated full year 2020 completed gross well count in the second quarter of 2020.


•	We currently are operating 14 drilling rigs and plan to enter the third quarter of 2020 running eight drilling rigs and enter the fourth quarter of 2020 running seven drilling rigs, with the ability to reduce the rig count further should conditions warrant in the fourth quarter of 2020 and into 2021.


•	We have reduced our operating costs by increasing water infrastructure efficiencies and reducing trucking costs.


•	We have reduced flaring to less than 0.5% of net production at the end of the first quarter 2020 from over 1.5% of net production in January 2020.

First Quarter 2020 Highlights


•	We recorded a net loss of $272 million for the first quarter ended March 31, 2020.


•	Our average production was 321.1 MBOE/d), with average oil production up 12% over the first quarter of 2019.


•	We turned 80 gross operated wells to production and had capital expenditures of $790 million during the first quarter of 2020.


•	As of March 31, 2020, we had $1.8 billion of availability for future borrowings under our revolving credit facility and approximately $0.1 billion of cash on hand.


•	Our cash operating costs for the first quarter ended March 31, 2020 were $8.52 per BOE; including cash general and administrative expenses of $0.51 per BOE.


•	On May 1, 2020, our board of directors declared a cash dividend for the first quarter of 2020 of $0.3750 per share of common stock, payable on May 21, 2020 to our stockholders of record at the close of business of May 14, 2020.


•	During the three months ended March 31, 2020, we repurchased approximately $98 million of common stock under our $2 billion repurchase program approved by our board of directors in May 2019 and, as of March 31, 2020, $1.3 billion remained available for future repurchases under this stock repurchase program although we have suspended this program to preserve liquidity.

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 in the Permian Basin and the Eagle Ford Shale and derives royalty income and lease bonus income from such interests.

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As of March 31, 2020, we had approximately 382,404 net acres, which primarily consisted of approximately 200,056 net acres in the Midland Basin and approximately 155,304 net acres in the Delaware Basin. As of December 31, 2019, we had an estimated 12,310 gross horizontal locations that we believe to be economic at $60 per Bbl West Texas Intermediate, or WTI.

The following table sets forth the total number of operated horizontal wells drilled and completed during the three months ended March 31, 2020:



	Three Months Ended March 31, 2020⁽¹⁾
	Drilled		Completed
Area	Gross	Net	Gross	Net
Midland Basin	55	50	34	30
Delaware Basin	38	35	46	42
Total	93	85	80	72


(1)	The average lateral length for the wells completed during the first quarter of 2020 was 9,751 feet. Operated completions during the first quarter of 2020 consisted of 47 Wolfcamp A wells, nine Wolfcamp B wells, seven Lower Spraberry wells, six Middle Spraberry wells, two Jo Mill wells, five Second Bone Springs wells, and four Third Bone Springs wells.

As of March 31, 2020, we operated the following wells:



	Vertical Wells		Horizontal Wells		Total
Area	Gross	Net	Gross	Net	Gross	Net
Midland Basin	1,548	1,454	1,041	952	2,589	2,406
Delaware Basin	32	23	544	509	576	532
Total	1,580	1,477	1,585	1,461	3,165	2,938

As of March 31, 2020, we held interests in 3,642 gross (3,035 net) wells, including wells that we do not operate.

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.

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 produced water gathering and disposal system spans approximately 482 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.

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Sources of Our Revenues

In our exploration and production segment, our main sources of revenues are the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from our natural gas during processing, derived from our net revenue and royalty interests.

In our midstream operations segment, our results are primarily driven by the volumes of crude oil that Rattler gathers, transports and delivers; natural gas that Rattler gathers, compresses, transports and delivers; fresh water that Rattler sources, transports and delivers; and produced water that Rattler gathers, transports and disposes of, and the fees Rattler charges per unit of throughput for our midstream services.

The following table presents the breakdown of our oil and natural gas revenues for the following periods:



	Three Months Ended March 31,
	2020		2019
Revenues:
Oil sales	94	%	88	%
Natural gas sales	—	%	3	%
Natural gas liquid sales	6	%	9	%
	100	%	100	%

Commodity Prices

In our upstream business, our production consists primarily of oil. As a result, our revenues are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas or natural gas liquids prices. Oil, natural gas and natural gas liquids prices have historically been volatile. Oil prices dropped sharply in early March 2020, and then continued to decline reaching levels below zero dollars per barrel. This was a result of multiple factors affecting the supply and demand in global oil and natural gas markets, including the announcement of price reductions and production increases by OPEC members and other oil exporting nations and the ongoing COVID-19 pandemic. During the first quarter of 2020, the depressed commodity prices negatively impacted our revenue, production and results of operations, and we recorded an impairment on proved oil and natural gas properties. In addition, the administrative agent under Viper’s credit agreements has recommended that the borrowing base under such credit agreement be decreased to $580 million effective mid-May 2020. Oil and natural gas prices are expected to continue to be volatile as a result of changes in oil and natural gas production, inventories and demand, as well as national and international economic performance. We cannot predict when prices will improve and stabilize. If commodity prices continue at current levels or decrease further, our ability to produce oil and natural gas economically and, as a result, our business, results of operations and financial condition will be adversely affected. Our results of operations may be further adversely impacted by any government rule, regulation or order that may impose production limits in the Permian Basin where we operate.

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.

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The following table sets forth information related to commodity prices for the following periods:



	Three Months Ended March 31,
	2020			2019
High and Low Futures Contract Prices:
Oil ($/Bbl, WTI Futures Contract 1)
High	$	63.27		$	60.14
Low	$	20.09		$	46.54
Natural Gas ($/MMBtu, Futures Contract 1)
High	$	2.20		$	3.59
Low	$	1.60		$	2.55

Average realized oil price ($/Bbl)	$	45.10		$	46.12
Average WTI Futures Contract 1 ($/Bbl)	$	45.78		$	54.90
Differential to WTI Futures Contract 1	(0.68		)	(8.78		)
Average realized oil price to WTI Futures Contract 1	99		%	84		%

Average realized natural gas price ($/Mcf)	$	0.14		$	1.32
Average Natural Gas Futures Contract 1 ($/Mcf)	$	1.87		$	2.87
Differential to Natural Gas Futures Contract 1	(1.73		)	(1.55		)
Average realized natural gas price to Natural Gas Futures Contract 1	7		%	46		%

Average realized natural gas liquids price ($/Bbl)	$	9.45		$	18.00
Average WTI Futures Contract 1 ($/Bbl)	$	45.78		$	54.90
Average realized natural gas liquids price to WTI Futures Contract 1	21		%	33		%

On March 31, 2020, the WTI Futures Contract 1 price for crude oil was $20.48 per Bbl and the Natural Gas Futures Contract 1 price was $1.64 per MMBtu.

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Results of Operations

The following table sets forth selected historical operating data for the three months ended March 31, 2020 and 2019:



	Three Months Ended March 31,
	2020		2019
	(in thousands)
Production Data:
Oil (MBbls)	18,325		16,115
Natural gas (MMcf)	32,120		21,684
Natural gas liquids (MBbls)	5,538		3,908
Combined volumes (MBOE)	29,216		23,637

Daily combined volumes (BOE/d)	321,057		262,633
Daily oil volumes (BO/d)	201,369		179,056

Average Prices:
Oil ($ per Bbl)	$	45.10	$	46.12
Natural gas ($ per Mcf)	$	0.14	$	1.32
Natural gas liquids ($ per Bbl)	$	9.45	$	18.00
Combined ($ per BOE)	$	30.23	$	35.63

Oil, hedged ($ per Bbl)⁽¹⁾	$	49.32	$	46.92
Natural gas, hedged ($ per MMbtu)⁽¹⁾	$	0.42	$	1.49
Natural gas liquids, hedged ($ per Bbl)⁽¹⁾	$	9.45	$	18.19
Average price, hedged ($ per BOE)⁽¹⁾	$	33.19	$	36.38


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

Production Data

Substantially all of our revenues are generated through the sale of oil, natural gas liquids and natural gas production. The following tables set forth our production data for the three months ended March 31, 2020 and 2019:



	Three Months Ended March 31,
	2020		2019
Oil (MBbls)	63	%	68	%
Natural gas (MMcf)	18	%	15	%
Natural gas liquids (MBbls)	19	%	17	%
	100	%	100	%

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	Three Months Ended March 31, 2020				Three Months Ended March 31, 2019
	Midland Basin	Delaware Basin	Other⁽¹⁾	Total	Midland Basin	Delaware Basin	Other⁽²⁾	Total
	(in thousands)
Production Data:
Oil (MBbls)	10,511	7,760	54	18,325	9,984	5,026	1,105	16,115
Natural gas (MMcf)	15,833	16,147	140	32,120	10,172	11,137	375	21,684
Natural gas liquids (MBbls)	3,048	2,463	27	5,538	2,176	1,671	61	3,908
Total (MBoe)	16,198	12,914	104	29,216	13,855	8,553	1,229	23,637


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


(2)	Includes the Eagle Ford Shale.

Comparison of the Three Months Ended March 31, 2020 and 2019

Oil, Natural Gas and Natural Gas Liquids Revenues. Our oil, natural gas and natural gas liquids 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 three months ended March 31, 2020 increased by $41 million, or 5%, to $883 million from $842 million during the three months ended March 31, 2019, primarily due to an increase in oil, natural gas and natural gas liquids production volumes, partially offset by lower average sales prices. The increase in production volumes was due to a combination of increased drilling activity and growth through acquisitions.

The net dollar effect of the change in prices (calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas and natural gas liquids) and the net dollar effect of the change in production (calculated as the increase in period-to-period volumes for oil, natural gas and natural gas liquids multiplied by the period average prices) are shown below:



	Three Months Ended March 31, 2020 Compared to 2019
	Change in prices			Production volumes⁽¹⁾		Total net dollar effect of change
						(in millions)
Effect of changes in price:
Oil	$	(1.02	)	18,325		$	(19	)
Natural gas	$	(1.18	)	32,120		(38		)
Natural gas liquids	$	(8.55	)	5,538		(47		)
Total revenues due to change in price						$	(104	)

	Change in production volumes⁽¹⁾			Prior period Average Prices		Total net dollar effect of change
						(in millions)
Effect of changes in production volumes:
Oil	2,210			$	46.12	$	102
Natural gas	10,436			$	1.32	14
Natural gas liquids	1,630			$	18.00	29
Total revenues due to change in production volumes						145
Total change in revenues						$	41


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

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Midstream Services Revenue. The following table shows midstream services revenue for the three months ended March 31, 2020 and 2019:



	Three Months Ended March 31,
	2020		2019
	(in millions)
Midstream services revenue	$	14	$	19

Our midstream services revenue represents fees charged to our joint interest owners and third parties for the transportation of oil and natural gas along with water gathering and related disposal facilities. These assets complement our operations in areas where we have significant production.

Lease Operating Expenses. The following table shows lease operating expenses for the three months ended March 31, 2020 and 2019:



	Three Months Ended March 31,
	2020				2019
	Amount		Per BOE		Amount		Per BOE
	(in millions, except per BOE amounts)
Lease operating expenses	$	127	$	4.35	$	109	$	4.61

Lease operating expenses for the three months ended March 31, 2020 increased by $18 million as compared to the three months ended March 31, 2019. This increase is primarily associated with our higher well count due to new drilling activity and, to a lesser extent, power generation costs as a result of reduced electrical availability. We are actively working to mitigate this power generation issue and expect these costs to decrease in the future. Lease operating expenses per BOE decreased by $0.26 for the three months ended March 31, 2020 as compared to the three months ended March 31, 2019, primarily due to higher production from our increased drilling activity during the period and growth through acquisitions.

Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the three months ended March 31, 2020 and 2019:



	Three Months Ended March 31,
	2020				2019
	Amount		Per BOE		Amount		Per BOE
	(in millions, except per BOE amounts)
Production taxes	$	42	$	1.42	$	41	$	1.73
Ad valorem taxes	29		1.01		14		0.60
Total production and ad valorem expense	$	71	$	2.43	$	55	$	2.33

In general, production taxes and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, among other factors, whereas production taxes are based upon current year commodity prices. Production taxes for the three months ended March 31, 2020 as compared to the three months ended March 31, 2019 increased by $1 million due to increased overall production from acquisitions and well completions. Production taxes per BOE for the three months ended March 31, 2020 as compared to the three months ended March 31, 2019 decreased by $0.31 primarily due to a higher percentage increase in production volumes as compared to production taxes. Ad valorem taxes for the three months ended March 31, 2020 as compared to the three months ended March 31, 2019 increased by $15 million primarily due to an increase in production volumes from wells drilled and completed in 2019.

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Midstream Services Expense. The following table shows midstream services expense for the three months ended March 31, 2020 and 2019:



	Three Months Ended March 31,
	2020		2019
	(in millions)
Midstream services expense	$	23	$	17

Midstream services expense represents costs incurred to operate and maintain our oil and natural gas gathering and transportation systems, natural gas lift, compression infrastructure and water transportation facilities.

Depreciation, Depletion and Amortization. The following table provides the components of our depreciation, depletion and amortization expense for the three months ended March 31, 2020 and 2019:



	Three Months Ended March 31,
	2020		2019

	(in millions, except BOE amounts)
Depletion of proved oil and natural gas properties	$	392	$	311
Depreciation of midstream assets	11		8
Depreciation of other property and equipment	4		3
Depreciation, depletion and amortization expense	$	407	$	322
Oil and natural gas properties depreciation, depletion and amortization per BOE	$	13.93	$	13.62

The increase in depletion of proved oil and natural gas properties of $81 million for the three months ended March 31, 2020 as compared to the three months ended March 31, 2019 resulted primarily from higher production levels and an increase in net book value on new reserves added.

Impairment of Oil and Natural Gas Properties. The following table shows impairment of oil and natural gas properties for the three months ended March 31, 2020 and 2019:



	Three Months Ended March 31,
	2020		2019
	(in millions)
Impairment of oil and natural gas properties	$	1,009	$	—

As a result of the sharp decline in commodity prices during the first quarter of 2020, we recorded a non-cash ceiling test impairment for the three months ended March 31, 2020 of $1.0 billion which was included in accumulated depletion. The impairment charge affected our results of operations but did not reduce 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 continue to fall as compared to the commodity prices used in prior quarters, we will have material write downs in subsequent quarters. No impairment on proved oil and natural gas properties was recorded for the three months ended March 31, 2019.

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General and Administrative Expenses. The following table shows general and administrative expenses for the three months ended March 31, 2020 and 2019:



	Three Months Ended March 31,
	2020				2019
	Amount		Per BOE		Amount		Per BOE
	(in millions, except per BOE amounts)
General and administrative expenses	$	15	$	0.51	$	13	$	0.55
Non-cash stock-based compensation	9		0.31		14		0.59
Total general and administrative expenses	$	24	$	0.82	$	27	$	1.14

General and administrative expenses for the three months ended March 31, 2020 as compared to the three months ended March 31, 2019 decreased by $3 million primarily due to a decrease in non-cash stock compensation partially offset by higher salary and benefit expenses, legal fees, community donations and software license expenses.

Net Interest Expense. The following table shows net interest expense for the three months ended March 31, 2020 and 2019:



	Three Months Ended March 31,
	2020		2019
	(in millions)
Net interest expense	$	48	$	46

Net interest expense for the three months ended March 31, 2020 as compared to the three months ended March 31, 2019, increased by $2 million. This increase was primarily due to increased average borrowings under our credit facility partially offset by a decrease in interest expense of $3 million related to our DrillCo Agreement during the three months ended March 31, 2020 as compared to the three months ended March 31, 2019.

Derivative Instruments. The following table shows the gain (loss) on derivative instruments, net for the three months ended March 31, 2020 and 2019:



	Three Months Ended March 31,
	2020		2019
	(in millions)
Change in fair value of open non-hedge derivative instruments	$	455	$	(285	)
Gain on settlement of non-hedge derivative instruments	87		17
Gain (loss) on derivative instruments, net	$	542	$	(268	)

We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our consolidated statements of operations under the line item captioned “Gain (loss) on derivative instruments, net.”

Provision for (Benefit From) Income Taxes. The following table shows provision for (benefit from) income taxes for the three months ended March 31, 2020 and 2019:



	Three Months Ended March 31,
	2020		2019
	(in millions)
Provision for (benefit from) income taxes	$	83	$	(33	)

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The change in our income tax provision was primarily due to the pre-tax loss for the three months ended March 31, 2020 offset by discrete tax expense resulting from application of a valuation allowance on Viper’s deferred tax assets, compared to pre-tax income for the three months ended March 31, 2019, offset by a discrete income tax benefit resulting from the revision of estimated deferred taxes recognized as a result of Viper’s change in tax status.

Liquidity and Capital Resources

Historically, our primary sources of liquidity have been proceeds from our public equity offerings, borrowings under our revolving credit facility, proceeds from the issuance of our senior notes and cash flows from operations. Our primary uses of capital have been for the acquisition, development and exploration of oil and natural gas properties. As we pursue 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, 2020 and 2019 are presented below:



	Three Months Ended March 31,
	2020			2019
	(in millions)
Net cash provided by operating activities	$	849		$	377
Net cash used in investing activities	(923		)	(937		)
Net cash provided by financing activities	101			471
Net increase (decrease) in cash	$	27		$	(89	)

Operating Activities

Net cash provided by operating activities was $849 million for the three months ended March 31, 2020 as compared to $377 million for the three months ended March 31, 2019. The increase in operating cash flows is primarily the result of an increase in our oil and natural gas revenues due to an increase in production growth partially offset by a decrease in average prices during the three months ended March 31, 2020.

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

Investing Activities

The purchase and development of oil and natural gas properties accounted for the majority of our cash outlays for investing activities. Net cash used in investing activities was $923 million and $937 million during the three months ended March 31, 2020 and 2019, respectively.

During the three months ended March 31, 2020, we spent (a) $746 million on capital expenditures in conjunction with our development program, in which we drilled 93 gross (85 net) operated horizontal wells, of which 38 gross (35 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin, and turned 80 gross (72 net) operated horizontal wells into production, of which 46 gross (42 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin, (b) $44 million on additions to midstream assets, (c) $40 million on leasehold interest acquisitions, (d) $65 million for the acquisition of mineral interests, (e) $23 million on equity method investment contributions net of distributions received and (f) $5 million for the purchase of other property, equipment and land.

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During the three months ended March 31, 2019, we spent (a) $569 million on capital expenditures in conjunction with our drilling program and related infrastructure projects, in which we drilled 83 gross (73 net) operated horizontal wells, of which 40 gross (36 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin, and turned 82 gross (74 net) operated horizontal wells into production, of which 28 gross (24 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin, (b) $58 million on additions to midstream assets, (c) $75 million on leasehold interest acquisitions, (d) $82 million for mineral interests acquisitions, (e) $4 million for the purchase of other property, equipment and land and (f) $149 million on equity method investments.

Our investing activities for the three months ended March 31, 2020 and 2019 are summarized in the following table:



	Three Months Ended March 31,
	2020			2019
	(in millions)
Drilling, completions and non-operated	$	(690	)	$	(533	)
Additions to infrastructure assets	(56		)	(36		)
Additions to midstream assets	(44		)	(58		)
Purchase of other property, equipment and land	(5		)	(4		)
Acquisitions of leasehold interests	(40		)	(75		)
Acquisitions of mineral interests	(65		)	(82		)
Contributions to equity method investments	(33		)	(149		)
Distributions from equity method investments	10			—
Net cash used in investing activities	$	(923	)	$	(937	)

Financing Activities

Net cash provided by financing activities for the three months ended March 31, 2020 and 2019 was $101 million and $471 million, respectively. During the three months ended March 31, 2020, the amount provided by financing activities was primarily attributable to $290 million of borrowings, net of repayments under our credit facility and $16 million in proceeds from joint ventures, partially offset by $5 million of share repurchases for tax withholdings, $98 million of share repurchases as part of our stock repurchase program, $59 million of dividends to stockholders and $43 million of distributions to non-controlling interest. The 2019 amount provided by financing activities was primarily attributable to $170 million of borrowings, net of repayments under our credit facility, an aggregate of $341 million of net proceeds from Viper’s public offering, partially offset by $26 million of distributions to non-controlling interest, $21 million of dividends to stockholders, $23 million in proceeds from joint ventures and $13 million of share repurchases for tax withholdings.

2025 Senior Notes

On December 20, 2016, we issued $500 million in aggregate principal amount of 5.375% senior notes due 2025, which we refer to as the existing 2025 notes, under an indenture among us, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, which we refer to as the 2025 indenture. On January 29, 2018, we issued $300 million aggregate principal amount of new 5.375% senior notes due 2025 as additional notes under the 2025 indenture, which we refer to as the new 2025 notes and, together with the existing 2025 notes, as the 2025 senior notes.

The 2025 senior notes bear interest at a rate of 5.375% per annum, payable semi-annually, in arrears on May 31 and November 30 of each year and will mature on May 31, 2025. All of our existing and future restricted subsidiaries that guarantee our revolving credit facility guarantee the 2025 senior notes. Currently, the 2025 senior notes are not guaranteed by any of our subsidiaries other than Diamondback O&G LLC and will not be guaranteed by any of our future unrestricted subsidiaries.

The 2025 indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of our restricted subsidiaries to incur or guarantee additional indebtedness or issue certain redeemable or preferred equity, make certain investments, declare or pay dividends or make distributions on equity interests or redeem, repurchase or retire equity interests or subordinated indebtedness, transfer or sell assets, agree to payment restrictions affecting its restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens and designate certain of its subsidiaries

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as unrestricted subsidiaries. These covenants are subject to numerous exceptions, some of which are material. Certain of these covenants are subject to termination upon the occurrence of certain events.

For additional information regarding the 2025 senior notes, see Note 10—Debt included in Notes to the Consolidated Financial Statements included elsewhere in this Form 10-Q. We may use cash on hand to repurchase a portion of the 2025 senior notes in privately-negotiated transactions, open market purchases or otherwise, but we are under no obligation to do so.

December 2019 Notes Offering

On December 5, 2019, we issued $1.0 billion in aggregate principal amount of 2.875% senior notes due 2024, which we refer to as the 2024 notes, $800 million in aggregate principal amount of 3.250% senior notes due 2026, which we refer to as the 2026 notes, and $1.2 billion aggregate principal amount of 3.500% senior notes due 2029, which we refer to as the 2029 notes. We refer to the 2024 notes, the 2026 notes and the 2029 notes, collectively, as the December 2019 notes. The 2024 notes will mature on December 1, 2024, the 2026 notes will mature on December 1, 2026 and the 2029 notes will mature on December 1, 2029. Interest will accrue and be payable semi-annually, in arrears on June 1 and December 1 of each year, commencing on June 1, 2020. The December 2019 notes are guaranteed by Diamondback O&G LLC and are not guaranteed by any of our other subsidiaries.

The December 2019 notes were issued under an indenture, dated as of December 5, 2019, among us and Wells Fargo, as the trustee, as supplemented by the first supplemental indenture dated as of December 5, 2019, which we collectively refer to as the December 2019 Notes Indenture. The December 2019 Notes Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of certain of our subsidiaries to incur liens securing funded indebtedness and on our ability to consolidate, merge or sell, convey, transfer or lease all or substantially all of its assets.

For additional information regarding the December 2019 Notes, see Note 10—Debt included in Notes to the Consolidated Financial Statements included elsewhere in this Form 10-Q. We may use cash on hand to repurchase a portion of the December 2019 Notes in privately-negotiated transactions, open market purchases or otherwise, but we are under no obligation to do so.

Second Amended and Restated Credit Facility

We, as parent guarantor, and Diamondback O&G LLC, as borrower, entered into the second amended and restated credit agreement, dated November 1, 2013, as amended, with a syndicate of banks, including Wells Fargo, as administrative agent, and its affiliate Wells Fargo Securities, LLC, as sole book runner and lead arranger. On June 28, 2019, the credit agreement was amended pursuant to an eleventh amendment, which implemented certain changes to the credit facility for the period on and after the date on which our unsecured debt achieves an investment grade rating from two rating agencies and certain other conditions in the credit agreement are satisfied which changes became effective November 20, 2019. As of March 31, 2020, the maximum credit amount available under the credit agreement is $2.0 billion. As of March 31, 2020, we had approximately $199 million of outstanding borrowings under our revolving credit facility and $1.8 billion available for future borrowings under our revolving credit facility.

The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by us that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 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 pricing level, which in turn depends on the rating agencies’ ratings of our unsecured debt. We are obligated to pay a quarterly commitment fee ranging from 0.125% to 0.350% per year on the unused portion of the commitment, based on the pricing level, which in turn depends on the rating agencies’ ratings of our unsecured debt.

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in the credit agreement) and we and our restricted subsidiaries may incur liens if the aggregate amount of debt secured by such liens does not exceed 15% of consolidated net tangible assets.

As of March 31, 2020, we were in compliance with all financial maintenance covenants under our revolving credit facility, as then in effect. The lenders may accelerate all of the indebtedness under our revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control.

Energen Notes

At the effective time of the merger, Energen became our wholly owned subsidiary and remained the issuer of an aggregate principal amount of $530 million in notes, which we refer to as the Energen Notes, issued under an indenture dated September 1, 1996 with The Bank of New York as Trustee, which we refer to as the Energen Indenture. As of March 31, 2020, the Energen Notes consist of: (a) $400 million aggregate principal amount of 4.625% senior notes due on September 1, 2021, (2) $100 million of 7.125% notes due on February 15, 2028, (3) $20 million of 7.32% notes due on July 28, 2022, and (4) $10 million of 7.35% notes due on July 28, 2027.

The Energen Notes are the senior unsecured obligations of Energen and, post-merger, Energen, as our wholly owned subsidiary, continues to be the sole issuer and obligor under the Energen Notes. The Energen Notes rank equally in right of payment with all other senior unsecured indebtedness of Energen if any, and are effectively subordinated to Energen’s senior secured indebtedness, if any, to the extent of the value of the collateral securing such indebtedness. Neither we nor any of our subsidiaries guarantee the Energen Notes.

For additional information regarding the Energen Notes, See Note 10—Debt included in Notes to the Consolidated Financial Statements included elsewhere in this Form 10-Q. We may use cash on hand to repurchase a portion of the Energen Notes in privately-negotiated transactions, open market purchases or otherwise, but we are under no obligation to do so.

Viper’s Credit Agreement

On July 20, 2018, Viper LLC, as borrower, entered into an amended and restated credit agreement with Viper, as guarantor, Wells Fargo, as administrative agent, and the other lenders. The credit agreement, as amended, which we refer to as the Viper credit agreement, provides for a revolving credit facility in the maximum credit amount of $2 billion and a borrowing base based on Viper LLC’s oil and natural gas reserves and other factors (the “borrowing base”) of $775 million, subject to scheduled semi-annual and other elective borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and November 1st. In addition, Viper LLC and Wells Fargo each may request up to three interim redeterminations of the borrowing base during any 12-month period. As of March 31, 2020, the borrowing base was $775 million, and Viper LLC had $174 million of outstanding borrowings and $601 million available for future borrowings under the Viper credit agreement. In connection with the regularly scheduled (semi-annual) spring 2020 redetermination, the administrative agent under the Viper credit agreement has recommended that the borrowing base be decreased under the Viper credit agreement to $580 million effective mid-May 2020. The decrease is subject to approval by the requisite lenders under the Viper credit agreement. Under the new expected borrowing base, Viper LLC would have had $407 million of availability for future borrowings under the Viper credit agreement as of March 31, 2020.

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



Financial Covenant	Required Ratio
Ratio of total net debt to EBITDAX, as defined in the Viper credit agreement	Not greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the Viper credit agreement	Not less than 1.0 to 1.0

As of March 31, 2020, Viper and Viper LLC were in compliance with all financial maintenance covenants under the Viper credit agreement, as then in effect. The lenders may accelerate all of the indebtedness under the Viper credit agreement upon the occurrence and during the continuance of any event of default. The Viper credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control.

Viper’s Notes

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

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

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

Rattler’s Credit Agreement

In connection with the Rattler Offering, Rattler, as parent, and Rattler LLC, as borrower, entered into a credit agreement, dated May 28, 2019, with Wells Fargo, as administrative agent, and a syndicate of banks, including Wells Fargo, as lenders party thereto, which we refer to as the Rattler credit agreement.

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 lender commitments and satisfaction of customary conditions. Loan principal may be optionally prepaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid at the maturity date of May 28, 2024.

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The Rattler credit agreement is guaranteed by Rattler, Tall City, Rattler OMOG LLC and Rattler AJAX Processing LLC and is secured by substantially all of the assets of Rattler LLC, Rattler, Tall City, Rattler OMOG LLC and Rattler AJAX Processing LLC. As of March 31, 2020, Rattler LLC had $451 million of outstanding borrowings and $149 million available for future borrowings under the Rattler credit agreement.

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



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

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

As of March 31, 2020, Rattler and Rattler LLC were in compliance with all financial maintenance covenants under the Rattler credit agreement. The lenders may accelerate all of the indebtedness under the Rattler credit agreement upon the occurrence and during the continuance of any event of default. The Rattler credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change in control.

Capital Requirements and Sources of Liquidity

Our board of directors approved a 2020 capital budget for drilling and completion, midstream and infrastructure of approximately $2.8 billion to $3.0 billion. In response to the current commodity price environment, we have updated our 2020 capital budget to narrow our anticipated capital expenditures for 2020 to approximately $1.5 billion to $1.9 billion, representing a decrease of 41% over our 2019 capital budget. We estimate that, of these expenditures, approximately:


•	$1.31 billion to $1.63 billion will be spent on drilling and completing 170 to 200 gross (153 to 180 net) horizontal wells across our operated leasehold acreage in the Northern Midland and Southern Delaware Basins, with an average lateral length of approximately 9,700 feet;


•	$100 million to $150 million will be spent on midstream infrastructure, excluding joint venture investments; and


•	$90 million to $120 million will be spent on infrastructure and other expenditures, excluding the cost of any leasehold and mineral interest acquisitions.

During the three months ended March 31, 2020, our aggregate capital expenditures for our development program were $746 million. Additionally during the three months ended March 31, 2020, we spent approximately $105 million in cash on acquisitions of leasehold interests and mineral acres. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.

In May 2019, our board of directors approved a stock repurchase program to acquire up to $2 billion of our outstanding common stock through December 31, 2020. We repurchased approximately $98 million of our common stock under this program during the three months ended March 31, 2020. Although we have approximately $1.3 billion remaining available for future repurchases under this program, we have suspended this program to preserve liquidity.

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 14 drilling rigs and no completion crews. We will continue monitoring commodity prices and overall market conditions and can adjust our rig cadence up or down in response to changes in commodity prices and overall market conditions.

Based upon current oil and natural gas prices and production expectations for 2020, we believe that our cash flow from operations, cash on hand and borrowings under our revolving credit facility will be sufficient to fund our operations through year-end 2020. 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 2020 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 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, 2020, Diamondback O&G LLC is the sole guarantor under the December 2019 Notes Indenture governing the 2019 senior notes and the 2025 Indenture governing the 2025 senior notes. In connection with the satisfaction and discharge of the indenture, dated as of October 28, 2016, as subsequently supplemented, among Diamondback Energy, Inc., the guarantor subsidiaries party thereto and Wells Fargo, as trustee, governing Diamondback Energy, Inc.’s then outstanding 4.750% Senior Notes due 2024, or the 4.750% senior notes, Diamondback E&P LLC and Energen Corporation and its subsidiaries were released as guarantors under the 4.750% senior notes, the 2025 senior notes and Diamondback O&G LLC’s revolving credit facility. Rattler LLC was released as a guarantor under Diamondback O&G LLC’s credit agreement on May 28, 2019. Viper, Viper’s General Partner, Viper LLC, Rattler, Rattler’s General Partner and Rattler’s subsidiaries remain non-guarantor subsidiaries.

Diamondback O&G LLC’s guarantees of the 2019 senior notes and the 2025 senior notes 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 indentures governing the 2019 senior notes and the 2025 senior notes, 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 2019 senior notes and the 2025 senior 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, 2020		December 31, 2019
Summarized Balance Sheet	(in millions)
Assets
Current assets	$	952	$	396
Property and equipment, net	10,556		10,109
Other noncurrent assets	43		17
Liabilities
Current liabilities	$	182	$	167
Intercompany accounts payable, non-guarantor subsidiary	794		600
Long-term debt	3,969		3,782
Other noncurrent liabilities	570		504



	Three Months Ended March 31, 2020
Summarized Statements of Operations	(in millions)
Revenues	$	523
Income from operations	95
Net Income	673

Contractual Obligations

There were no material changes to our contractual obligations and other commitments, as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2019.

Critical Accounting Policies

There have been no changes in our critical accounting policies from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2019.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of March 31, 2020. Please read Note 18 included in Notes to the Consolidated Financial Statements set forth in Part I, Item 1 of this report, for a discussion of our commitments and contingencies, which are not recognized in the balance sheets under GAAP.

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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. Oil prices dropped sharply in early March 2020, and then continued to decline reaching levels below zero dollars per barrel. This was a result of multiple factors affecting supply and demand in global oil and gas markets, including the announcement of price reductions and production increases by OPEC members and other oil exporting nations and the ongoing COVID-19 pandemic. Oil and natural gas prices are expected to continue to be volatile as a result of the changes in oil and natural gas production, inventories and demand, as well as national and international economic performance. We cannot predict when prices will improve and stabilize.

We use price swap derivatives, including basis swaps, double-up swaps, put spreads, interest rate swaps and three-way collars, to reduce price volatility associated with certain of our oil and natural gas sales. With respect to these fixed price swap contracts, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap price, and we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. Our derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate pricing (Cushing and Magellan East Houston) and Crude Oil - Brent and with natural gas derivative settlements based on NYMEX Henry Hub and Waha Hub pricing.

At March 31, 2020 and December 31, 2019, we had a net asset derivative position related to our commodity price swap derivatives of $551 million and $26 million, respectively. Utilizing actual derivative contractual volumes under our fixed price swaps as of March 31, 2020, a 10% increase in forward curves associated with the underlying commodity would have decreased the net asset position to $459 million, a decrease of $92 million, while a 10% decrease in forward curves associated with the underlying commodity would have increased the net asset derivative position to $643 million, an increase of $92 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 shuts 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.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from joint interest receivables (approximately $178 million at March 31, 2020) and receivables from the sale of our oil and natural gas production (approximately $225 million at March 31, 2020).

We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. For the three months ended March 31, 2020, four purchasers each accounted for more than 10% of our revenue: Vitol Midstream (27%), Shell Trading Risk Management LLC (25%), Plains Marketing LP (22%), and Trafigura Trading LLC (11%). For the three months ended March 31, 2019, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (25%), Plains Marketing LP (25%) and Occidental Energy Marketing Inc (10%). No other customer accounted for more than 10% of our revenue during these periods.

Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells. At March 31, 2020, we had 15 customers that represented approximately 82% of our total joint operations receivables. At December 31, 2019, we had 15 customers that represented approximately 80% of our total joint operations receivables.

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The ongoing COVID-19 pandemic, depressed commodity pricing environment and adverse macroeconomic conditions may enhance our customer credit risk.

Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facility. The terms of our revolving credit facility provide for interest on borrowings at a floating rate equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.25% to 1.25% in the case of the alternative base rate and from 1.25% to 2.25% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base.

As of March 31, 2020, we had $199 million in outstanding borrowings under our revolving credit facility. Our weighted average interest rate on borrowings under our revolving credit facility was 2.26% as of March 31, 2020. An increase or decrease of 1% in the interest rate would have a corresponding increase or decrease in our interest expense of approximately $2 million based on the $199 million outstanding under our revolving credit facility as of such date.

As of March 31, 2020, Viper LLC had $174 million in outstanding borrowings. Viper LLC’s weighted average interest rate was 2.78%. An increase or decrease of 1% in the interest rate would have a corresponding increase or decrease in Viper LLC’s interest expense of approximately $2 million based on the $174 million outstanding in the aggregate under the Viper credit agreement on March 31, 2020.

As of March 31, 2020, Rattler LLC had $451 million of outstanding borrowings. Rattler LLC’s weighted average interest rate was 2.19%. An increase or decrease of 1% in the interest rate would have a corresponding increase or decrease in Rattler LLC’s interest expense of approximately $5 million based on the $451 million outstanding under the Rattler credit agreement as of March 31, 2020.

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, 2020, 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, 2020, 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, 2020 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

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PART II

ITEM 1. LEGAL PROCEEDINGS

We are a party to various legal proceedings, disputes and claims arising in the 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 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, cash flows or results of operations.

ITEM 1A. RISK FACTORS

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

In addition to the information set forth in this report, you should carefully consider the risk factors discussed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2019 and in subsequent filings we make with the SEC, as well as the risk factors set forth below.

Risks Related to Our Business

Our business and operations have been and will likely continue to be adversely affected by the recent COVID-19 pandemic.

The spread of COVID-19 caused, and is continuing to cause, severe disruptions in the worldwide and U.S. economy, including contributing to the reduced global and domestic demand for oil and natural gas, which has had and will likely continue to have an adverse effect on our business, financial condition and results of operations. Moreover, since the beginning of January 2020, the COVID-19 pandemic has caused significant disruption in the financial markets both globally and in the United States. The continued spread of COVID-19 could also negatively impact the availability of key personnel necessary to conduct our business. If COVID-19 continues to spread or the response to contain the COVID-19 pandemic is unsuccessful, we could continue to experience material adverse effects on our business, financial condition and results of operations.

The sharp decline in oil and natural gas prices and continued volatility in the oil and natural gas markets have negatively impacted, and are likely to continue to negatively impact, our exploration and production activities, which has adversely impacted our business, financial condition and results of operations.

Oil prices dropped sharply in early March 2020 and then continued to decline reaching levels below zero dollars per barrel as a result of multiple factors affecting supply and demand in global oil and gas markets, including the announcement of price reductions and production increases by OPEC members and other oil exporting nations and the COVID-19 pandemic. Oil and natural gas prices are expected to continue to be volatile as a result of changes in oil and natural gas production, inventories and demand, as well as national and international economic performance. We cannot predict when prices will improve and stabilize.

Other significant factors that are likely to continue to affect commodity prices in current and future periods include, but are not limited to, the effect of U.S. energy, monetary and trade policies, U.S. and global political and economic developments, including the outcome of the U.S. presidential election and resulting energy and environmental policies, the impact of the ongoing COVID-19 pandemic and conditions in the U.S. oil and gas industry, all of which are beyond our control.

The current prices of oil, natural gas and natural gas liquids, as well as ongoing volatility, have had an adverse impact on our level of drilling and exploration and production activity, which has impacted and could materially and adversely affect our business, financial condition and results of operations. Lower commodity prices may also limit the amount of reserves we can produce economically thus adversely affecting our proved reserves, reserve replacement ratio and accelerating the reduction in our existing reserve levels as we continue production in our upstream business. A decrease in our proved reserve estimates would increase the unit-of-production rate used to determine DD&A expense

on producing properties. Prolonged lower crude oil prices may affect certain decisions related to our operations, including decisions to further reduce capital expenditures or decisions to curtail production. In addition, lower commodity prices may affect future dividends we elect to declare and pay on our common stock. To preserve liquidity, we have suspended our stock repurchase program.

As result of the sharp decline in commodity prices during the first quarter of 2020, we recorded a non-cash ceiling test impairment for the three months ended March 31, 2020 of $1.0 billion. The impairment charge adversely affected our results of operations but did not reduce our cash flows. 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 impairment analysis in the future. If the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters, we will have material write downs in subsequent quarters. Although it is not reasonably practicable to quantify the impact of any future impairments, our results of operations may be adversely affected.

Our results of operations may be also adversely impacted by any future government rule, regulation or order that may impose production limits, as well as pipeline capacity and storage constraints, in the Permian Basin were we operate.

A prolonged curtailment or shut-in of horizontal wells on our acreage could adversely impact future well performance

In response to the current depressed commodity prices and the global oversupply of crude oil, we announced plans to voluntarily curtail 10% to 15% of our expected May 2020 production in operating areas where we can manage production economically and without the addition of material operating expense. We will continue to monitor whether additional strategic curtailments are warranted in June 2020 and beyond. If this short-term curtailment becomes prolonged or is expanded to involve a large-scale shut-in of horizontal wells, the impact of such action is uncertain but could potentially adversely impact future well performance.

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, 2020 was as follows:



Period	Total Number of Shares Purchased	Average Price Paid Per Share⁽¹⁾		Total Number of Shares Purchased as Part of Publicly Announced Plan	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan⁽²⁾
	($ in millions, except per share amounts, shares in thousands)
January 2020	516	$	87.28	516	$	1,357
February 1, 2020	596	$	72.03	596	$	1,314
March 1, 2020	168	$	58.57	168	$	1,304
Total	1,280	$	76.40	1,280


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


(2)	In May 2019, our board of directors approved a new stock repurchase program to acquire up to $2 billion of our outstanding common stock through December 31, 2020. This repurchase program has been suspended to preserve liquidity.

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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	Description of the Company’s Securities (incorporated by reference to Exhibit 4.1 to the Form 10-K, File No. 001-35700, filed by the Company with the SEC on February 27, 2020).
4.3	Registration Rights Agreement, dated as of February 28, 2017, by and among Diamondback Energy, Inc., Brigham Resources, LLC, Brigham Resources Operating, LLC and Brigham Resources Upstream Holdings, LP (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on March 6, 2017).
4.4	Registration Rights Agreement, dated October 31, 2018, by and between Diamondback Energy, Inc. and Ajax Resources, LLC (incorporated by reference to Exhibit 4.1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 7, 2018).
10.1+	2019 Amended and Restated Diamondback Energy, Inc. Equity Incentive Plan (incorporated by reference to Appendix A to Schedule DEF 14A filed by the Company with the SEC on April 26, 2019).
10.2+	2020 Form of Time Vesting Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.2 to the Form 10-K, File No. 001-35700, filed by the Company with the SEC on February 27, 2020).
10.3+	2020 Form of Performance Vesting Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.3 to the Form 10-K, File No. 001-35700, filed by the Company with the SEC on February 27, 2020).
10.4+	Diamondback Energy, Inc. Senior Management Severance Plan (including forms of participation agreements attached thereto as Schedules C-1 and C-2) (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 27, 2020).
22.1*	List of Issuers and Guarantor Subsidiaries.
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, 2020, formatted in Inline XBRL: (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statement of Changes in Stockholders’ Equity, (iv) 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).

______________

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

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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, 2020	/s/ Travis D. Stice
		Travis D. Stice
		Chief Executive Officer
		(Principal Executive Officer)

Date:	May 7, 2020	/s/ Kaes Van’t Hof
		Kaes Van’t Hof
		Chief Financial Officer
		(Principal Financial Officer)