UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 
FORM 10-Q

☒QUARTERLY REPORT UNDERPURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED For the quarterly period ended September 30, 20192020
OR
☐TRANSITION REPORT UNDERPURSUANT 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)
DE45-4502447
(State or Other Jurisdiction of Incorporation or Organization)(I.R.S. Employer Identification Number)
500 West Texas
Suite 1200
Midland,TX79701
(Address of principal executive offices)(Zip code)
(432) (432) 221-7400
(Registrant'sRegistrant’s telephone number, including area code)
 Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common StockFANGThe 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☐
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 November 1, 2019,October 30, 2020, the registrant had 160,444,608157,972,650 shares of common stock outstanding.




DIAMONDBACK ENERGY, INC.
FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 20192020
TABLE OF CONTENTS
Page
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PART I. FINANCIAL INFORMATION
Consolidated Balance Sheets
1
Condensed Consolidated Balance Sheets
1
Condensed Consolidated Statements of Operations
3
Condensed Consolidated Statements of Stockholders’ Equity
4
Condensed Consolidated Statements of Cash Flows
6
Condensed Notes to Consolidated Financial Statements
87
5433
7449
7550
PART II. OTHER INFORMATION
7651
7651
7652
7753
Signatures
79






Table of Contents
GLOSSARY OF OIL AND NATURAL GAS TERMS
The following is a glossary of certain oil and natural gas industry terms that are used in this Quarterly Report on Form 10-Q (this “report”):
BasinA large depression on the earth’s surface in which sediments accumulate.
Bbl or barrelStockOne stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
BOEBarrels
BOEOne barrel of crude oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BOE/dBOE per day.
British Thermal Unit or BtuThe quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
CompletionThe 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 oilLiquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.
Finding and development costsCapital 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 wellsThe total acres or wells, as the case may be, in which a working interest is owned.
Horizontal drillingA 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 wellsWells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.
Mb/dThousand
MBblOne thousand barrels of crude oil and other liquid hydrocarbons.
MBOE/dOne thousand BOE per day.
McfThousandOne thousand cubic feet of natural gas.
Mcf/dOne thousand cubic feet of natural gas per day.
Mineral interestsThe interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
MMBtuMillionOne million British Thermal Units.
Net acres or net wellsThe sum of the fractional working interest owned in gross acres.
Oil and natural gas propertiesTracts of land consisting of properties to be developed for oil and natural gas resource extraction.
OperatorThe individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
Plugging and abandonmentRefers 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
ProspectA 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 reservesThe 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
ReservesThe 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).
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ReservoirA porous and permeable underground formation containing a natural accumulation of producible natural gas and/or crude oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Royalty interestAn interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development.

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Spacing
SpacingThe 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 interestAn operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

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GLOSSARY OF CERTAIN OTHER TERMS
The following is a glossary of certain other terms that are used in this report.
ASUAccounting Standards Update
ASUAccounting Standards Update
Equity PlanThe Company’s Equity Incentive Plan.
Exchange ActThe Securities Exchange Act of 1934, as amended.
FASBFinancial Accounting Standards Board
GAAPAccounting principles generally accepted in the United States.
2024 IndentureThe indenture relating to the 2024 Senior Notes, dated as of October 28, 2016, among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented.
2025 IndentureThe indenture relating to the 2025 Senior Notes (defined below), dated as of December 20, 2016, among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented.
NYMEX2025 Senior NotesThe Company’s 5.375% Senior Notes due 2025 in the aggregate principal amount of $800 million
December 2019 NotesThe Company’s 2.875% Senior Notes due 2024 in the aggregate principal amount of $1 billion, the Company’s 3.250% Senior Notes due 2026 in the aggregate principal amount of $800 million and the Company’s 3.500% Senior Notes due 2029 in the aggregate principal amount of $1.2 billion.
December 2019 Notes IndentureThe indenture, dated as of December 5, 2019, among the Company and Wells Fargo, as the trustee, as supplemented by the first supplemental indenture dated as of December 5, 2019 and the second supplemental indenture dated as of May 26, 2020, relating to the December 2019 Notes (defined above) and the May 2020 Notes (defined below).
May 2020 NotesThe Company’s 4.750% Senior Notes due 2025 in the aggregate principal amount of $500.0 million issued on May 26, 2020 under the December 2019 Notes Indenture (defined above) and the related second supplemental indenture.
NYMEXNew York Mercantile Exchange.
RattlerRattler Midstream LP, a Delaware limited partnership.
Rattler’s General PartnerRattler Midstream GP LLC, a Delaware limited liability company; the general partner of Rattler Midstream LP and a wholly-owned subsidiary of the Company.
Rattler LLCRattler Midstream Operating LLC, a Delaware limited liability company and a subsidiary of Rattler.
Rattler LTIPRattler Midstream LP Long-Term Incentive Plan.
Rattler OfferingRattler’s initial public offering.
Rattler’s Partnership AgreementThe first amended and restated agreement of limited partnership, dated May 28, 2019.
SECUnited States Securities and Exchange Commission.
Securities ActThe Securities Act of 1933, as amended.
2024 Senior NotesThe Company’s 4.750% senior unsecured notes due 2024 in the aggregate principal amount of $1,250 million.
Senior NotesThe 2025 Senior Notes,The Company’s 5.375% senior unsecured notes due 2025 in the aggregate principal amount of $800 million.
Senior NotesThe 2024 SeniorDecember 2019 Notes and the 2025 SeniorMay 2020 Notes.
ViperViper Energy Partners LP, a Delaware limited partnership.
Viper’s General PartnerViper Energy Partners GP LLC, a Delaware limited liability company and the General Partner of the Partnership.
Viper LLCViper Energy Partners LLC, a Delaware limited liability company and a subsidiary of the Partnership.
Viper LTIPViper Energy Partners LP Long Term Incentive Plan.
Viper OfferingViper’s initial public offering.
Viper’s Partnership AgreementThe second amended and restated agreement of limited partnership, dated May 9, 2018, as amended as of May 10, 2018.
Wells FargoWells 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, 20182019 could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted or implied in such forward-looking statements. Unless the context requires otherwise, references to “we,” “us,” “our” or the “Company” are intended to mean the business and operations of the Company and its consolidated subsidiaries.

Forward-looking statements may include statements about our:about:

•the volatility of realized oil and natural gas prices and the extent and duration of price reductions and increased production by the Organization of the Petroleum Exporting Counties, or OPEC, members and other oil exporting nations;

•the threat, occurrence, potential duration or other implications of epidemic or pandemic diseases, including the ongoing COVID-19 pandemic or any government responses to such threat, occurrence or pandemic;

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

•logistical challenges and the supply chain disruptions;

•changes in general economic, business strategy;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 the 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 recent 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, curtailments or interruptions of production, and any governmental order, rule or regulation that may impose production limits;

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

•our ability to identify, complete and effectively integrate acquisitions includingof properties or businesses;

•competition in the oil and natural gas industry;

•title defects in our acquisition of Energen Corporation, or Energen, discussed elsewhere in this report;oil and natural gas properties;

our recently completed drop-down transaction•uncertainties with our subsidiary Viper Energy Partners LP, or Viper;

respect to identified drilling locations;locations and estimates of reserves;

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

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•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;

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

financial strategy;•future operating results;

realized oil and natural gas prices and effects•impact of hedging arrangements;any impairment charges;

production;

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

•operating hazards;

•civil unrest, terrorist attacks and cyber threats;

•the effects of future operating results;litigation;

•our ability to keep up with technological advancements;

•capital expenditure plans; and

•other plans, objectives, expectations and intentions.intentions; and

•certain other factors discussed elsewhere in this report.

All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities laws. You should not place undue reliance on these forward-looking statements. 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.     CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Diamondback Energy, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets
(Unaudited)
September 30,December 31,
20202019
(In millions, except par values and share data)
Assets
Current assets:
Cash and cash equivalents$92 $123 
Restricted cash7 5 
Accounts receivable:
Joint interest and other, net67 186 
Oil and natural gas sales, net224 429 
Inventories33 37 
Derivative instruments15 46 
Income tax receivable100 19 
Prepaid expenses and other current assets20 24 
Total current assets558 869 
Property and equipment:
Oil and natural gas properties, full cost method of accounting ($7,879 million and $9,207 million excluded from amortization at September 30, 2020 and December 31, 2019, respectively)27,305 25,782 
Midstream assets1,026 931 
Other property, equipment and land135 125 
Accumulated depletion, depreciation, amortization and impairment(11,031)(5,003)
Property and equipment, net17,435 21,835 
Equity method investments532 479 
Derivative instruments0 7 
Deferred tax assets, net75 142 
Investment in real estate, net104 109 
Other assets56 90 
Total assets$18,760 $23,531 
Diamondback Energy, Inc. and Subsidiaries
Consolidated Balance Sheets
(Unaudited)
   
   
 September 30,December 31,
 20192018
 (In millions, except par values and share data)
Assets  
Current assets:  
Cash and cash equivalents$100
$215
Accounts receivable:  
Joint interest and other, net171
96
Oil and natural gas sales367
296
Inventories45
37
Derivative instruments140
231
Prepaid expenses and other22
50
Total current assets845
925
Property and equipment:  
Oil and natural gas properties, full cost method of accounting ($9,464 million and $9,670 million excluded from amortization at September 30, 2019 and December 31, 2018, respectively)24,822
22,299
Midstream assets884
700
Other property, equipment and land152
147
Accumulated depletion, depreciation, amortization and impairment(3,815)(2,774)
Net property and equipment22,043
20,372
Funds held in escrow7
—
Equity method investments225
1
Derivative instruments58
—
Deferred tax asset158
97
Investment in real estate, net111
116
Other assets106
85
Total assets$23,553
$21,596

















See accompanying notes to condensed consolidated financial statements.

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


September 30,December 31,
20202019
(In millions, except par values and share data)
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable - trade$95 $179 
Accrued capital expenditures309 475 
Current maturities of long-term debt191 0 
Other accrued liabilities329 304 
Revenues and royalties payable219 278 
Derivative instruments86 27 
Total current liabilities1,229 1,263 
Long-term debt5,656 5,371 
Derivative instruments108 0 
Asset retirement obligations112 94 
Deferred income taxes978 1,886 
Other long-term liabilities8 11 
Total liabilities8,091 8,625 
Commitments and contingencies (Note 17)
Stockholders’ equity:
Common stock, $0.01 par value; 200,000,000 shares authorized; 157,849,848 and 159,002,338 shares issued and outstanding at September 30, 2020 and December 31, 2019, respectively2 2 
Additional paid-in capital12,615 12,357 
Retained earnings (accumulated deficit)(3,065)890 
Total Diamondback Energy, Inc. stockholders’ equity9,552 13,249 
Non-controlling interest1,117 1,657 
Total equity10,669 14,906 
Total liabilities and equity$18,760 $23,531 


 September 30,December 31,
 20192018
 (In millions, except par values and share data)
Liabilities and Stockholders’ Equity  
Current liabilities:  
Accounts payable-trade$233
$128
Accrued capital expenditures427
495
Other accrued liabilities304
253
Revenues and royalties payable207
143
Derivative instruments10
—
Total current liabilities1,181
1,019
Long-term debt4,761
4,464
Derivative instruments2
15
Asset retirement obligations90
136
Deferred income taxes2,019
1,785
Other long-term liabilities11
10
Total liabilities8,064
7,429
Commitments and contingencies (Note 19)




Stockholders’ equity:  
Common stock, $0.01 par value, 200,000,000 shares authorized, 161,142,305 issued and outstanding at September 30, 2019; 200,000,000 shares authorized, 164,273,447 issued and outstanding at December 31, 20182
2
Additional paid-in capital12,641
12,936
Retained earnings1,407
762
Total Diamondback Energy, Inc. stockholders’ equity14,050
13,700
Non-controlling interest1,439
467
Total equity15,489
14,167
Total liabilities and equity$23,553
$21,596

























See accompanying notes to condensed consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries
Condensed Consolidated Statements of Operations
(Unaudited)


Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(In millions, except per share amounts, shares in thousands)
Revenues:
Oil sales$606 $882 $1,785 $2,572 
Natural gas sales36 16 61 36 
Natural gas liquid sales65 58 156 190 
Lease bonus0 1 0 4 
Midstream services12 16 37 51 
Other operating income1 2 5 7 
Total revenues720 975 2,044 2,860 
Costs and expenses:
Lease operating expenses102 128 332 364 
Production and ad valorem taxes55 61 148 180 
Gathering and transportation33 25 105 54 
Midstream services26 26 81 60 
Depreciation, depletion and amortization286 365 1,036 1,046 
Impairment of oil and natural gas properties1,451 0 4,999 0 
General and administrative expenses20 19 64 68 
Asset retirement obligation accretion2 1 5 6 
Other operating expense1 1 4 3 
Total costs and expenses1,976 626 6,774 1,781 
Income (loss) from operations(1,256)349 (4,730)1,079 
Other income (expense):
Interest expense, net(53)(38)(147)(133)
Other income, net0 2 1 5 
Gain (loss) on derivative instruments, net(99)177 82 3 
Gain (loss) on revaluation of investment(2)0 (9)4 
Loss on extinguishment of debt(2)0 (5)0 
Income (loss) from equity investments3 0 (10)0 
Total other income (expense), net(153)141 (88)(121)
Income (loss) before income taxes(1,409)490 (4,818)958 
Provision for (benefit from) income taxes(304)102 (902)171 
Net income (loss)(1,105)388 (3,916)787 
Net income (loss) attributable to non-controlling interest8 20 (138)60 
Net income (loss) attributable to Diamondback Energy, Inc.$(1,113)$368 $(3,778)$727 
Earnings (loss) per common share:
Basic$(7.05)$2.27 $(23.91)$4.44 
Diluted$(7.05)$2.26 $(23.91)$4.42 
Weighted average common shares outstanding:
Basic157,833 162,543 157,984 164,070 
Diluted157,833 162,780 157,984 164,466 
Dividends declared per share$0.375 $0.1875 $1.125 $0.5625 

 Three Months Ended September 30, Nine Months Ended September 30,
 20192018 20192018
 (In millions, except per share amounts, shares in thousands)
Revenues:     
Oil sales$882
$454
 $2,572
$1,334
Natural gas sales16
14
 36
40
Natural gas liquid sales58
57
 190
133
Lease bonus1
1
 4
2
Midstream services16
8
 51
27
Other operating income2
3
 7
7
Total revenues975
537
 2,860
1,543
Costs and expenses:     
Lease operating expenses128
49
 364
129
Production and ad valorem taxes61
33
 180
93
Gathering and transportation25
6
 54
17
Midstream services26
20
 60
49
Depreciation, depletion and amortization365
146
 1,046
391
General and administrative expenses19
14
 68
45
Asset retirement obligation accretion1
—
 6
1
Other operating expense1
1
 3
2
Total costs and expenses626
269
 1,781
727
Income from operations349
268
 1,079
816
Other income (expense):     
Interest expense, net(38)(19) (133)(49)
Other income, net2
2
 5
89
Gain (loss) on derivative instruments, net177
(48) 3
(139)
Gain on revaluation of investment—
—
 4
5
Total other income (expense), net141
(65) (121)(94)
Income before income taxes490
203
 958
722
Provision for income taxes102
43
 171
83
Net income388
160
 787
639
Net income attributable to non-controlling interest20
3
 60
100
Net income attributable to Diamondback Energy, Inc.$368
$157
 $727
$539
Earnings per common share:

 

Basic$2.27
$1.59
 $4.44
$5.47
Diluted$2.26
$1.59
 $4.42
$5.45
Weighted average common shares outstanding:     
Basic162,543
98,638
 164,070
98,603
Diluted162,780
98,818
 164,466
98,820
Dividends declared per share$0.1875
$0.125
 $0.5625
$0.375





See accompanying notes to condensed consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries
Condensed Consolidated Statements of Stockholders’ Equity
(Unaudited)


Common StockAdditional Paid-in CapitalRetained Earnings (Accumulated Deficit)Non-Controlling InterestTotal
SharesAmount
($ in millions, shares in thousands)
Balance December 31, 2019159,002 $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(75)— (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 units168 — 1 — — 1 
Net income (loss)— — — (272)(128)(400)
Balance March 31, 2020157,815 2 12,265 559 1,490 14,316 
Distribution equivalent rights payments— — — — (1)(1)
Stock-based compensation— — 11 — — 11 
Repurchased shares for tax withholding— — 0 — (2)(2)
Distribution to non-controlling interest— — — — (19)(19)
Dividend paid— — — (59)— (59)
Exercise of stock options and vesting of restricted stock units9 — 0 — — 0 
Change in ownership of consolidated subsidiaries, net— — 329 — (329)0 
Net income (loss)— — — (2,393)(18)(2,411)
Balance June 30, 2020157,824 2 12,605 (1,893)1,121 11,835 
Unit-based compensation— — — — 3 3 
Stock-based compensation— — 10 — — 10 
Repurchased shares for tax withholding(1)— 0 — — 0 
Distribution to non-controlling interest— — — — (15)(15)
Dividend paid— — — (59)— (59)
Exercise of stock options and vesting of restricted stock units27 — 0 — — 0 
Net income (loss)— — — (1,113)8 (1,105)
Balance September 30, 2020157,850 $2 $12,615 $(3,065)$1,117 $10,669 

 Common StockAdditional Paid-in CapitalRetained Earnings (Accumulated Deficit)Non-Controlling InterestTotal
 SharesAmount
 ($ in millions, shares in thousands)
Balance December 31, 2018164,273
$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 and unit options and awards of restricted stock468
—
—
—
—
—
Change in ownership of consolidated subsidiaries, net —
77
—
(74)3
Net income —
—
10
33
43
Balance March 31, 2019164,616
2
13,019
752
741
14,514
Net proceeds from issuance of common units - Rattler Midstream LP —
—
—
720
720
Unit-based compensation —
—
—
2
2
Stock-based compensation —
12
—
—
12
Repurchased shares for share buyback program(1,016)—
(104)—
—
(104)
Distribution to non-controlling interest —
—
—
(24)(24)
Dividend paid —
—
(32)—
(32)
Exercise of stock and unit options and awards of restricted stock349
—
6
—
—
6
Net income —
—
349
7
356
Balance June 30, 2019163,949
2
12,933
1,069
1,446
15,450
Unit-based compensation —
—
—
2
2
Stock-based compensation —
1
—
—
1
Repurchased shares for share buyback program(2,954)—
(296)—
—
(296)
Distribution to non-controlling interest —
—
—
(29)(29)
Dividend paid —
—
(30)—
(30)
Exercise of stock and unit options and awards of restricted stock147
—
3
—
—
3
Net income —
—
368
20
388
Balance September 30, 2019161,142
$2
$12,641
$1,407
$1,439
$15,489














See accompanying notes to condensed consolidated financial statements.

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Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Condensed Consolidated Statements of Stockholders’ Equity
(Unaudited)


Common StockAdditional Paid-in CapitalRetained Earnings (Accumulated Deficit)Non-Controlling InterestTotal
SharesAmount
($ in millions, shares in thousands)
Balance December 31, 2018164,273 $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 units468 — 0 — — 0 
Change in ownership of consolidated subsidiaries, net— — 77 — (74)3 
Net income (loss)— — — 10 33 43 
Balance March 31, 2019164,616 2 13,019 752 741 14,514 
Net proceeds from issuance of common units - Viper Energy Partners LP— — — — 720 720 
Unit-based compensation— — — — 2 2 
Stock-based compensation— — 12 — — 12 
Repurchased shares for share buyback program(1,016)— (104)— — (104)
Distribution to non-controlling interest— — — — (24)(24)
Dividend paid— — — (32)— (32)
Exercise of stock options and vesting of restricted stock units349— 6 — — 6 
Net income (loss)— — — 349 7 356 
Balance June 30, 2019163,949 2 12,933 1,069 1,446 15,450 
Unit-based compensation— — — — 2 2 
Stock-based compensation— — 1 — — 1 
Repurchased shares for share buyback program(2,954)— (296)— — (296)
Distribution to non-controlling interest— — — — (29)(29)
Dividend paid— — — (30)— (30)
Exercise of stock options and vesting of restricted stock units147 — 3 — — 3 
Net income (loss)— — — 368 20 388 
Balance September 30, 2019161,142$2 $12,641 $1,407 $1,439 $15,489 


 Common StockAdditional Paid-in CapitalRetained Earnings (Accumulated Deficit)Non-Controlling InterestTotal
 SharesAmount
 ($ in millions, shares in thousands)
Balance December 31, 201798,167
$1
$5,291
$(37)$327
$5,582
Impact of adoption of ASU 2016-01, net of tax —
—
(9)(7)(16)
Unit-based compensation

—
—
—
1
1
Stock-based compensation

—
9
—
—
9
Distribution to non-controlling interest

—
—
—
(19)(19)
Exercise of stock options and vesting of restricted stock units443
—
—
—
—
—
Net income

—
—
163
15
178
Balance March 31, 201898,610
1
5,300
117
317
5,735
Unit-based compensation —
—
—
1
1
Stock-based compensation —
7
—
—
7
Distribution to non-controlling interest —
—
—
(19)(19)
Dividend paid —
—
(13)—
(13)
Exercise of stock options and vesting of restricted stock units10
—
—
—
—
—
Net income —
—
219
82
301
Balance June 30, 201898,620
1
5,307
323
381
6,012
Net proceeds from issuance of common units - Viper Energy Partners LP —
—
—
303
303
Stock-based compensation —
8
—
—
8
Distribution to non-controlling interest —
—
—
(31)(31)
Dividend paid —
—
(12)—
(12)
Exercise of stock options and vesting of restricted stock units54
—
—
—
—
—
Change in ownership of consolidated subsidiaries, net —
150
—
(160)(10)
Net income —
—
157
3
160
Balance at September 30, 201898,674
$1
$5,465
$468
$496
$6,430


















See accompanying notes to condensed consolidated financial statements.

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Table of Contents
Diamondback Energy, Inc. and Subsidiaries
Condensed Consolidated Statements of Cash Flows
(Unaudited)

Nine Months Ended September 30,
20202019
(In millions)
Cash flows from operating activities:
Net income (loss)$(3,916)$787 
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Provision for (benefit from) deferred income taxes(902)171 
Impairment of oil and natural gas properties4,999 0 
Depreciation, depletion and amortization1,036 1,046 
(Gain) loss on derivative instruments, net(82)(3)
Cash received on settlement of derivative instruments288 33 
Other68 34 
Changes in operating assets and liabilities:
Accounts receivable265 (116)
Accounts payable and accrued liabilities(18)(136)
Accrued interest34 (29)
Revenues and royalties payable(59)64 
Other2 1 
Net cash provided by (used in) operating activities1,715 1,852 
Cash flows from investing activities:
Drilling, completions and non-operated additions to oil and natural gas properties(1,404)(1,883)
Infrastructure additions to oil and natural gas properties(96)(104)
Additions to midstream assets(133)(186)
Acquisitions of leasehold interests(89)(311)
Acquisitions of mineral interests(65)(320)
Proceeds from sale of assets2 301 
Contributions to equity method investments(90)(225)
Distributions from equity method investments27 0 
Other(7)(16)
Net cash provided by (used in) investing activities(1,855)(2,744)
Cash flows from financing activities:
Proceeds from borrowings under credit facility917 1,409 
Repayments under credit facility(1,238)(1,168)
Proceeds from senior notes997 0 
Repayment of senior notes(239)0 
Proceeds from joint venture47 42 
Public offering costs0 (40)
Proceeds from public offerings0 1,106 
Repurchased shares as part of share buyback(98)(400)
Dividends to stockholders(177)(82)
Distributions to non-controlling interest(77)(79)
Other(21)(11)
Net cash provided by (used in) financing activities111 777 
Net increase (decrease) in cash and cash equivalents(29)(115)
Cash, cash equivalents and restricted cash at beginning of period128 215 
Cash, cash equivalents and restricted cash at end of period$99 $100 
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized interest$100 $115 
Accrued capital expenditures$352 $560 

 Nine Months Ended September 30,
 20192018
   
 (In millions)
Cash flows from operating activities:  
Net income$787
$639
Adjustments to reconcile net income to net cash provided by operating activities:  
Provision for deferred income taxes171
83
Asset retirement obligation accretion6
1
Depreciation, depletion and amortization1,046
391
Amortization of debt issuance costs4
2
Change in fair value of derivative instruments30
24
Income from equity investment1
—
Gain on revaluation of investment(4)(5)
Equity-based compensation expense27
18
Loss on sale of assets, net—
3
Changes in operating assets and liabilities:  
Accounts receivable(116)(21)
Inventories(8)(14)
Prepaid expenses and other8
(6)
Accounts payable and accrued liabilities(136)18
Accrued interest(29)13
Income tax payable1
—
Revenues and royalties payable64
7
Net cash provided by operating activities1,852
1,153
Cash flows from investing activities:  
Drilling, completions and non-operated additions to oil and natural gas properties(1,883)(900)
Infrastructure additions to oil and natural gas properties(104)(110)
Additions to midstream assets(186)(130)
Purchase of other property, equipment and land(8)(2)
Acquisition of leasehold interests(311)(186)
Acquisition of mineral interests(320)(336)
Proceeds from sale of assets301
7
Investment in real estate(1)(111)
Funds held in escrow(7)(51)
Equity investments(225)—
Net cash used in investing activities(2,744)(1,819)
Cash flows from financing activities:  
Proceeds from borrowings under credit facility1,409
1,028
Repayment under credit facility(1,168)(1,222)
Proceeds from senior notes—
1,062
Proceeds from joint venture42
—
Debt issuance costs(7)(14)
Public offering costs(40)(3)
Proceeds from public offerings1,106
306
Proceeds from exercise of stock options9
—
Repurchased shares for tax withholdings(13)—
Repurchased as part of share buyback(400)—
Dividends to stockholders(82)(25)
Distributions to non-controlling interest(79)(69)

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Diamondback Energy, Inc. and Subsidiaries
Consolidated Statements of Cash Flows - Continued
(Unaudited)

 Nine Months Ended September 30,
 20192018
   
Net cash provided by financing activities777
1,063
Net (decrease) increase in cash and cash equivalents(115)397
Cash and cash equivalents at beginning of period215
112
Cash and cash equivalents at end of period$100
$509
   
Supplemental disclosure of cash flow information:  
Interest paid, net of capitalized interest$115
$52
Supplemental disclosure of non-cash transactions:  
Change in accrued capital expenditures$(68)$71
Capitalized stock-based compensation$9
$7
Asset retirement obligations acquired$3
$—








































See accompanying notes to condensed consolidated financial statements.

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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements
(Unaudited)



1.    DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION

Organization and Description of the Business

Diamondback Energy, Inc., together with its subsidiaries (collectively referred to as “Diamondback” or the “Company” unless the context otherwise requires), is an independent oil and 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 September 30, 2019,2020, 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, (formerly known as Rattler Midstream Partners LP), a Delaware limited partnership, (“Rattler”), Rattler Midstream Operating LLC, (formerly known as Rattler Midstream LLC), a Delaware limited liability company, (“Rattler LLC”), Rattler LLC’s wholly-owned subsidiarysubsidiaries Tall City Towers LLC, a Delaware limited liability company (“Tall City”), Rattler Ajax Processing LLC, a Delaware limited liability company, Rattler OMOG LLC, a Delaware limited liability company, and Energen’s wholly-owned subsidiaries Energen Resources Corporation, an Alabama corporation, and EGN Services, Inc., an Alabama corporation.

Basis of Presentation

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

Viper isand Rattler are consolidated in the financial statements of the Company. As of September 30, 2019,2020, the Company owned approximately 54%58% of Viper’s total units outstanding. The Company’s wholly-owned subsidiary, Viper Energy Partners GP LLC, is the general partner of Viper. Immediately following the completion of the Drop-Down on October 1, 2019, the Company owned 731,500 common units and 90,709,946 Class B units, representing approximately 60% of Viper’s total units outstanding. See Note 4—Acquisitions and Divestitures and Note 20—Subsequent Events for additional information regarding this transaction.

Rattler is consolidated in the financial statements of the Company. As of September 30, 2019,2020, 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. The results of operations attributable to the non-controlling interest in Viper and Rattler are presented within equity and net income and are shown separately from the Company’s equity and net income attributable to the Company.

These condensed consolidated financial statements have been prepared by the Company without audit, pursuant to the rules and regulations of the SEC. They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been omitted pursuant to suchSEC 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, 2018,2019, 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

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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)

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 is particularly difficult as the oil and natural gas industry experiences challenges resulting from negative pricing pressure from the effects of COVID-19 and actions by OPEC members and other exporting nations on the supply and demand in global oil and gas markets. Companies in the oil and gas industry have changed near term business plans in response to changing market conditions. The aforementioned circumstances generally increase the uncertainty in the Company’s accounting estimates, particularly those involving financial forecasts.

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

ReclassificationsAccounts Receivable

Certain prior period amounts have been reclassifiedAccounts receivable consist of receivables from joint interest owners on properties the Company operates and from sales of oil and natural gas production delivered to conformpurchasers. The purchasers remit payment for production directly to the 2019 presentation. These reclassifications had no impact on net income, total assets, liabilities and stockholders’ equity or total cash flows.Company. Most payments for production are received within three months after the production date.

Investments

Equity investments in which the Company exercises significant influence but does not control are accounted for using the equity method. Under the equity method, generally the Company’s share of investees’ earnings or loss is recognized in the statement of operations. The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, the Company would recognize an impairment provision.

Viper has an equity interest in a limited partnership that is so minor that Viper has no influence over the limited partnership’s operating and financial policies. This interest was acquired during the year ended December 31, 2014 and was accounted for under the cost method. Effective January 1, 2018, Viper adopted Accounting Standards Update (“ASU”) 2016-01 which requires Viper2016-13 and the subsequent applicable modifications to measurethe rule on January 1, 2020. Accounts receivable are stated at amounts due from joint interest owners or purchasers, net of an allowance for expected losses as estimated by the Company when collection is deemed doubtful. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable from joint interest owners or purchasers outstanding longer than the contractual payment terms are considered past due. The Company determines its investment at fair value which resultedallowance 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 downward adjustment of $19 million to record the impact of this adoption. See Note 17—Fair Value Measurements.

New Accounting Pronouncements

Recently Adopted Pronouncements

In February 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Company enters into lease agreements to support its operations. These agreements are for leases on assets such as office space, vehicles and compressors. The Company has completed the process of reviewing and determining the agreements to which this new guidance applies. Upon adoption effective January 1, 2019, the Company recognized approximately $13 million of right-of-use assets, of which the total amount relatesmaterial change to the Company’s operating leases.allowance. At September 30, 2020 and December 31, 2019, the Company recorded an immaterial allowance for expected losses.

In January 2018,Non-controlling Interest

Non-controlling interest in the FASB issued ASU 2018-01, “Leases - Land Easement Practical Expedient for Transitionaccompanying condensed consolidated financial statements represents minority interest ownership in Viper and Rattler. When the Company’s relative ownership interests in Viper and Rattler change, adjustments to Topic 842”. This update applies to any entity that holds land easements. The update allows entities to adoptnon-controlling interest and additional paid-in-capital, tax effected, will occur. Because these changes in the ownership interests in Viper and Rattler do not result in a practical expedient to not evaluate existing or expired land easements under Topic 842 that were not previouslychange of control, the transactions are accounted for as leasesequity transactions under ASC Topic 810, Consolidation, which requires that any differences between the current leases guidance. An entitycarrying value of the Company’s basis in Viper and Rattler and the fair value of the consideration received are recognized directly in equity and attributed to the controlling interest.

In the second quarter of 2020, the Company recorded an adjustment to non-controlling interest for Rattler of $(329) million and to additional paid-in-capital of $329 million to reflect the ownership structure that elects this practical expedient should evaluate new or modified land easements under Topic 842 beginningwas effective at the date that the entity adopts Topic 842.June 30, 2020. The Company adopted this standard effective January 1, 2019. The adoption of this update did not have anadjustment had no impact on its financial position, resultsearnings. See Note 11—Capital Stock and Earnings Per Share for a presentation of operations or liquidity.the change in ownership.


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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)

Recent Accounting Pronouncements
In July 2018, the FASB issued ASU 2018-10, “Codification Improvements to Topic 842, Leases”. This update provides clarification and corrects unintended application of certain sections in the new lease guidance.
The Company adopted this standard effective January 1, 2019.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 adoptionfollowing table provides a brief description of this update did not have an impactrecent accounting pronouncements and the Company’s analysis of the effects on its financial position, results of operations or liquidity.statements:
StandardDescriptionDate of AdoptionEffect 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 2020The 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.
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 2021This 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.
In July 2018, the FASB issued ASU 2018-11, “Leases (Topic 842): Targeted Improvements”. This update provides another transition method of allowing entities to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The Company adopted this standard effective January 1, 2019. The adoption of this update did not have an impact on its financial position, results of operations or liquidity.

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

See Note 18—Leases for more information on the adoption of these standards.

In June 2018, the FASB issued ASU 2018-07, “Stock Compensation - Improvements to Nonemployee Share-Based Payment Accounting”. This update applies the existing employee guidance to nonemployee share-based transactions, with the exception of specific guidance related to the attribution of compensation cost. The Company adopted this standard effective January 1, 2019. The adoption of this update did not have an impact on its financial position, results of operations or liquidity because the Company currently accounts for nonemployee share-based transactions in the same manner as employee share-based transactions.

In July 2018, the FASB issued ASU 2018-09, “Codification Improvements”. This update provides clarification and corrects unintended application of the guidance in various sections. The Company adopted this standard effective January 1, 2019. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity.

In July 2019, the FASB issued ASU 2019-07, “Codification Updates to SEC Sections”. This update simplifies the guidance in various sections that was duplicative, redundant or outdated. The Company adopted this update effective July 2019. It did not have a material impact on its financial position, results of operations or liquidity.

Accounting Pronouncements Not Yet Adopted

In June 2016, the FASB issued 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. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company believes the adoption of this update will not have an impact on its financial position, results of operations or liquidity since it does not have a history of credit losses.

In August 2018, the FASB issued 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. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied prospectively. The Company believes the adoption of this update will not have an impact on its financial position, results of operations or liquidity.

In August 2018, the FASB issued 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

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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)

That Is a Service Contract”. This update requires the capitalization of implementation costs incurred in a hosting arrangement that is a service contract for internal-use software. Training and certain data conversion costs cannot be capitalized. The entity is required to expense the capitalized implementation costs over the term of the hosting agreement. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update should be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. The Company believes the adoption of this update will not have an impact on its financial position, results of operations or liquidity.

In November 2018, the FASB issued ASU 2018-19, “Codification Improvements to Topic 326, Financial Instruments-Credit Losses”. This update clarifies that receivables arising from operating leases are not within the scope of this topic, but rather Topic 842, Leases. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. The Company believes the adoption of this update will not have an impact on its financial position, results of operations or liquidity since it does not have a history of credit losses.

In April 2019, the FASB issued ASU 2019-04, “Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives and Hedging, and Topic 825, Financial Instruments ”. This update clarifies guidance previously issued in ASU 2016-01, ASU 2016-13 and ASU 2017-12. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. The Company does not believe the updates to the referenced standards will have an impact on its financial position, results of operations or liquidity.

In May 2019, the FASB issued 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. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. The Company does not believe the adoption of this standard will have an impact on its financial position, results of operations or liquidity.

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 infollowing tables present the Company’s consolidated statements of operations.revenue from contracts with customers disaggregated by product type and basin:

Natural gas and natural gas liquids sales
Three Months Ended September 30, 2020Three Months Ended September 30, 2019
Midland BasinDelaware BasinOtherTotalMidland BasinDelaware BasinOtherTotal
(in millions)
Oil sales$348 $257 $1 $606 $529 $350 $3 $882 
Natural gas sales19 17 0 36 7 8 1 16 
Natural gas liquid sales36 28 1 65 33 25 0 58 
Total$403 $302 $2 $707 $569 $383 $4 $956 

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

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Nine Months Ended September 30, 2020Nine Months Ended September 30, 2019
Midland BasinDelaware BasinOtherTotalMidland BasinDelaware BasinOtherTotal
(in millions)
Oil sales$1,030 $750 $5 $1,785 $1,561 $951 $60 $2,572 
Natural gas sales32 29 0 61 17 18 1 36 
Natural gas liquid sales88 67 1 156 110 78 2 190 
Total$1,150 $846 $6 $2,002 $1,688 $1,047 $63 $2,798 
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.

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

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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 and nine months ended September 30, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Company believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the revenue related to expected sales volumes and prices for those properties are estimated and recorded.

4.    ACQUISITIONS AND DIVESTITURES

2019 Activity

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

On May 23, 2019, the Company completed its divestiture of 6,589 net acres of certain conventional and non-core Permian assets, which were acquired by the Company in its merger with Energen, (as described below), for an aggregate sale price of $37 million. This divestiture did 0tnot result in a gain or loss because it did not have a significant effect on the Company’s reserve base or depreciation, depletion and amortization rate.

On July 1, 2019, the Company completed its divestiture of 103,750 net acres of certain conventional and non-core Permian assets, which were acquired by the Company in the merger with Energen, (as described below), for an aggregate sale price of $285 million. This divestiture did 0tnot result in a gain or loss because it did not have a significant effect on the Company’s reserve base or depreciation, depletion and amortization rate.

2019 Drop-Down Transaction

On July 29, 2019, the Company entered into a definitive purchase agreement to divest certain mineral and royalty interests to Viper for approximately 18.3 million of Viper’s newly-issued Class B units, approximately 18.3 million newly-issued units of Viper LLC with a fair value of $497 million and $190 million in cash, after giving effect to closing adjustments for net title benefits (the “Drop-Down”). Based on the volume weighted average sales price of Viper’s common units for the ten trading-day period ended July 26, 2019 of $30.07, the transaction is valued at $740 million. The mineral and royalty interests being divested in the Drop-Down represent approximately 5,490 net royalty acres across the Midland and Delaware Basins, of which over 95% are operated by the Company, and have an average net royalty interest of approximately 3.2% (the “Drop-Down Assets”). The Drop-Down closed on October 1, 2019 and was effective as of July 1, 2019. Viper funded the cash portion of the purchase price of the Drop-Down Assets through a combination of cash on hand and borrowings under Viper LLC’s revolving credit facility.
2018 Activity

Tall City Towers LLC

On January 31, 2018, Tall City, a subsidiary of the Company, completed its acquisition of the Fasken Center office buildings in Midland, TX where the Company’s corporate offices are located for a net purchase price of $110 million.

Ajax Resources, LLC

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

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Down Transaction”), borrowing under the Company’s revolving credit facility and a portion of the proceeds from the Company’s September 2018 senior note offering. See Note 11—Debt for information relating to this offering.

2018 Drop-Down Transaction

On August 15, 2018, the Company completed a transaction to sell to Viper mineral interests underlying 32,424 gross (1,696 net royalty) acres primarily in Pecos County, Texas, in the Permian Basin, approximately 80% of which are operated by the Company, for $175 million.
ExL Petroleum Management, LLC and EnergyQuest II LLC

On October 31, 2018, the Company completed its acquisitions of leasehold interests and related assets, one with ExL Petroleum Management, LLC and ExL Petroleum Operating, Inc. and one with EnergyQuest II LLC, for an aggregate of approximately 3,646 net leasehold acres in the Northern Midland Basin for a total of $313 million in cash. These transactions were effective as of August 1, 2018 and were funded through a combination of cash on hand, proceeds from the sale of assets to Viper (described immediately above) and borrowing under the Company’s revolving credit facility.

Energen Corporation Merger

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

In connection with the closing of the Merger, the Company repaid outstanding principal under Energen’s revolving credit facility and assumed all of Energen’s other long-term debt. See Note 11—Debt for additional information.

Purchase Price Allocation

The Merger has been accounted for as a business combination, using the acquisition method. The following table represents the preliminary allocation of the total purchase price of Energen to the identifiable assets acquired and the liabilities assumed based on the fair values on the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired. Certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, valuation of pre-acquisition contingencies, final tax returns that provide the underlying tax basis of Energen’s assets and liabilities and final appraisals of assets acquired and liabilities assumed. The Company will complete the purchase price allocation during the fourth quarter of 2019.


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The following table sets forth the Company’s preliminary purchase price allocation as of September 30, 2019:
 (In millions)
Consideration: 
Fair value of the Company's common stock issued$7,136
Total consideration$7,136
  
Fair value of liabilities assumed: 
Current liabilities$377
Asset retirement obligation105
Long-term debt1,099
Noncurrent derivative instruments17
Deferred income taxes1,408
Other long-term liabilities7
Amount attributable to liabilities assumed$3,013
  
Fair value of assets acquired: 
Total current assets$311
Oil and natural gas properties9,313
Midstream assets263
Investment in real estate11
Other property, equipment and land55
Asset retirement obligation105
Other postretirement assets3
Noncurrent income tax receivable, net76
Other long term assets12
Amount attributable to assets acquired$10,149


Pro Forma Financial Information

The following unaudited summary pro forma consolidated statement of operations data of Diamondback for the three and nine months ended September 30, 2018 have been prepared to give effect to the Merger as if it had occurred on January 1, 2018. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for Energen’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the Company’s common stock issued to convert Energen’s outstanding shares of common stock and equity awards as of the closing date of the Merger, (ii) the depletion of Energen’s fair-valued proved oil and natural gas properties and (iii) the estimated tax impacts of the pro forma adjustments.

The pro forma results of operations do not include any cost savings or other synergies that may result from the Merger or any estimated costs that have been or will be incurred by the Company to integrate the Energen assets. The pro forma financial data does not include the results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material.


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The pro forma consolidated statement of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Merger taken place on January 1, 2018 and is not intended to be a projection of future results.
 Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018
 (in millions, except per share amounts)
Revenues$919
 $2,655
Income from operations$431
 $1,280
Net income$156
 $727
Basic earnings per common share$0.97
 $4.50
Diluted earnings per common share$0.96
 $4.49


5.    VIPER ENERGY PARTNERS LP

Viper is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “VNOM”. Viper was formed by Diamondback on February 27, 2014, to, among other things, own, acquire and exploit oil and natural gas properties in North America. Viper is currently focused on oil and natural gas properties in the Permian Basin 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 September 30, 2019, the Company owned approximately 54% of Viper’s total units outstanding. Immediately following the completion of the Drop-Down on October 1, 2019, the Company owned 731,500 common units and 90,709,946 Class B units, representing approximately 60% of Viper’s total units outstanding. See Note 4—Acquisitions and Note 20—Subsequent Events for additional information regarding this transaction.

Equity Offering

On March 1, 2019, Viper completed an underwritten public offering of 10,925,000 common units, which included 1,425,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Following this offering, the Company owned approximately 54% of Viper’s total units then outstanding. Viper received net proceeds from this offering of approximately $341 million, after deducting underwriting discounts and commissions and estimated offering expenses. Viper used the net proceeds to purchase units of Viper LLC. Viper LLC in turn used the net proceeds to repay a portion of the outstanding borrowings under the revolving credit facility and finance acquisitions during the period.

As a result of this public offering and Viper’s issuance of unit-based compensation, the Company’s ownership percentage in Viper was reduced. During the nine months ended September 30, 2019, the Company recorded a $74 million decrease to non-controlling interest in Viper with an increase to additional paid-in capital, which represents the difference between the Company’s share of the underlying net book value in Viper before and after the respective Partnership common unit transactions, on the Company’s consolidated balance sheet.

Recapitalization,Tax Status Election and Related Transactions by Viper

In March 2018, Viper announced that the Board of Directors of Viper’s General Partner had unanimously approved a change of Viper’s federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election. In connection with making this election, on May 9, 2018 Viper (i) amended and restated its First Amended and Restated Partnership Agreement, (ii) amended and restated the First Amended and Restated Limited Liability Company Agreement of Viper LLC, (iii) amended and restated its existing registration rights agreement with the Company and (iv) entered into an exchange agreement with the Company, Viper’s General Partner and Viper LLC. Simultaneously with the effectiveness of these agreements, the Company delivered and assigned to Viper the 73,150,000 common units the Company owned in exchange for (i) 73,150,000 of Viper’s newly-issued Class B units and (ii) 73,150,000 newly-issued units of Viper LLC pursuant to the terms of a Recapitalization Agreement dated March 28, 2018, as amended as of May 9, 2018 (the “Recapitalization Agreement”). Immediately following that exchange, Viper continued to be the managing member of Viper LLC, with sole control of its operations, and owned approximately 36% of the outstanding units issued by Viper LLC, and the Company owned the remaining approximately 64% of the outstanding units issued by Viper LLC. Upon completion of Viper’s July 2018 offering of units, it owned

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approximately 41% of the outstanding units issued by Viper LLC and the Company owned the remaining approximately 59%. Viper LLC units and Viper’s Class B units owned by the Company are exchangeable from time to time for Viper’s common units (that is, 1 Viper LLC unit and 1 Viper Class B unit, together, will be exchangeable for 1 Viper common unit).

On May 10, 2018, the change in Viper’s income tax status became effective. On that date, pursuant to the terms of the Recapitalization Agreement, (i) Viper’s General Partner made a cash capital contribution of $1 million to Viper in respect of its general partner interest and (ii) the Company made a cash capital contribution of $1 million to Viper in respect of the Class B units. The Company, as the holder of the Class B units, and Viper’s General Partner, as the holder of the general partner interest, are entitled to receive an 8% annual distribution on the outstanding amount of these capital contributions, payable quarterly, as a return on this invested capital. On May 10, 2018, the Company also exchanged 731,500 Class B units and 731,500 units in Viper LLC for 731,500 common units of Viper and a cash amount of $10,000 representing a proportionate return of the $1 million invested capital in respect of the Class B units. Viper’s General Partner continues to serve as Viper’s general partner and the Company continues to control Viper. After the effectiveness of the tax status election and the completion of related transactions, Viper’s minerals business continues to be conducted through Viper LLC, which continues to be taxed as a partnership for federal and state income tax purposes. This structure is anticipated to provide significant benefits to Viper’s business, including operational effectiveness, acquisition and disposition transactional planning flexibility and income tax efficiency. For additional information regarding the tax status election and related transactions, please refer to Viper’s Definitive Information Statement on Schedule 14C filed with the SEC on April 17, 2018 and Viper’s Current Report on Form 8-K filed with the SEC on May 15, 2018.

Partnership Agreement

The second amended and restated agreement of limited partnership, dated as of May 9, 2018, as amended as of May 10, 2018 (the “Viper Partnership Agreement”), requires Viper to reimburse Viper’s General Partner for all direct and indirect expenses incurred or paid on Viper’s behalf and all other expenses allocable to Viper or otherwise incurred by Viper’s General Partner in connection with operating Viper’s business. The Viper Partnership Agreement does not set a limit on the amount of expenses for which Viper’s General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for Viper or on its behalf and expenses allocated to Viper’s General Partner by its affiliates. Viper’s General Partner is entitled to determine the expenses that are allocable to Viper. For each of the three months ended September 30, 2019 and 2018, Viper’s General Partner allocated $1 million to Viper. For each of the nine months ended September 30, 2019 and 2018, Viper’s General Partner allocated $2 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 and nine months ended September 30, 2019 and the three months and nine months ended September 30, 2018, 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 11—Debt for a description of this credit facility.


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6.    RATTLER MIDSTREAM LP

Rattler is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “RTLR”.“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 September 30, 2019,2020, Diamondback owned approximately 71% of Rattler’s total units outstanding.

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

In connection with the completion of Rattler’s initial public offering (the “Rattler Offering”),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
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entitled to receive cash preferred distributions equal to 8% per annum on the outstanding amount of their respective $1 million capital contributions, payable quarterly.

Diamondback has also entered into
6.    REAL ESTATE ASSETS    

The following schedule presents the cost and related accumulated depreciation of the Company’s real estate assets. The Company’s intangible lease assets and related accumulated amortization were immaterial as of September 30, 2020 and December 31, 2019.
Estimated Useful LivesSeptember 30, 2020December 31, 2019
(Years)(in millions)
Buildings20-30$102 $102 
Tenant improvements155 5 
LandN/A2 2 
Land improvements151 1 
Total real estate assets110 110 
Less: accumulated depreciation(12)(9)
Total investment in land and buildings, net$98 $101 

7.    PROPERTY AND EQUIPMENT

Property and equipment includes the following agreements with Rattler:

Rattler’s Partnership Agreement

In connection with the closingas of the Rattler Offering, Rattler’s General Partnerdates indicated:
September 30,December 31,
20202019
(in millions)
Oil and natural gas properties:
Subject to depletion$19,426 $16,575 
Not subject to depletion7,879 9,207 
Gross oil and natural gas properties27,305 25,782 
Accumulated depletion(3,988)(2,995)
Accumulated impairment(6,933)(1,934)
Oil and natural gas properties, net16,384 20,853 
Midstream assets1,026 931 
Other property, equipment and land135 125 
Accumulated depreciation(110)(74)
Total property and equipment, net$17,435 $21,835 

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 proved oil and Energen Resources Corporation entered intonatural gas properties. As a result of the sharp decline in commodity prices which began during the first amendedquarter of 2020 and restated agreementcontinued for most of limited partnershipthe second and third quarters of Rattler, dated May 28, 2019 (the “Rattler Partnership Agreement”). The Rattler Partnership Agreement requires Rattler to reimburse Rattler’s General Partner2020, the Company recorded non-cash ceiling test impairments 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 and nine months ended September 30, 2019,2020 of $1.5 billion and $5.0 billion, respectively, which were included in accumulated depletion. The impairment charge affected the General Partner allocated $225,030Company’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 $262,937, respectively, of such expensesother factors will determine its actual ceiling test calculation and impairment analysis in future periods. If the trailing 12-month commodity prices continue 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, datedfall as of May 28, 2019 (the “Services and Secondment Agreement”). Pursuantcompared to the Servicescommodity prices used in prior quarters, the Company may have material write downs in subsequent quarters. NaN impairment on proved oil 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 Diamondbacknatural gas properties was recorded for the cost of the seconded employees and contractors, including their wages and benefits. For the three months andor nine months ended September 30, 2019, Rattler’s General Partner2019. Given the rate of change impacting the oil and Rattler paid Diamondback $1 million and $3 million, respectively, under the Services and Secondment Agreement.

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.
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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 and nine months ended September 30, 2019, Rattler accrued state income tax expense of $75,944 and $107,758, respectively, for its share of Texas margin tax for which Rattler’s share of Rattler LLC’s results are included in a combined tax return filed by Diamondback.

Other Agreements

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

7.    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:
 Estimated Useful Lives September 30, 2019 December 31, 2018
 (Years) (in millions)
Buildings30 $102
 $103
Tenant improvements15 5
 4
LandN/A 2
 1
Land improvements15 1
 1
Total real estate assets  110
 109
Less: accumulated depreciation  (8) (4)
Total investment in land and buildings, net  $102
 $105

 Weighted Average Useful Lives September 30, 2019 December 31, 2018
 (Months) (in millions)
In-place lease intangibles45 $11
 $11
Less: accumulated amortization  (5) (3)
In-place lease intangibles, net  6
 8
      
Above-market lease intangibles45 4
 4
Less: accumulated amortization  (1) (1)
Above-market lease intangibles, net  3
 3
Total intangible lease assets, net  $9
 $11



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8.    PROPERTY AND EQUIPMENT

Property and equipment includes the following:
 September 30,December 31,
 20192018
   
 (in millions)
Oil and natural gas properties:  
Subject to depletion$15,358
$12,629
Not subject to depletion9,464
9,670
Gross oil and natural gas properties24,822
22,299
Accumulated depletion(2,605)(1,599)
Accumulated impairment(1,144)(1,144)
Oil and natural gas properties, net21,073
19,556
Midstream assets884
700
Other property, equipment and land152
147
Accumulated depreciation(66)(31)
Property and equipment, net of accumulated depreciation, depletion, amortization and impairment$22,043
$20,372
   
Balance of costs not subject to depletion:  
Incurred in 2019$513
 
Incurred in 20185,844
 
Incurred in 20172,438
 
Incurred in 2016669
 
Total not subject to depletion$9,464
 


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 $8$14 million and $6$8 million for the three months ended September 30, 20192020 and 2018,2019, respectively, and $32$42 million and $20$32 million for the nine months ended September 30, 20192020 and 2018,2019, 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 three years to five years. Acquisition costs not currently being amortized are primarily related to unproved acreage that the Company plans to prove up through drilling. The Company has no plans to let any of the acreage, expire. Sales of oil and natural gas properties, whether orassociated with acquisition costs not currently being amortized, currently, are accountedexpire based on current drilling plans.

8.    ASSET RETIREMENT OBLIGATIONS

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

Nine Months Ended September 30,
20202019
(in millions)
Asset retirement obligations, beginning of period$94 $136 
Additional liabilities incurred12 6 
Liabilities acquired3 3 
Liabilities settled(1)(61)
Accretion expense5 6 
Asset retirement obligations, end of period113 90 
Less current portion(1)
1 0 
Asset retirement obligations - long-term$112 $90 
Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter.(1) The test determines a limit, or ceiling, on the book valuecurrent portion of the proved oil and natural gas properties. Net capitalized costs are limited toasset retirement obligation is included in other accrued liabilities in the lowerCompany’s condensed consolidated balance sheets.

9.    EQUITY METHOD INVESTMENTS

The following table presents the carrying values of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is definedRattler’s equity method investments 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 excludingdates indicated:
Ownership InterestSeptember 30, 2020December 31, 2019
(in millions)
EPIC Crude Holdings, LP10 %$123 $110 
Gray Oak Pipeline, LLC10 %135 115 
Wink to Webster Pipeline LLC4 %75 34 
OMOG JV LLC60 %195 219 
Amarillo Rattler, LLC50 %4 1 
Total$532 $479 







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

the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required.

At September 30, 2019, there was $82 million in exploration costs and development costs and $102 million in capitalized interest that was not subject to depletion. At December 31, 2018, there were $68 million in exploration costs and development costs and $55 million in capitalized interest that was not subject to depletion.

9.    ASSET RETIREMENT OBLIGATIONS

The following table describespresents income (loss) from Rattler’s equity method investees reflected in the changes to the Company’s asset retirement obligation liabilityCondensed Consolidated Statement of Operations for the following periods:periods indicated:
 Nine Months Ended September 30,
 20192018
   
 (in millions)
Asset retirement obligations, beginning of period$136
$21
Additional liabilities incurred6
2
Liabilities acquired3
—
Liabilities settled(61)(1)
Accretion expense6
1
Revisions in estimated liabilities—
1
Asset retirement obligations, end of period90
24
Less current portion—
—
Asset retirement obligations - long-term$90
$24


Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(in millions)
EPIC Crude Holdings, LP$(2)$0 $(5)$0 
Gray Oak Pipeline, LLC4 0 6 0 
OMOG JV LLC1 0 (11)0 
Total$3 $0 $(10)$0 
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.

10.    EQUITY METHOD INVESTMENTS

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

On June 30, 2018, HMW LLC’s operating agreement was amended. As a result of the amendment, Rattler no longer recognizes an equity investment in HMW LLC but instead consolidates its undivided interest in the salt water disposal assets owned by HMW LLC. In exchange for Rattler’s 25% investment, Rattler received a 50% undivided ownership interest in 2 of the 4 SWD wells and associated assets previously owned by HMW LLC. Rattler’s basis in the assets is equivalent to its basis in the equity investment in HMW LLC.

On February 1, 2019, Rattler LLC obtainedacquired a 10% equity interest in EPIC Crude Holdings, LP (“EPIC”), which is buildingowns and operates a pipeline (the “EPIC project”pipeline”) that once fully operational, will transporttransports crude and NGLnatural gas liquids across Texas for delivery into the Corpus Christi market. As of September 30, 2019, Rattler’s total investment in the EPIC project was $89 million. During the nine months ended September 30, 2019, Rattler recorded net expenses of $532,800 related to the EPIC project. The EPIC project began initial operations during the third quarter of 2019.pipeline became fully operational in April 2020.

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


On February 15, 2019, Rattler LLC obtainedacquired a 10% equity interest in Gray Oak Pipeline, LLC (“Gray Oak”), which is buildingowns and operates a pipeline (the “Gray Oak project”pipeline”) that once operational, will transporttransports crude from the Permian to Corpus Christi on the Texas Gulf Coast. As of September 30, 2019, Rattler’s total investment in the Gray Oak project was $114 million. During the nine months ended September 30, 2019, Rattler recorded net expenses of $189,374 related to the Gray Oak project. The Gray Oak project is anticipated to bepipeline became fully operational in the fourth quarter of 2019.April 2020.

On March 29, 2019, Rattler LLC executed a short-term promissory note to Gray Oak. The note allowsallowed for borrowing by Gray Oak of up to $123 million at 2.52% interest rate with a maturity date of March 31, 2022. DuringThe short-term promissory note was repaid on May 31, 2019.

On June 4, 2019, Rattler entered into an equity contribution agreement with respect to Gray Oak. The equity contribution agreement required Rattler to contribute equity or make loans to Gray Oak so that Gray Oak can, to the three months endedextent 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 were limited to its proportionate ownership interest in Gray Oak, and such obligations were guaranteed by Rattler LLC, Tall City, Rattler OMOG LLC and Rattler Ajax Processing LLC. The equity contribution agreement and Rattler’s obligations under the agreement were terminated in September 30, 2019, there were 0 borrowings or repayments under this note. There were 0 outstanding loans at September 30, 2019.2020.

On July 30, 2019, Rattler LLC joined Wink to Webster Pipeline LLC as a 4% member, together with affiliates of ExxonMobil, Plains All American Pipeline, Delek US, MPLX LP and Lotus Midstream. The joint venture is developing a crude oil pipeline with origin points at Wink and Midland in the Permian Basin for delivery to multiple Houston area locations (the “Wink to Webster project”pipeline”). As of September 30, 2019, Rattler's total investment in the Wink to Webster project was $21 million. During the nine months ended September 30, 2019, Rattler recorded net income of $26,280 related to interest. The Wink to Webster projectpipeline is expected to begin service in the first half of 2021.

NaN impairments were recordedOn 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.

On December 20, 2019, Rattler LLC acquired a 50% equity interest in Amarillo Rattler, LLC (“Amarillo Rattler”), 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. Amarillo Rattler 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. However, development of the new processing plant has been postponed pending a recovery in commodity prices and activity levels. The Company has contracted for Rattler’s equity method investmentsup to 30,000 Mcf/d of the capacity of the new processing plant pursuant to a gas gathering and processing agreement entered into with Amarillo Rattler in exchange for the nine months ended September 30, 2019 or 2018.Company’s dedication of certain leasehold interests to that agreement.

At September 30, 2019, there was $124,301 of capitalized interest that was related to equity method investments that have not yet begun operations.

11.    DEBT

Long-term debt consisted of the following as of the dates indicated:
 September 30,December 31,
 20192018
   
 (in millions)
4.625% Notes due 2021(1)
$400
$400
7.320% Medium-term Notes, Series A, due 2022(1)
21
20
4.750 % Senior Notes due 20241,250
1,250
5.375 % Senior Notes due 2025800
800
7.350% Medium-term Notes, Series A, due 2027(1)
11
10
7.125% Medium-term Notes, Series B, due 2028(1)
108
100
DrillCo Agreement42
—
Unamortized debt issuance costs(22)(27)
Unamortized premium costs9
10
Revolving credit facility1,629
1,490
Viper revolving credit facility410
411
Rattler revolving credit facility103
—
Total long-term debt$4,761
$4,464

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


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

Rattler reviews its investments to determine if a loss in value which is other than temporary has occurred. If such a loss has occurred, Rattler recognizes an impairment provision. During the nine months ended September 30, 2020, Rattler’s loss from equity method investments includes a proportional charge of $16 million representing impairment recorded by the investee associated with its goodwill. During the three months and nine months ended September 30, 2020, Rattler’s loss from equity method investment includes an immaterial abandonment charge related to a project that is no longer expected to be completed. NaN other impairments were recorded for Rattler’s equity method investments for the three or nine months ended September 30, 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.
Diamondback Notes

2024 Senior Notes10.    DEBT

On October 28, 2016,Long-term debt consisted of the Company issued $500 million in aggregate principal amountfollowing as of 4.750% Senior Notes due 2024 (the “existing 2024 Senior Notes”). The existing 2024 Senior Notes bear interest at a ratethe dates indicated:
September 30,December 31,
20202019
(in millions)
4.625% Notes due 2021$191 $399 
7.320% Medium-term Notes, Series A, due 202220 21 
2.875% Senior Notes due 20241,000 1,000 
4.750% Senior Notes due 2025500 0 
5.375% Senior Notes due 2025800 800 
3.250% Senior Notes due 2026800 800 
7.350% Medium-term Notes, Series A, due 20270 11 
7.125% Medium-term Notes, Series B, due 2028100 108 
3.500% Senior Notes due 20291,200 1,200 
DrillCo Agreement86 39 
Unamortized debt issuance costs(30)(19)
Unamortized discount costs(28)(31)
Unamortized premium costs16 9 
Revolving credit facility(1)
0 13 
Viper revolving credit facility(1)
127 97 
Viper 5.375% Senior Notes due 2027480 500 
Rattler revolving credit facility(2)
85 424 
Rattler 5.625% Senior Notes due 2025500 0 
Total debt, net5,847 5,371 
Less: current maturities of long-term debt(191)0 
Total long-term debt$5,656 $5,371 
(1) Each of 4.750% per annum, payable semi-annually, in arrears on May 1 and November 1 of each year and will maturethese revolving credit facilities matures on November 1, 2024. All of the Company’s existing and future restricted subsidiaries that guarantee its2022.
(2) The Rattler revolving credit facility or certain other debt guarantee the existing 2024 Senior Notes; provided, however, that the existing 2024 Senior Notes are not guaranteed by Viper, Viper’s General Partner, Viper LLC, Rattler, Rattler’s General Partner or Rattler LLC, and will not be guaranteed by any of the Company’s future unrestricted subsidiaries.matures on May 28, 2024.

On September 25, 2018,References in this section to the Company issued $750 million aggregate principal amount of new 4.750% Senior Notes due 2024 (the “New 2024 Notes”), which together with the existing Senior Notes are referred to as the 2024 Senior Notes, as additional notes under,shall mean Diamondback Energy, Inc. and subject to the terms of, the 2024 Indenture. The New 2024 Notes were issued in a transaction exempt from the registration requirements under the Securities Act. The Company received approximately $741 million in net proceeds, after deducting the initial purchasers’ discount and its estimated offering expenses, but disregarding accrued interest, from the issuance of the New 2024 Notes. The Company used a portion of the net proceeds from the issuance of the New 2024 Notes to repay the outstanding borrowings under its revolving credit facility and used the balance for general corporate purposes, including funding a portion of the cash consideration for the acquisition of assets from Ajax Resources, LLC.Diamondback O&G LLC, collectively, unless otherwise specified.

The 2024 Senior Notes were issued under, and are governed by, an indenture among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented (the “2024 Indenture”). The 2024 Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit the Company’s ability and the ability of the restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make other distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting the Company’s restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and natural gas business and designate certain of the Company’s subsidiaries as unrestricted subsidiaries.

The Company may on any one or more occasions redeem some or all of the 2024 Senior Notes at any time on or after November 1, 2019 at the redemption prices (expressed as percentages of principal amount) of 103.563% for the 12-month period beginning on November 1, 2019, 102.375% for the 12-month period beginning on November 1, 2020, 101.188% for the 12-month period beginning on November 1, 2021 and 100.000% beginning on November 1, 2022 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to November 1, 2019, the Company may on any one or more occasions redeem all or a portion of the 2024 Senior Notes at a price equal to 100% of the principal amount of the 2024 Senior Notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to November 1, 2019, the Company may on any one or more occasions redeem the 2024 Senior Notes in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2024 Senior Notes issued prior to such date at a redemption price of 104.750%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings.

As required under the terms of the registration rights agreement relating to the New 2024 Notes, on March 22, 2019, the Company filed with the SEC its registration Statement on Form S-4, as amended on July 3, 2019 (the “Exchange Offer S-4”), relating to the exchange offer of the New 2024 Notes for substantially identical notes registered under the Securities Act of 1933, as amended. The Exchange Offer S-4 was declared effective by the SEC on July 11, 2019 and the Company closed the Exchange Offer on August 12, 2019.

2025 Senior Notes

On December 20, 2016, the Company issued $500 million in aggregate principal amount of 5.375% Senior Notes due 2025 (the “existing 2025 Senior Notes”). The existing 2025 Senior Notes bear interest at a rate of 5.375% per annum, payable semi-annually, in arrears on May 31 and November 30 of each year and will mature on May 31, 2025. All of the Company’s existing and future restricted subsidiaries that guarantee its revolving credit facility or certain

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

other debt guarantee the existing 2025May 2020 Senior Notes provided, however, that

On May 26, 2020, the existing 2025Company completed a notes offering of $500 million in aggregate principal amount of its 4.750% Senior Notes due 2025 (the “May 2020 Notes”). Interest on the May 2020 Notes accrues from May 26, 2020, and is payable in cash semi-annually on May 31 and November 30 of each year, beginning November 30, 2020. The May 2020 Notes mature on May 31, 2025. The Company received net proceeds of approximately $496 million from the offering of the May 2020 Notes. The May 2020 Notes are notthe Company’s senior unsecured obligations, and are guaranteed by Viper, Viper’s General Partner, ViperDiamondback O&G LLC Rattler, Rattler’s General Partner or Rattler LLC, and will(the “Guarantor”), but are not be guaranteed by any of the Company’s future unrestrictedother subsidiaries.
On January 29, 2018, the Company issued $300 million aggregate principal amount of new 5.375% Senior Notes due 2025 (the “New 2025 Notes”), which together with the existing 2025 Senior The May 2020 Notes are referredsenior in right or payment to as the 2025 Senior Notes, as additional notes under, and subject to the terms of, the 2025 Indenture. The New 2025 Notes were issued in a transaction exempt from the registration requirements under the Securities Act. The Company received approximately $308 million in net proceeds, after deducting the initial purchaser’s discount and its estimated offering expenses, but disregarding accrued interest, from the issuance of the New 2025 Notes. The Company used the net proceeds from the issuance of the New 2025 Notes to repay a portion of the outstanding borrowings under its revolving credit facility.
The 2025 Senior Notes were issued under an indenture, dated as of December 20, 2016, among the Company, the guarantors party thereto and Wells Fargo Bank, as the trustee (the “2025 Indenture”). The 2025 Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit the Company’s ability and the ability of the restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make other distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting the Company’s restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of its assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and natural gas business and designate certainany of the Company’s subsidiaries as unrestricted subsidiaries.

The Company may on any one or more occasions redeem some or all ofand 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, 2022Guarantor’s future subordinated indebtedness 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 pricerank equal to 100% of the principal amount of the 2025 Senior Notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to May 31, 2020, the Company may on any one or more occasions redeem the 2025 Senior Notes in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2025 Senior Notes issued prior to such date at a redemption price of 105.375%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings.

Energen Notes
At the effective time of the Merger, Energen became the Company’s wholly owned subsidiary and remained the issuer of $530 million aggregate principal amount of the Energen Notes, issued under an indenture dated September 1, 1996 with The Bank of New York as Trustee (the “Energen Indenture”). The Energen Notes consist of: (1) $400 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 of the Company, continues to be the sole issuer and obligor under the Energen Notes. The Energen Notes rank equally in right of payment with all other senior unsecured indebtedness of Energen, including any unsecured guaranties by Energen of the Company’s indebtedness and the Guarantor’s existing and future senior indebtedness. The May 2020 Notes are effectively subordinated to Energen’s seniorthe Company’s and the Guarantor’s existing and future secured indebtedness, including Energen’s secured guaranty of all borrowings and other obligations under the Company’s revolving credit facility,if any, to the extent of the value of the collateral securing such indebtedness.
The Energen Indenture contains certain covenants that, subjectindebtedness, and structurally subordinated to certain exceptionsall of the existing and qualifications, limit Energen’s ability to incur or suffer to exist liens, to enter into salefuture indebtedness and leaseback transactions, to consolidate with or merge into any other entity, and to convey, transfer or lease its properties and assets substantially as an entirety to any person or entity. The Energen Indenture does not include a restriction on the paymentliabilities of dividends.

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

On November 29, 2018, Energen guaranteed the Company’s indebtedness under its credit facilitysubsidiaries other than the Guarantor.

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

The Company and 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 the Company’s unsecured debt achieves an investment grade rating from two rating agencies and certain other conditions in the credit agreement are satisfied, (the “investment grade changeover date”). The maximum credit amount available under the credit agreement is $5 billion, subject, prior to the investment grade changeover date, to a borrowing base basedwhich changes became effective on the Company’s oil and natural gas reserves and other factors (the “borrowing base”) and the elected commitment amount. Prior to the investment grade changeover date, the borrowing base is scheduled to be redetermined, under certain circumstances, annually with an effective dateNovember 20, 2019. As of May 1st, and, under certain circumstances, semi-annually with effective dates of May 1st and November 1st. In addition, the Company and Wells Fargo each may request up to 2 interim redeterminations of the borrowing base during any 12-month period. On and after the investment grade changeover date,September 30, 2020, the maximum credit amount available under the credit agreement will be based solely on the commitments of the lenders, and will no longer be limited by the borrowing base. On the investment grade changeover date, the aggregate commitments of the lenders will be set at an amount equal to the aggregate elected commitment amount in effect on such date.was $2 billion. As of September 30, 2019, the borrowing base was set at $3.4 billion,2020, the Company had elected a commitment amount of $2.5 billion and the Company had approximately $1.6 billion of0 outstanding borrowings under its revolving credit facility and $0.9$2.0 billion available for future borrowings under itsthe revolving credit facility. As of September 30, 2020, there was an aggregate of $3 million in outstanding letters of credit, which reduce the amount available under the credit agreement on a dollar-for-dollar basis. The weighted average interest rate on the credit facility was 1.83% and 2.27% for the three months and nine months ended September 30, 2020, respectively.

As of September 30, 2020, the Company was in compliance with all financial maintenance covenants under the revolving credit facility.
Diamondback O&G LLC is
Energen’s Notes

Energen became a wholly owned subsidiary of the borrower underCompany at the credit agreement.effective time of the merger and remained the issuer of an aggregate principal amount of $530 million in notes (the “Energen Notes”). As of September 30, 2019,2020, the credit agreement is guaranteed byEnergen Notes consist of: (1) $191 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, and (3) $20 million of 7.32% notes due on July 28, 2022.
The Company used the net proceeds from the offering of May 2020 Notes, among other things, to make an equity contribution to Energen to purchase $209 million in previously outstanding aggregate principal amount of Energen’s 4.625% senior notes pursuant to a tender offer.
During the third quarter of 2020, the Company Diamondback E&P LLC and Energen and its subsidiaries and will also be guaranteed by anyrepurchased $10 million in principal amount of the Company’s future subsidiaries that are classified as restricted subsidiaries under the credit agreement. On and after the investment grade changeover date, the Company and Diamondback O&G LLC will no longer be required to cause all restricted subsidiaries to guarantee the credit agreement, and, in certain circumstances, may cause guaranties made by subsidiary guarantors to be released. Prior to the investment grade changeover date, the credit agreement is also secured by substantially alloutstanding Energen 7.350% medium-term notes due on July 28, 2027 at a price of 120% of the assetsaggregate principal amount, which resulted in an immaterial loss on extinguishment of the Company, Diamondback O&G LLC and the guarantors. On and after the investment grade changeover date, the credit agreement will be unsecured and all liens securing the credit facility will be released.
The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by the Company that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5%, and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. Prior to the investment grade changeover date, the applicable margin ranges from 0.25% to 1.25% in the case of the alternate base rate and from 1.25% to 2.25% in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the least of the maximum credit amount, the borrowing base and the elected commitment amount. On and after the investment grade changeover date, the applicable margin will range from 0.125% to 1.0% per annum in the case of the alternate 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’ rating of the Company’s unsecured debt. Prior to the investment grade changeover date, the Company is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. On and after the investment grade changeover date, the commitment fee will range from 0.125% to 0.350% per year on the unused portion of the commitment, based on the pricing level, which in turn depends on the rating agencies’ rating of the Company’s unsecured debt.
Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage). Prior to the investment grade changeover date, loan principal is required to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or

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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)

otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2022. On and after the investment grade changeover date, 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 various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.
Financial Covenant (prior to the investment grade changeover date)Required Ratio
Ratio of total net debt to EBITDAX, as defined in the credit agreementNot greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreementNot less than 1.0 to 1.0


The covenant prohibiting additional indebtedness, applicable prior to the investment grade changeover date, allows for the issuance of unsecured debt in the form of senior or senior subordinated notes if no default would result from the incurrence of such debt after giving effect thereto and if, in connection with any such issuance, the borrowing base is reduced by 25% of the stated principal amount of each such issuance.
On and after the investment grade changeover date, the financial covenants listed above will be replaced by a financial covenant that will require the Company to not permit the total net debt to capitalization ratio, as defined in the credit agreement, to exceed 65%. Additionally, on and after the investment grade changeover date, many of the negative covenants set forth in the credit agreement will no longer restrict the Company, Diamondback O&G LLC and their restricted subsidiaries (the “Restricted Group”), including the covenants that limit (i) equity repurchases, dividends and other restricted payments, (ii) redemptions of the senior or senior subordinated notes, (iii) making investments, (iv) dispositions of property, (v) transactions with affiliates, and (vi) entering into swap agreements. In addition, on and after the investment grade changeover date, (i) the debt covenant will no longer restrict incurrences of debt by Diamondback O&G LLC and guarantors, and will allow non-guarantor restricted subsidiaries to 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 (ii) the liens covenant will be modified to allow the Restricted Group to create liens if the aggregate amount of debt secured by such liens does not exceed 15% of consolidated net tangible assets.
On August 28, 2019, the Company, the borrower and certain of the Company’s subsidiaries (the “Loan Parties”) entered into a Consent Letter with Wells Fargo allowing the Loan Parties to enter into certain swap agreements in respect of interest rates for United States Treasury securities for an aggregate notional principal amount of up to $3 billion, subject to certain conditions set forth in the consent, which otherwise would be in excess of the notional principal amount of interest rate swap agreements permitted under the revolving credit facility immediately prior to the effectiveness of the consent. As of September 30, 2019, the borrower was party to interest rate swap agreements with an aggregate notional principal amount of $2 billion, interest rates ranging from 1.3565% to 2.1509% and maturity dates ranging from August 24, 2020 to December 31, 2050.

As of September 30, 2019 and December 31, 2018, the Company was in compliance with all financial covenants under its revolving credit facility, as then in effect. The lenders may accelerate all of the indebtedness under the Company’s revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.

Viper’s Credit Agreement

On July 20, 2018, Viper LLC, as guarantor,borrower, entered into an amended and restated credit agreement with Viper, LLC, as borrower,guarantor, Wells Fargo, as administrative agent, and the other lenders. The credit agreement, as amended to the date hereof,(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 $725 million, subject to scheduled

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

semi-annual and other elective borrowing base redeterminations.. The borrowing base is scheduled to be re-determinedredetermined semi-annually with effective dates ofin May 1st and November 1st.November. In addition, Viper LLC and Wells Fargo each may request up to 3 interim redeterminationsredeterminations of the borrowing base during any 12-month period. Upon closing of the Drop-Down on October 1, 2019, theThe borrowing base under Viper LLC’s revolving credit facility was increased byreduced from $775 million to $580 million during the regularly scheduled (semi-annual) spring 2020 redetermination in the second quarter of 2020, and is expected to be reaffirmed at $125580 million to $725 million from $600 million. In connection with the commencement of the Viper Notes Offering described in Note 20—Subsequent Events below, Viper entered into a third amendment to Viper LLC’s revolving credit facility with Wells Fargo, as administrative agent, and certain required lenders party thereto, which provides for the waiver of the automatic reduction of the borrowing base that would otherwise occur upon the consummation of the Viper Notes Offering. In addition, the third amendment increased the maximum amount of unsecured senior or senior subordinated notes that may be issued by Viper LLC or Viper from $400 million to $1.0 billion. The amendment was approved by the requisite percentage of lenders underduring the revolving credit facility and became effective on October 8, 2019. If the amendment had not been approved, the borrowing base under the revolving credit facility would have decreased by $125 million upon consummation of the Viper Notes Offering.

regularly scheduled (semi-annual) fall 2020 redetermination in November 2020. As of September 30, 2019, the borrowing base was set at $600 million, and2020, Viper LLC had $410$127 million of outstanding borrowings and $190$453 million available for future borrowings under itsthe Viper credit agreement. The weighted average interest rate on the credit facility was 2.14% and 2.66% for the three months and nine months ended September 30, 2020, respectively. The revolving credit facility.facility will mature on November 1, 2022.

As of September 30, 2020, Viper funded LLC was in compliance with all financial maintenance covenants under the cash portionViper credit agreement.

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 net proceeds of approximately $490 million from the offering of the purchase price forViper Notes. Viper loaned the Drop-Down through a combination of cash on hand and borrowings undergross proceeds to Viper LLC’s revolving credit facility.LLC. Viper LLC used the proceeds from the Viper Notes Offeringnotes offering to pay down borrowings under its revolving credit facility. Following these transactions, as of October 16, 2019,During the closing date of thethree months and nine months endedSeptember 30, 2020, Viper Notes Offering, there was $95 million in outstanding borrowings under Viper LLC’s revolving credit facility, the borrowing base under Viper LLC’s revolving credit facility wasrepurchased $7256 million and Viper LLC had $630$20 million, of available borrowing capacity under its revolving credit facility. Additionally, in connection with Viper’s fall redetermination expected to occur in November 2019, the lead bank under the Viper LLC’s revolving credit facility has recommended a borrowing base increase to $775 million from the current borrowing base of $725 million. The anticipated increase in the borrowing base is subject to approval by the requisite lenders under Viper LLC’s revolving credit facility.

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

The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, purchases of margin stock, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements, and require the maintenance of the financial ratios described below:
Financial CovenantRequired Ratio
Ratio of total net debt to EBITDAX, as defined in the credit agreementNot greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreementNot less than 1.0 to 1.0


The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $400 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portionrespectively of the outstanding principal amount of Viper Notes in open market purchases at a cash price ranging from 97.5% to 98.5% of the loanaggregate principal amount, which resulted in an immaterial gain on extinguishment of debt. The repurchase brought the total outstanding principal amount of Viper Notes down to be repaid.


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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)

As$480 million as of September 30, 2019 and December 31, 2018, Viper was in compliance with all financial covenants under its revolving credit facility, as then in effect. The lenders may accelerate all of the indebtedness under Viper’s credit agreement upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods.2020.

Rattler’s Credit Agreement

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

The Rattler credit agreement provides for a revolving credit facility in the maximum credit amount of $600 million. Loan principal may be optionally repaid from timemillion, which is expandable to time without premium or penalty (other than$1 billion upon Rattler’s election, subject to obtaining additional lender commitments and satisfaction of customary LIBOR breakage), and is required to be paid at the maturity date of May 28, 2024. The loan is guaranteed by Rattler and Tall City, and is secured by substantially all of the assets of Rattler LLC, Rattler and Tall City.conditions. As of September 30, 2019,2020, Rattler LLC had $103$85 million of outstanding borrowings and $497$515 million available for future borrowings under the Rattler credit agreement. The weighted average interest rate on the credit facility was 1.46% and 2.18% for the three months and nine months ended September 30, 2020, respectively.

As of September 30, 2020, Rattler LLC was in compliance with all financial maintenance covenants under the Rattler credit agreement.

See Note 18—Subsequent Events for a description of the amendment to the Rattler credit agreement which occurred subsequent to September 30, 2020.

Rattler’s Notes

On July 14, 2020, Rattler completed an offering (the “Notes Offering”) of $500 million in aggregate principal amount of its 5.625% Senior Notes due 2025 (the “Rattler Notes”). Interest on the Rattler Notes is payable on January 15 and July 15 of each year, beginning on January 15, 2021. The Rattler Notes mature on July 15, 2025. Rattler received net proceeds of approximately $490 million from the Notes Offering. Rattler loaned the gross proceeds to Rattler LLC, which Rattler LLC used to repay then outstanding borrowings under the Rattler credit agreement bear interest atagreement. The Rattler Notes are senior unsecured obligations of Rattler, rank equally in right of payment with all of Rattler’s existing and future senior indebtedness it may incur and initially are guaranteed on a per annum rate electedsenior unsecured basis by Rattler LLC, that is based onTall City, Rattler OMOG LLC and Rattler Ajax Processing LLC. Neither 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 inCompany nor Rattler’s General Partner guarantee the Rattler credit agreement). Rattler LLC is obligated to pay a quarterly commitment fee ranging from 0.250% to 0.375% per annum onNotes. In the unused portionfuture, each 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 otherRattler’s restricted payments, transactions with affiliates, and entering into certain swap agreements, in each case of Rattler, Rattler LLC and their restricted subsidiaries. The covenants are subject to exceptions set forth in the Rattler credit agreement, including an exception allowing Rattler LLC or Rattler to issue unsecured debt securities and an exception allowing payment of distributions if no default exists. The Rattler credit agreement may be used to fund capital expenditures, to finance working capital, for general company purposes, to pay fees and expenses related to the Rattler credit agreement, and to make distributions permitted 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 CovenantRequired Ratio
Consolidated Total Leverage Ratio commencing with the fiscal quarter ending September 30, 2019Not 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 madeNot greater than 3.50 to 1.00
Consolidated Interest Coverage Ratio (as defined in the Rattler credit agreement) commencing with the fiscal quarter ending September 30, 2019Not less than 2.50 to 1.00
16


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.

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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)


Assubsidiaries that either (1) guarantees any of September 30, 2019, each of Rattler and Rattler LLC were in compliance with all financial covenantsits or a guarantor’s other indebtedness or (2) is classified as a domestic restricted subsidiary under the indenture governing the Rattler credit agreement. The lenders may accelerate all of theNotes and is an obligor with respect to any indebtedness under any credit facility will be required to guarantee the Rattler credit agreement upon the occurrence and during the continuance of any event of default. The Rattler credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change in control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial maintenance covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods. With certain specified exceptions, the terms and provisions of the Rattler credit agreement generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.Notes.

Alliance with Obsidian Resources, L.L.C.
The Company
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 September 30, 2020 and December 31, 2019, CEMOF had funded approximately $33 million.CEMOF’s return related to this alliance was $86 million and $39 million, respectively. As of September 30, 2019, 82020, 15 joint wells have been drilled and completed.

12.11.    CAPITAL STOCK AND EARNINGS PER SHARE

Diamondback did not complete any equity offerings during the nine months ended September 30, 20192020 and September 30, 2018.2019.

Viper’s Equity Offering

On March 1, 2019, Viper completed an underwritten public offering of 10,925,000 common units, which included 1,425,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Following this offering, the Company owned approximately 54% of Viper’s total units then outstanding. Viper received net proceeds from this offering of approximately $341 million, after deducting underwriting discounts and commissions and estimated offering expenses. Viper used the net proceeds to purchase units of Viper LLC. Viper LLC in turn used the net proceeds to repay a portion of the outstanding borrowings under its revolving credit facility and finance acquisitions during the period.

In July 2018, Viper completed an underwritten public offering of 10,080,000 common units, which included 1,080,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Following this offering, Diamondback owned approximately 59% of the total Viper units then outstanding. Viper received net proceeds from this offering of approximately $303 million, after deducting underwriting discounts and commissions and estimated offering expenses. Viper used the net proceeds to purchase units of Viper LLC. Viper LLC in turn used the net proceeds to repay a portion of the $362 million then outstanding borrowings under its revolving credit facility.

Rattler’s Initial Public Offering
Please see Note 6—5—Rattler Midstream LP for information regarding Rattler’s IPO.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

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

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 andended September 30, 2020, the Company repurchased 0 common stock under this repurchase program. During the nine months ended September 30, 2019,2020, the Company repurchased approximately $296$98 million and $400 million, respectively, of common stock under this repurchase program. As of September 30, 2019, $1.62020, $1.3 billion remained available for use to repurchase shares under the Company's common stock repurchase program.program, although the Company has suspended this program to preserve liquidity.

Earnings (Loss) Per Share

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


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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)
A reconciliation of the components of basic and diluted earnings per common share is presented in the table below:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
($ in millions, except per share amounts, shares in thousands)
Net income (loss) attributable to common stock$(1,113)$368 $(3,778)$727 
Weighted average common shares outstanding:
Basic weighted average common units outstanding157,833 162,543 157,984 164,070 
Effect of dilutive securities:
Potential common shares issuable(1)
0 237 0 396 
Diluted weighted average common shares outstanding157,833 162,780 157,984 164,466 
Basic net income (loss) attributable to common stock$(7.05)$2.27 $(23.91)$4.44 
Diluted net income (loss) attributable to common stock$(7.05)$2.26 $(23.91)$4.42 
 Three Months Ended September 30, Nine Months Ended September 30,
 20192018 20192018
 ($ in millions, except per share amounts, shares in thousands)
Net income attributable to common stock$368
$157
 $727
$539
Weighted average common shares outstanding     
Basic weighted average common units outstanding162,543
98,638
 164,070
98,603
Effect of dilutive securities:     
Potential common shares issuable237
180
 396
217
Diluted weighted average common shares outstanding162,780
98,818
 164,466
98,820
Basic net income attributable to common stock$2.27
$1.59
 $4.44
$5.47
Diluted net income attributable to common stock$2.26
$1.59
 $4.42
$5.45

The Company had(1)    For the following shares thatthree and nine months ended September 30, 2020, 0 potential common units were included in the computation of diluted earnings per share because their inclusion would have been anti-dilutive. For the three months and nine months ended September 30, 2019, there were 50,814 and 40,291 potential common units excluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive forunder the periods presented but could potentially dilute basic earnings per share in future periods:treasury stock method.

 Three Months Ended September 30, Nine Months Ended September 30,
 20192018 20192018
 (in thousands)
Restricted stock units51
13
 40
2


Change in Ownership of Consolidated Subsidiaries

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

Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(in millions)
Net income (loss) attributable to the Company$(1,113)$368 $(3,778)$727 
Change in ownership of consolidated subsidiaries0 0 329 77 
Change from net income (loss) attributable to the Company's stockholders and transfers to non-controlling interest$(1,113)$368 $(3,449)$804 


12.    EQUITY-BASED COMPENSATION

The following table presents the effects of the equity compensation plans and related costs:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(in millions)
General and administrative expenses$9 $4 $27 $27 
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties4 (1)12 9 
 Three Months Ended September 30, Nine Months Ended September 30,
 20192018 20192018
 (in millions)
General and administrative expenses$4
$5
 $27
$18
Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties(1)2
 9
7


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


Restricted Stock Units

The following table presents the Company’s restricted stock units activity under the Equity Plan during the nine months ended September 30, 2019:2020:
Restricted Stock
Awards & Units		Weighted Average Grant-Date
Fair Value
Unvested at December 31, 2019505,867 $96.01 
Granted183,102 $60.72 
Vested(139,355)$85.21 
Forfeited(19,228)$99.01 
Unvested at September 30, 2020530,386 $86.55 
 Restricted Stock
Awards & Units		Weighted Average Grant-Date
Fair Value
Unvested at December 31, 2018324,224
$116.01
Granted468,778
$106.85
Vested(217,300)$100.47
Forfeited(81,962)$107.35
Unvested at September 30, 2019493,740
$107.54


The aggregate fair value of restricted stock units that vested during the nine months ended September 30, 2020 and 2019 and 2018 was $4$12 million and $15$4 million, respectively. As of September 30, 2019,2020, the Company’s unrecognized compensation cost related to unvested restricted stock awards and units was $28 million. Such cost$27 million, which is expected to be recognized over a weighted-average period of 1.41.7 years.

During the nine months ended September 30, 2020, the Company modified an insignificant amount of restricted stock units to include dividend equivalent rights during the vesting period which resulted in 0 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-basedIn February 2018, eligible employees received performance restricted stock unit awards totaling 117,423 units to eligible employees. The ultimate numberfrom which a minimum of shares0% and a maximum of 200% units could be 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-yearthe performance period.period of January 1, 2018 to December 31, 2020 and cliff vest at December 31, 2020 subject to continued employment.

In March 2019, eligible employees received performance restricted stock unit awards totaling 199,723 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have aawarded based upon the TSR during the performance period of January 1, 2019 to December 31, 2021 and cliff vest at December 31, 2021.2021 subject to continued employment. In March 2019, eligible employees received performance restricted stock unit awards totaling 32,958 units from which a minimum of 0% and a maximum of 200% units could be awarded. The awards have a performance period of January 1, 2019 to December 31, 2021 and vest in 5 equal installments beginning on March 1, 2025.

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

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 20192020 awards.
 2019
Grant-date fair value (3-year vesting)$137.22
Grant-date fair value (5-year vesting)$132.48
Risk-free rate2.55%
Company volatility35.00%



202020192018
Grant-date fair value$70.17 $137.22 $170.45 
Grant-date fair value (5-year vesting)$132.48 
Risk-free rate0.86 %2.55 %1.99 %
Company volatility36.70 %35.00 %35.90 %
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Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)

The following table presents the Company’s performance restricted stock units activity under the Equity Plan for the nine months ended September 30, 2019:2020:
Performance Restricted Stock UnitsWeighted Average Grant-Date Fair Value
Unvested at December 31, 2019271,819 $147.07 
Granted272,601 $85.73 
Vested(47,554)$89.27 
Forfeited(8,396)$170.45 
Unvested at September 30, 2020(1)
488,470 $110.33 
 Performance Restricted Stock UnitsWeighted Average Grant-Date Fair Value
Unvested at December 31, 2018196,203
$169.76
Granted356,227
$131.30
Vested(123,546)$60.70
Forfeited(103,635)$155.23
Unvested at September 30, 2019(1)
325,249
$150.63
(1)A maximum of 1,089,464 units could be awarded based upon the Company’s final TSR ranking.

(1)A maximum of 650,498 units could be awarded based upon the Company’s final TSR ranking.

As of September 30, 2019,2020, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $28 million. Such cost$26 million, which is expected to be recognized over a weighted-average period of 2.42.0 years.

Stock Appreciation Rights
In connection with the Energen Merger, each outstanding stock appreciation right in respect of Energen common stock that was outstanding immediately prior to the effective time of the Merger was converted into a fully vested stock appreciation right in respect of 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 nine months ended September 30, 2019:

 Shares Weighted Average Exercise Price
Outstanding at December 31, 201857,721
 $22.12
Exercised(11,265) $70.64
Expired(3,775) $96.91
Outstanding at September 30, 201942,681
 $90.84


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.

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.

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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)

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, 2018332,387
 $95.04
    
Exercised(116,044) $82.29
    
Outstanding at September 30, 2019216,343
 $89.90
 1.92 $—
        
Vested and Expected to vest at September 30, 2019216,343
 $89.90
 1.92 $—
Exercisable at September 30, 2019216,343
 $89.90
 1.92 $—


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 nine months ended September 30, 2019:
 Phantom Units Weighted Average Grant-Date
Fair Value
Unvested at December 31, 2018125,053
 $23.44
Granted33,886
 $32.78
Vested(81,124) $23.34
Forfeited(1,028) $42.50
Unvested at September 30, 201976,787
 $27.42


The aggregate fair value of phantom units that vested during the nine months ended September 30, 2019 was $2 million. As of September 30, 2019, the unrecognized compensation cost related to unvested phantom units was $1 million. Such cost is expected to be recognized over a weighted-average period of 0.81 years.

Rattler Long-Term Incentive Plan

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

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


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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)

The following table presents the phantom unit activity under the Rattler LTIP for the nine months ended September 30, 2019:2020:
Phantom
Units		Weighted Average
Grant-Date
Fair Value
Unvested at December 31, 20192,226,895 $19.14 
Granted53,943 $10.41 
Vested(449,633)$19.14 
Forfeited(23,442)$18.23 
Unvested at September 30, 20201,807,763 $18.89 
 Phantom
Units		 Weighted Average
Grant-Date
Fair Value
Unvested at May 28, 2019—
 $—
Granted2,248,572
 $19.20
Forfeited(57,143) $19.21
Unvested at September 30, 20192,191,429
 $19.20


The aggregate fair value of phantom units that vested during the nine months ended September 30, 2020 was $9 million. As of September 30, 2019,2020, the unrecognized compensation cost related to unvested phantom units was $39$31 million. Such cost is expected to be recognized over a weighted-average period of 2.63.6 years.

14.    RELATED PARTY TRANSACTIONS

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Advisory Services Agreement - ViperDiamondback Energy, Inc. and Subsidiaries

Condensed Notes to Consolidated Financial Statements-(Continued)
In connection with the closing of the Viper Offering, Viper and Viper’s General Partner entered into an advisory services agreement (the “Viper Advisory Services Agreement”) with Wexford, dated as of June 23, 2014, under which Wexford provided Viper and Viper’s General Partner with general financial and strategic advisory services related to the business in return for an annual fee of $500,000, plus reasonable out-of-pocket expenses. The Advisory Services Agreement was terminated on November 12, 2018 and Viper’s payment obligation ended in June 2019. During 2019, Viper did 0t pay any amounts under the Advisory Services Agreement. For the three months and nine months ended September 30, 2018, Viper did 0t pay any amounts under the Advisory Services Agreement.(Unaudited)

Lease Bonus - Viper
During the three months ended September 30, 2019, the Company did 0t pay Viper any lease bonus payments. During the nine months ended September 30, 2019, the Company paid Viper $39,198 in lease bonus payments to extend the term of 2 leases and $3,101 in lease bonus payments for 2 new leases. During the three months and nine months ended September 30, 2018, the Company paid Viper $3 million in lease bonus payments to extend the term of 12 leases.

Rattler Offering
Please see Note 6—Rattler Midstream LP for information regarding relationships between the Company and Rattler.

15.13.    INCOME TAXES

The Company’s effective income tax rates were 20.8%21.6% and 21.2%20.8% for the three months ended September 30, 20192020 and 2018,2019, respectively, and 17.9%18.7% and 11.5%17.9% for the nine months ended September 30, 2020 and 2019, respectively. Total income tax benefit from continuing operations for the three and 2018, respectively. nine months ended September 30, 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 in the first quarter resulting from the carryback of federal net operating losses.

For the nine months ended September 30, 2020, the Company recorded a discrete income tax expense of $143 million related to application in the first quarter 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 pre-tax loss for 2020. The determination to record a valuation allowance was based on assessment of all available evidence, both positive and negative, supporting realizability of Viper’s deferred tax assets. In light of those criteria for recognizing the tax benefit of deferred tax assets, Viper’s assessment resulted in application of a valuation allowance against Viper’s deferred tax assets as of March 31, 2020, June 30, 2020, and September 30, 2020. In addition, for the nine months ended September 30, 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 and nine months ended September 30, 2019 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income primarily due to current and deferred(i) state income taxes, (ii) the impact of permanent differences between book and taxable income and (iii) the revision of estimated deferred taxes recognized by Viper as a result of its change in tax status. For the nine months ended September 30, 2019, the Company recorded a discrete income tax expense of less than $1 million related to equity-based compensation and a discrete benefit of approximately $42 million related to the revision of estimated deferred taxes on Viper’s investment in Viper LLC arising from the change in Viper’s tax status. Based on information available regarding unitholders’ tax basis, which, under IRS reporting rules, was not available until the current period, Viper revised its estimate of deferred taxes on Viper’s investment in Viper LLC and further revisions are not expected. Total incomeon the date of the tax expense for the three and nine months ended September 30, 2018 differed from amounts computed by applying the federal statutory rate to pre-tax income primarily due to (i) state income taxes, (ii) net income attributable to the noncontrolling interest, (iii) the impactstatus change, resulting in discrete deferred tax benefit of permanent differences between book and taxable income, and (iv)$42 million for the nine months ended September 30, 2018,2019.

During the three months ended June 30, 2020, the Company recorded an increase through stockholders’ equity to the carrying value of its investment in Rattler LLC, resulting in an increase in the Company’s deferred taxes recognized by Viper astax liability related to its investment in Rattler LLC. A corresponding adjustment to the noncontrolling interest resulted in a decrease in Rattler’s deferred tax liability related to its investment in Rattler LLC and a total net deferred tax asset balance for Rattler. As a result of Rattler’s assessment each period, including consideration of all available positive and negative evidence, Rattler continued to determine that it is more likely than not that Rattler will realize its changedeferred tax assets as of September 30, 2020.

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 status.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 $100 million as of March 31, 2020, June 30, 2020 and September 30, 2020.


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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)

As discussed further in Note 6,5, 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.

As discussed further in Note 5, on March 29, 2018, Viper announced that the Board

21
Table of Directors of Viper’s General Partner had unanimously approved a change of Viper’s federal income tax status from that of a pass-through partnershipContents
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to that of a taxable entity, which change became effective on May 10, 2018. The transactions undertaken in connection with the change in Viper’s tax status were not taxable to the Company. Subsequent to Viper’s change in tax status, Viper’s provision for income taxes is based on its estimated annual effective tax rate plus discrete items. As such, Viper’s provision for income taxes is included in the Company’s consolidated financial statements and to the extent applicable, in net income attributable to the non-controlling interest.Consolidated Financial Statements-(Continued)

(Unaudited)
16.14.    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 combinedcondensed consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.”

Commodity Contracts

Commodity Contracts

The Company has used fixed price swap contracts, fixed price basis swap contracts, double-up swap contractsentered into multiple crude oil, natural gas, natural gas liquids and three-way costless collars with corresponding put, short put and call optionsdiesel fuel derivatives, indexed to the respective indices as noted in the table below, to reduce price volatility associated with certain of its oil and natural gas sales. 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 and liquids derivative settlements based on Mt. Belvieu pricing.

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


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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)

As of September 30, 2019,2020, the Company had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.
SwapsCollars
Settlement MonthSettlement YearType of ContractBbls/Mmbtu/Gallons Per DayIndexWeighted Average DifferentialWeighted Average Fixed PriceWeighted Average Floor PriceWeighted Average Ceiling Price
OIL
Oct. - Dec.2020Swaps11,000WTI Cushing$0$43.47$—$—
Oct. - Dec.2020Swaps4,000WTI Magellan$0$61.95$—$—
Oct. - Dec.2020Swaps24,200Brent$0$47.62$—$—
Oct. - Dec.2020Basis Swaps45,087
WTI Cushing(1)
$(1.33)$0$—$—
Oct. - Dec.2020Basis Swaps8,000
WTL Cushing(1)
$(1.31)$0$—$—
Oct. - Dec.2020
Rolling Hedge(2)
120,000WTI Cushing$(1.05)$0$—$—
Oct. - Dec.2020Costless Collar45,779WTI Cushing$—$—$35.92$42.29
Oct. - Dec.2020Costless Collar4,000WTI Magellan$—$—$39.00$49.00
Oct. - Dec.2020Costless Collar64,710Brent$—$—$37.59$45.63
Jan. - Dec.2021Swaps5,000WTI Magellan$0$37.78$—$—
Jan. - Dec.2021Swaps7,500Brent$0$41.58$—$—
Jan. - Dec.2021Costless Collar65,000Brent$—$—$39.25$48.36
July - Dec.2021Swaption5,000Brent$0$51.00$—$—
Jan. - Dec.2021Costless Collar10,000WTI Cushing$—$—$30.00$43.05
NATURAL GAS
Oct. - Dec.2020Swaps60,000Henry Hub$0$2.48$—$—
Oct. - Dec.2020Swaps60,000Waha Hub$0$1.51$—$—
Oct. - Dec.2020Basis Swaps145,000
Waha Hub(1)
$(1.57)$0$—$—
Jan. - Dec.2021Swaps190,000Henry Hub$0$2.62$—$—
Jan. - Dec.2021Basis Swaps230,000
Waha Hub(1)
$(0.69)$0$—$—
Jan. - Dec.2022Basis Swaps80,000
Waha Hub(1)
$(0.45)$0$—$—
NATURAL GAS LIQUIDS
Oct. - Dec.2020Swaps7,000Mont Belvieu Ethane$0$8.43$—$—
Oct. - Dec.2020Swaps5,000Mont Belvieu Propane$0$21.76$—$—
DIESEL
Oct. - Dec.2021Swaps1,000,000Gulf Cost Ultra Low Sulfur$0$1.60$—$—
(1) The Company has fixed price basis swaps for the spread between the Cushing crude oil price and the Midland WTI crude oil price or the Midland Argus WTL crude oil price as well as the spread between the Henry Hub natural gas price and the Waha Hub natural gas price. The weighted average differential represents the amount of reduction to Cushing, Oklahoma, oil price and the Waha Hub natural gas price for the notional volumes covered by the basis swap contracts.
(2) The Company has rolling hedge basis swaps for the differential between the NYMEX prices between the calendar month average and the physical crude oil delivery month. The weighted average differential represents the amount of reduction to Cushing, Oklahoma, oil price for the notional volumes covered by the rolling hedge basis swap contracts.
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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)
 2019 2020 2021
 Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu) Volume (Bbls/MMBtu) Fixed Price Swap (per Bbl/MMBtu)
Oil Swaps - WTI Cushing2,710,000
 $61.21
 4,388,000
 $57.87
 —
 $—
Oil Swaps - WTI Magellan East Houston920,000
 $63.47
 2,196,000
 $62.80
 —
 $—
Oil Swaps - BRENT644,000
 $67.71
 4,205,000
 $62.72
 —
 $—
Oil Basis Swaps - WTI Cushing4,140,000
 $(5.52) 15,120,000
 $(1.21) —
 $—
Natural Gas Swaps - Henry Hub6,440,000
 $3.06
 10,980,000
 $2.55
 —
 $—
Natural Gas Swaps - Waha Hub—
 $—
 18,300,000
 $1.67
 —
 $—
Natural Gas Basis Swaps - Waha Hub6,440,000
 $(1.56) 14,640,000
 $(1.10) 36,500,000
 $(0.68)
Natural Gas Liquid Swaps - Mont Belvieu690,000
 $27.30
 —
 $—
 —
 $—
Settlement MonthSettlement YearType of ContractBbls/Mcf Per DayIndexStrike PriceSwap PricePut PriceLong Put PriceOption Price
OIL
Oct. - Dec.2020
Calls(1)
8,000WTI Magellan$45.00$0$0$0$0
Oct. - Dec.2020Option4,700WTI Cushing$0$0$0$46.51$0
Oct. - Dec.2020Put Spread3,800WTI Magellan$0$0$25.00$50.00$0
Oct. - Dec.2022Option5,000WTI Cushing$0$0$35.00$0$0
NATURAL GAS
Oct. - Dec.2020Swap Double-Up30,000Waha Hub$0$1.70$0$0$1.70

(1) Includes a deferred premium at a weighted-average price of $(1.89)/Bbl and a strike price of $45.00/Bbl
 2019 2020
Oil Three-Way CollarsWTI Cushing Brent WTI Magellan East Houston WTI CushingBrent WTI Magellan East Houston
Volume (Bbls)1,440,000 552,000 460,000 6,842,2009,278,100 5,124,000
Short put price (per Bbl)$35.94
 $51.67
 $50.00
 $44.20
$50.00
 $50.00
Floor price (per Bbl)$45.94
 $61.67
 $60.00
 $54.20
$60.00
 $60.00
Ceiling price (per Bbl)$61.65
 $78.47
 $66.10
 $65.42
$72.18
 $68.61

Gas Swap Double-Up - Waha Hub2020
Volume (Mcf)10,980,000
Swap price (per Mcf)$1.70
Option price$1.70

Interest Rate Swaps and Treasury Locks

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


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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)

The following table summarizes the Company’s interest rate swaps and treasury locks as of September 30, 2019:2020:
TypeEffective DateContractual Termination DateNotional Amount (in millions)Interest Rate
Interest Rate SwapDecember 31, 2020December 31, 2030$250 1.551 %
Interest Rate SwapDecember 31, 2020December 31, 2030$250 1.5575 %
Interest Rate SwapDecember 31, 2020December 31, 2030$250 1.297 %
Interest Rate SwapDecember 31, 2020December 31, 2030$250 1.195 %
TypeEffective DateTermination DateNotional Amount (in millions)Interest Rate
Treasury LockAugust 23, 2019August 24, 2020$250
2.1509%
Treasury LockAugust 23, 2019August 24, 2020$250
1.6563%
Interest Rate SwapDecember 31, 2020December 31, 2030$250
1.59675%
Interest Rate SwapDecember 31, 2020December 31, 2050$250
1.615%
Interest Rate SwapDecember 31, 2020December 31, 2030$500
1.567%
Interest Rate SwapDecember 31, 2020December 31, 2050$250
1.555%
Interest Rate SwapDecember 31, 2020December 31, 2030$250
1.3565%

See Note 18—Subsequent Events for discussion of derivative transactions which occurred subsequent to September 30, 2020.

Balance sheet offsettingSheet Offsetting of derivative assetsDerivative Assets and liabilitiesLiabilities

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, including any deferred premiums that are with the same counterparty and are subject to contractual terms which provide for net settlement. See Note 15—Fair Value Measurements for further details.

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 September 30, 2019 and December 31, 2018.
 September 30, 2019December 31, 2018
 (in millions)
Gross amounts of assets presented in the Consolidated Balance Sheet$198
$231
Net amounts of assets presented in the Consolidated Balance Sheet198
231
   
Gross amounts of liabilities presented in the Consolidated Balance Sheet12
15
Net amounts of liabilities presented in the Consolidated Balance Sheet$12
$15



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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)

Gains and Losses on Derivative Instruments
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:
 September 30, 2019December 31, 2018
 (in millions)
Current assets: derivative instruments  
Commodity contracts$140
$231
Interest rate swaps—
—
Total$140
$231
   
Noncurrent assets: derivative instruments  
Commodity contracts$38
$—
Interest rate swaps20
—
Total$58
$—
   
Total assets$198
$231
   
Current liabilities: derivative instruments  
Commodity contracts$10
$—
Interest rate swaps—
—
Total$10
$—
   
Noncurrent liabilities: derivative instruments  
Commodity contracts$2
$15
Interest rate swaps—
—
Total$2
$15
   
Total liabilities$12
$15


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

Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(in millions)
Gain (loss) on derivative instruments, net
Commodity contracts$(104)$157 $147 $(17)
Interest rate swaps5 20 (65)20 
Total$(99)$177 $82 $3 
Net cash received (paid) on settlements
Commodity contracts(1)
(9)11 288 33 
Total$(9)$11 $288 $33 
(1)The three and nine months ended September 30, 2020 include cash received on contracts terminated prior to their contractual maturity of $6 million and $17 million, respectively.
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Diamondback Energy, Inc. and Subsidiaries
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 September 30, Nine Months Ended September 30,
 20192018 20192018
 (in millions)
Change in fair value of open non-hedge derivative instruments:     
Commodity contracts$146
$(10) $(50)$(24)
Interest rate swaps20
—
 20
—
Total$166
$(10) $(30)$(24)
      
Gain (loss) on settlement of non-hedge derivative instruments:     
Commodity contracts$11
$(38) $33
$(115)
Interest rate swaps—
—
 —
—
Total$11
$(38) $33
$(115)
      
Gain (loss) on derivative instruments$177
$(48) $3
$(139)

17.15.    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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Diamondback Energy, Inc. and Subsidiaries
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”.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 9—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. TheViper measures its investment utilizing the fair value of Viper’soption, and as such the investment is determined using quoted market prices. These valuations areclassified as Level 1 inputs.in the fair value hierarchy. The fair values of the Company’s fixed price swaps, fixed price basis swaps and costless collarsderivative contracts are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs.


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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)
The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Company’s condensed consolidated balance sheets as of September 30, 20192020 and December 31, 2018.:2019. The net amounts are classified as current or noncurrent based on their anticipated settlement dates.
 September 30, 2019 December 31, 2018
 Level 1Level 2Level 3 Level 1Level 2Level 3
 (in millions)
Assets:       
Investment$18
$—
$—
 $14
$—
$—
Fixed price swaps—
186
—
 —
216
—
Liabilities:       
Fixed price swaps$—
$—
$—
 $—
$—
$—

The following table summarizes the changes in fair value of Viper’s cost method investment during the periods presented:
 (in millions)
Value at December 31, 2018$14
Gain on investment4
Value at September 30, 2019$18
  
Value at December 31, 2017$34
Impact of adoption of Accounting Standards Update 2016-01(19)
Gain on investment5
Value at September 30, 2018$20


As of September 30, 2020
Level 1Level 2Level 3Total Gross Fair ValueGross Amounts Offset in Balance SheetNet Fair Value Presented in Balance Sheet
(in millions)
Assets:
Current:
Derivative Instruments$0 $107 $0 $107 $(92)$15 
Non-current:
Investment$5 $0 $0 $5 $0 $5 
Derivative Instruments$0 $65 $0 $65 $(65)$0 
Liabilities:
Current:
Derivative Instruments$0 $178 $0 $178 $(92)$86 
Non-current:
Derivative Instruments$0 $173 $0 $173 $(65)$108 

As of December 31, 2019
Level 1Level 2Level 3Total Gross Fair ValueGross Amounts Offset in Balance SheetNet Fair Value Presented in Balance Sheet
(in millions)
Assets:
Current:
Derivative Instruments$0 $64 $0 $64 $(18)$46 
Non-current:
Investment$19 $0 $0 $19 $0 $19 
Derivative Instruments$0 $7 $0 $7 $0 $7 
Liabilities:
Current:
Derivative Instruments$0 $45 $0 $45 $(18)$27 


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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The following table provides the fair value of financial instruments that are not recorded at fair value in the condensed consolidated balance sheets:
September 30, 2020December 31, 2019
CarryingCarrying
Value(1)
Fair Value
Value(1)
Fair Value
(in millions)
Debt:
Revolving credit facility$0 $0 $13 $13 
4.625% Notes due 2021$191 $194 $399 $411 
7.320% Medium-term Notes, Series A, due 2022$21 $22 $21 $22 
2.875% Senior Notes due 2024$993 $1,014 $992 $1,012 
4.750% Senior Notes due 2025$496 $541 $0 $0 
5.375% Senior Notes due 2025$800 $830 $799 $840 
3.250% Senior Notes due 2026$793 $803 $792 $812 
7.350% Medium-term Notes, Series A, due 2027$0 $0 $11 $12 
7.125% Medium-term Notes, Series B, due 2028$107 $113 $108 $116 
3.500% Senior Notes due 2029$1,187 $1,158 $1,186 $1,226 
Viper revolving credit facility$127 $127 $97 $97 
Viper's 5.375% Senior Notes due 2027$471 $477 $490 $521 
Rattler revolving credit facility$85 $85 $424 $424 
Rattler’s 5.625% Senior Notes due 2025$490 505 $0 $0 
DrillCo Agreement$86 $86 $39 $39 
 September 30, 2019December 31, 2018
 Carrying Carrying 
 AmountFair ValueAmountFair Value
 (in millions)
Debt:    
Revolving credit facility$1,629
$1,629
$1,490
$1,490
4.625% Notes due 2021(1)
$400
$411
$400
$393
7.320% Medium-term Notes, Series A, due 2022(1)
$21
$22
$20
$21
4.750% Senior Notes due 2024$1,250
$1,283
$1,250
$1,204
5.375% Senior Notes due 2025$800
$837
$800
$782
7.350% Medium-term Notes, Series A, due 2027(1)
$11
$11
$10
$11
7.125% Medium-term Notes, Series B, due 2028(1)
$108
$111
$100
$102
Viper revolving credit facility$410
$410
$411
$411
Rattler revolving credit facility$103
$103
$—
$—
DrillCo Agreement$42
$42
$—
$—
(1)The carrying value includes associated deferred loan costs and any remaining discount or premium, if any.

(1)At the effective time of the Energen Merger, Energen became a wholly owned subsidiary of the Company and remained the issuer of the Energen Notes. These notes were marked to fair value with the excess being amortized.

The fair valuevalues of the revolving credit facility, Viper’s revolvingthe Viper credit facilityagreement and Rattler’s revolvingthe Rattler credit facility approximatesagreement approximate their carrying valuevalues 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 valuevalues of the Senior Notes and the Energen Notes wasoutstanding notes were determined using the September 30, 20192020 quoted market price, a Level 1 classification in the fair value hierarchy.

Fair Value of Financial Assets
18.
The carrying amount of cash and cash equivalents, receivables, prepaid expenses and other current assets, payables and other accrued liabilities approximate their fair value because of the short-term nature of the instruments.

16.    LEASES

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

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

The following table summarizes operating lease costs for the three months and nine months ended September 30, 2020 and 2019:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(in millions)
Operating lease costs$4 $7 $13 $19 
 Three Months Ended September 30, 2019 Nine Months Ended September 30, 2019
 (in millions)
Operating lease costs$7
 $19


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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)
For the nine months ended September 30, 2020 and 2019, cash paid for operating lease liabilities, andas reported in cash flows provided by operating activities on the Company's StatementCompany’s condensed consolidated statements of Condensed Consolidated Cash Flows,cash flows, was $13 million and $19 million.million, respectively. During the nine months ended September 30, 2020 and 2019, the Company recorded an additional $10 million and $15 million of right-of-use assets in exchange for new lease liabilities.

The operating leaseliabilities, respectively. There were no significant right-of-use assets were reportedrecorded during the three months ended September 30, 2020 and 2019.

As of September 30, 2020, the Condensed Consolidated Balance Sheet includes operating right-of-use assets of $13 million in other assets, and the current and noncurrent portions of the operating lease liabilities were reportedof $9 million in other accrued liabilities , and long-term operating lease liabilities of $4 million in other long-term liabilities, respectively, on the Condensed Consolidated Balance Sheet.liabilities. As of September 30, 2019, the operating right-of-use assets were $19 million and operating lease liabilities were $19 million, of which $13 million was classified as current. As of September 30, 2019,2020, the weighted average remaining lease term was 1.61.5 years and the weighted average discount rate was 8.4%9.2%.

Schedule of Operating Lease Liability Maturities. The following table summarizes undiscounted cash flows owed by the Company to lessors pursuant to contractual agreements in effect as of September 30, 2019:2020:
As of September 30, 2020
(in millions)
2020 (October - December)$4 
20217 
20223 
20230 
20240 
Thereafter0 
Total lease payments14 
Less: interest1 
Present value of lease liabilities$13 
 As of September 30, 2019
 (in millions)
2019 (October - December)$7
20208
20214
20221
2023—
Thereafter—
Total lease payments20
Less: interest1
Present value of lease liabilities$19


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.

19.17.    COMMITMENTS AND CONTINGENCIES

The Company is a party to various routine legal proceedings, disputes and claims arising in the ordinary course of its business, including those that arise from interpretation of federal and state laws and regulations affecting the 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 CompanyCompany’s management 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.operations or cash flows. The Company’s assessment is based on information known about the pending matters and its experience in contesting, litigating and settling similar matters. Actual outcomes could differ materially from the Company’s assessment. The Company records reserves for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)

20.18.    SUBSEQUENT EVENTS

Third Quarter 20192020 Dividend Declaration
On November 1, 2019,October 29, 2020, the Board of Directors of the Company declared a cash dividend for the third quarter of 20192020 of $0.1875$0.375 per share of common stock, payable on November 22, 201919, 2020 to its stockholders of record at the close of business on November 15, 2019.12, 2020.
Amendment to the Rattler Credit Agreement in Connection with Initiation of Rattler’s Common Unit Repurchase Program

On November 2, 2020, Rattler and Rattler LLC entered into a second amendment (the “Second Amendment”) to the Rattler Credit Agreement with Wells Fargo, as the administrative agent, and the lenders party thereto. The Second Amendment permits Rattler to conduct common unit repurchases in connection with the common unit repurchase program approved by the board of directors of Rattler’s General Partner on October 29, 2020.

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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)
Under Rattler’s common unit repurchase program to be conducted under Rule 10b-18 of the Exchange Act, Rattler is authorized to acquire up to $100 million of Rattler’s outstanding common units in open market or privately negotiated transactions with cash on hand and free cash flow from operations. The common unit repurchase program is authorized to extend through December 31, 2021, may be suspended from time to time or modified, extended or discontinued by the board of directors of Rattler’s General Partner at any time, and will be subject to market conditions, applicable legal requirements, contractual obligations and other factors.
Commodity Contracts

Subsequent to September 30, 2019,2020, the Company entered into new fixed price swaps and 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.noted in the table below.

The following tables present the derivative contracts entered into by the Company subsequent to September 30, 2019.between October 1, 2020 and November 2, 2020. When aggregating multiple contracts, the weighted average contract price is disclosed.
 January 2020 - December 2020
Oil Three-Way CollarsBrent
Volume (Bbls)2,525,400
Short put price (per Bbl)$50.00
Floor price (per Bbl)$60.00
Ceiling price (per Bbl)$66.00


SwapsCollars
Settlement MonthSettlement YearType of ContractBbls/Mmbtu Per DayIndexWeighted Average DifferentialWeighted Average Fixed PriceWeighted Average Floor PriceWeighted Average Ceiling Price
OIL
Jan. - Mar.2021Costless Collar3,000WTI Cushing$—$—$37.00$44.19
Mar. - June2021Costless Collar1,000WTI Cushing$—$—$37.00$47.00
Jan. - June2021Costless Collar6,000Brent$—$—$37.50$45.50
NATURAL GAS
Jan. - Dec.2021Swaps10,000Henry Hub$—$3.05$—$—
Jan. - Dec.2022Basis Swap20,000Waha Hub$(0.31)$—$—$—
Drop-Down and Increase in the Borrowing Base under Viper LLC’s Revolving Credit Facility
On October 1, 2019,Interest Rate Swaps

Subsequent to September 30, 2020, the Company completed a transaction to divest certain mineralentered into new interest rate swaps and royalty interests to Viper for approximately 18.3 million of Viper’s newly-issued Class B units, approximately 18.3 million newly-issued units of Viper LLC and $190 million in cash, after giving effect to closing adjustments for net title benefits. Based on the volume weighted average sales price of Viper’s common units for the ten trading-day period ended July 26, 2019 of approximately $30.07, the transaction is valued at $740 million. See Note 4—Acquisitions for additional information regarding this divestiture.terminated existing interest rate swaps.
Viper’s Notes Offering
On October 16, 2019, Viper completed an offering (the “Viper Notes Offering”) of $500 million in aggregate principal amount of its 5.375% Senior Notes due 2027 (the “Viper Notes”). Viper received net proceeds of approximately $492 million from the Viper Notes Offering. Viper loaned the gross proceeds to Viper LLC as described below. Viper LLC used the proceeds from the Viper Notes Offering to pay down borrowings under its revolving credit facility.

The Viper Notes are senior unsecured obligations of Viper, initially are guaranteed on a senior unsecured basisfollowing table presents the interest rate swaps entered into by Viper LLC, and will pay interest semi-annually. Neither the Company nor Viper’s General Partner guaranteesubsequent to September 30, 2020.

TypeEffective DateContractual Termination DateNotional Amount (in millions)Interest Rate
Interest Rate SwapDecember 31, 2024December 31, 2054$250 1.692 %
Interest Rate SwapDecember 31, 2024December 31, 2054$250 1.8361 %
Interest Rate SwapDecember 31, 2024December 31, 2054$250 1.852 %

The following table presents the Viper Notes. Ininterest rate swap contracts terminated by the future, each of Viper’s restricted subsidiaries that either (1) guarantees any of its or a guarantor’s other indebtedness or (2) is a domestic restricted subsidiary and is an obligor with respectCompany subsequent to any indebtedness under any credit facility will be required to guarantee the Viper Notes.September 30, 2020.

TypeEffective DateContractual Termination DateNotional Amount (in millions)Interest Rate
Interest Rate SwapDecember 31, 2020December 31, 2030$250 1.551 %
Interest Rate SwapDecember 31, 2020December 31, 2030$250 1.5575 %
Interest Rate SwapDecember 31, 2020December 31, 2030$250 1.297 %
Amendment to Rattler Credit Agreement
On October 23, 2019, Rattler entered into a first amendment (the “First Amendment”) to the Rattler credit agreement with Rattler LLC, Wells Fargo Bank, National Association, as the administrative agent, and certain lenders from time to time party thereto. The First Amendment, among other things, provides Rattler LLC with additional flexibility to make investments in joint ventures and other third parties, including investments in the Wink to Webster project and the Joint Venture. Pursuant to the First Amendment, the Joint Venture is designated as an unrestricted subsidiary under the Credit Agreement.


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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)

19.    SEGMENT INFORMATION

21.    REPORT OF BUSINESS SEGMENTS

The Company reports its operations in 2 businessoperating segments: (i) the exploration and productionupstream 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 businessCompany’s operating segments during the periods presented:
UpstreamMidstream ServicesEliminationsTotal
Three Months Ended September 30, 2020:(in millions)
Third-party revenues$706 $14 $— $720 
Intersegment revenues— 83 (83)— 
Total revenues706 97 (83)720 
Depreciation, depletion and amortization275 11 0 286 
Impairment of oil and natural gas properties1,451 0 0 1,451 
Income (loss) from operations(1,282)44 (18)(1,256)
Interest expense, net(47)(6)0 (53)
Other income (expense)(103)4 (1)(100)
Provision for (benefit from) income taxes(307)3 0 (304)
Net income (loss) attributable to non-controlling interest(1)9 0 8 
Net income (loss) attributable to Diamondback Energy, Inc.(1,124)30 (19)(1,113)
As of September 30, 2020:
Total assets$17,245 $1,812 $(297)$18,760 
Exploration and Production Midstream Services Eliminations TotalUpstreamMidstream ServicesEliminationsTotal
Three Months Ended September 30, 2019:(in millions)Three Months Ended September 30, 2019:(in millions)
Third-party revenues$957
 $18
 $—
 $975
Third-party revenues$957 $18 $— $975 
Intersegment revenues—
 97
 (97) —
Intersegment revenues— 97 (97)— 
Total revenues957
 115
 (97) 975
Total revenues957 115 (97)975 
Income from operations321
 52
 (24) 349
Depreciation, depletion and amortizationDepreciation, depletion and amortization353 12 0 365 
Income (loss) from operationsIncome (loss) from operations321 52 (24)349 
Interest expense, netInterest expense, net(37)(1)0 (38)
Other income (expense)143
 (1) (1) 141
Other income (expense)181 (1)(1)179 
Provision for income taxes99
 3
 —
 102
Net income attributable to non-controlling interest20
 37
 (37) 20
Net income attributable to Diamondback Energy$345
 $11
 $12
 $368
Provision for (benefit from) income taxesProvision for (benefit from) income taxes99 3 0 102 
Net income (loss) attributable to non-controlling interestNet income (loss) attributable to non-controlling interest20 37 (37)20 
Net income (loss) attributable to Diamondback Energy, Inc.Net income (loss) attributable to Diamondback Energy, Inc.346 10 12 368 
As of December 31, 2019:As of December 31, 2019:
Total assets$22,452
 $1,307
 $(206) $23,553
Total assets$22,125 $1,636 $(230)$23,531 

31
 Exploration and Production Midstream Services Eliminations Total
Three Months Ended September 30, 2018:(in millions)
Third-party revenues$527
 $10
 $—
 $537
Intersegment revenues—
 39
 (39) —
Total revenues527
 49
 (39) 537
Income from operations268
 23
 (23) 268
Other income (expense)(65) —
 —
 (65)
Provision for income taxes43
 —
 —
 43
Net income attributable to non-controlling interest3
 —
 —
 3
Net income attributable to Diamondback Energy$157
 $23
 $(23) $157
Total assets$9,365
 $525
 $(83) $9,807


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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)

UpstreamMidstream ServicesEliminationsTotal
Nine Months Ended September 30, 2020:(in millions)
Third-party revenues$2,002 $42 $— $2,044 
Intersegment revenues— 273 (273)— 
Total revenues2,002 315 (273)2,044 
Depreciation, depletion and amortization1,001 35 0 1,036 
Impairment of oil and natural gas properties4,999 0 0 4,999 
Income (loss) from operations(4,787)134 (77)(4,730)
Interest expense, net(137)(10)0 (147)
Other income (expense)73 (10)(4)59 
Provision for (benefit from) income taxes(910)8 0 (902)
Net income (loss) attributable to non-controlling interest(163)25 0 (138)
Net income (loss) attributable to Diamondback Energy, Inc.(3,778)81 (81)(3,778)
As of September 30, 2020:
Total assets$17,245 $1,812 $(297)$18,760 
 Exploration and Production Midstream Services Eliminations Total
Nine Months Ended September 30, 2019:(in millions)
Third-party revenues$2,802
 $58
 $—
 $2,860
Intersegment revenues—
 264
 (264) —
Total revenues2,802
 322
 (264) 2,860
Income from operations1,004
 159
 (84) 1,079
Other income (expense)(116) (2) (3) (121)
Provision for income taxes167
 4
 —
 171
Net income attributable to non-controlling interest60
 52
 (52) 60
Net income attributable to Diamondback Energy$661
 $101
 $(35) $727
Total assets$22,452
 $1,307
 $(206) $23,553

 Exploration and Production Midstream Services Eliminations Total
Nine Months Ended September 30, 2018:(in millions)
Third-party revenues$1,509
 $34
 $—
 $1,543
Intersegment revenues—
 99
 (99) —
Total revenues1,509
 133
 (99) 1,543
Income from operations808
 63
 (55) 816
Other income (expense)(92) (2) —
 (94)
Provision for income taxes83
 —
 —
 83
Net income attributable to non-controlling interest100
 —
 —
 100
Net income attributable to Diamondback Energy$533
 $61
 $(55) $539
Total assets$9,365
 $525
 $(83) $9,807


22.    GUARANTOR FINANCIAL STATEMENTS

As of September 30, 2019, Diamondback E&P LLC, Diamondback O&G LLC and Energen Corporation and its subsidiaries (the “Guarantor Subsidiaries”) are guarantors under the 2024 Indenture and the 2025 Indenture. In connection with the issuance of the 2024 Senior Notes and the 2025 Senior Notes, Viper, Viper’s General Partner, Viper LLC and Rattler LLC were designated as Non-Guarantor Subsidiaries. The following presents condensed consolidated financial information for the Company (which for purposes of this Note 22 is referred to as the “Parent”), the Guarantor Subsidiaries and the Non–Guarantor Subsidiaries on a consolidated basis. Elimination entries presented are necessary to combine the entities. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantor Subsidiaries operated as independent entities. The Company has not presented separate financial and narrative information for each of the Guarantor Subsidiaries because it believes such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the Guarantor Subsidiaries.

The Rattler entities were not guarantors under the 2024 Senior Notes or the 2025 Senior Notes for the previous periods presented; therefore, the schedules that follow have been adjusted to reflect this correction of an immaterial change.


UpstreamMidstream ServicesEliminationsTotal
Nine Months Ended September 30, 2019:(in millions)
Third-party revenues$2,802 $58 $— $2,860 
Intersegment revenues— 264 (264)— 
Total revenues2,802 322 (264)2,860 
Depreciation, depletion and amortization1,014 32 0 1,046 
Income (loss) from operations1,004 159 (84)1,079 
Interest expense, net(132)(1)0 (133)
Other income (expense)16 (1)(3)12 
Provision for (benefit from) income taxes167 4 0 171 
Net income (loss) attributable to non-controlling interest60 52 (52)60 
Net income (loss) attributable to Diamondback Energy, Inc.$661 $101 $(35)727 
As of December 31, 2019:
Total assets$22,125 $1,636 $(230)$23,531 
45
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Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)

Condensed Consolidated Balance Sheet
September 30, 2019
(in millions)
     Non–    
   Guarantor Guarantor    
 Parent Subsidiaries Subsidiaries Eliminations Consolidated
Assets         
Current assets:         
Cash and cash equivalents$48
 $29
 $23
 $—
 $100
Accounts receivable, net—
 493
 45
 —
 538
Accounts receivable - related party—
 —
 44
 (44) —
Intercompany receivable4,223
 —
 —
 (4,223) —
Inventories—
 32
 13
 —
 45
Derivative instruments—
 140
 —
 —
 140
Prepaid expenses and other1
 20
 1
 —
 22
Total current assets4,272
 714
 126
 (4,267) 845
Property and equipment:         
Oil and natural gas properties, full cost method of accounting—
 22,964
 2,037
 (179) 24,822
Midstream assets—
 —
 884
 —
 884
Other property, equipment and land—
 61
 91
 —
 152
Accumulated depletion, depreciation, amortization and impairment—
 (3,425) (353) (37) (3,815)
Net property and equipment—
 19,600
 2,659
 (216) 22,043
Funds held in escrow—
 —
 7
 —
 7
Equity method investments—
 —
 225
 —
 225
Derivative instruments—
 58
 —
 —
 58
Investment in subsidiaries12,460
 —
 —
 (12,460) —
Deferred tax asset—
 —
 158
 —
 158
Investment in real estate, net—
 —
 111
 —
 111
Other assets—
 79
 27
 —
 106
Total assets$16,732
 $20,451
 $3,313
 $(16,943) $23,553
Liabilities and Stockholders’ Equity         
Current liabilities:         
Accounts payable-trade$—
 $233
 $—
 $—
 $233
Intercompany payable—
 4,267
 —
 (4,267) —
Accrued capital expenditures—
 385
 42
 —
 427
Other accrued liabilities39
 228
 37
 —
 304
Revenues and royalties payable—
 207
 —
 —
 207
Derivative instruments—
 10
 —
 —
 10
Total current liabilities39
 5,330
 79
 (4,267) 1,181
Long-term debt2,037
 2,211
 513
 —
 4,761
Derivative instruments—
 2
 —
 —
 2
Asset retirement obligations—
 81
 9
 —
 90
Deferred income taxes606
 1,408
 5
 —
 2,019
Other long-term liabilities—
 11
 —
 —
 11
Total liabilities2,682
 9,043
 606
 (4,267) 8,064
Commitments and contingencies

 

 

 

 

Stockholders’ equity14,050
 11,408
 1,518
 (12,926) 14,050
Non-controlling interest—
 —
 1,189
 250
 1,439
Total equity14,050
 11,408
 2,707
 (12,676) 15,489
Total liabilities and equity$16,732
 $20,451
 $3,313
 $(16,943) $23,553

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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)

Condensed Consolidated Balance Sheet
December 31, 2018
(in millions)
     Non–    
   Guarantor Guarantor    
 Parent Subsidiaries Subsidiaries Eliminations Consolidated
Assets         
Current assets:         
Cash and cash equivalents$84
 $100
 $31
 $—
 $215
Accounts receivable, net—
 351
 41
 —
 392
Accounts receivable - related party—
 —
 9
 (9) —
Intercompany receivable4,469
 195
 —
 (4,664) —
Inventories—
 28
 9
 —
 37
Derivative instruments—
 231
 —
 —
 231
Prepaid expenses and other3
 43
 4
 —
 50
Total current assets4,556
 948
 94
 (4,673) 925
Property and equipment:         
Oil and natural gas properties, full cost method of accounting—
 20,675
 1,717
 (93) 22,299
Midstream assets—
 284
 416
 —
 700
Other property, equipment and land—
 71
 76
 —
 147
Accumulated depletion, depreciation, amortization and impairment—
 (2,486) (276) (12) (2,774)
Net property and equipment—
 18,544
 1,933
 (105) 20,372
Equity method investments—
 1
 —
 —
 1
Investment in subsidiaries11,576
 112
 —
 (11,688) —
Deferred tax asset—
 —
 97
 —
 97
Investment in real estate, net—
 12
 104
 —
 116
Other assets—
 68
 17
 —
 85
Total assets$16,132
 $19,685
 $2,245
 $(16,466) $21,596
Liabilities and Stockholders’ Equity         
Current liabilities:         
Accounts payable-trade$—
 $128
 $—
 $—
 $128
Intercompany payable—
 4,673
 —
 (4,673) —
Accrued capital expenditures—
 495
 —
 —
 495
Other accrued liabilities14
 170
 69
 —
 253
Revenues and royalties payable—
 143
 —
 —
 143
Total current liabilities14
 5,609
 69
 (4,673) 1,019
Long-term debt2,036
 2,017
 411
 —
 4,464
Derivative instruments—
 15
 —
 —
 15
Asset retirement obligations—
 136
 —
 —
 136
Deferred income taxes382
 1,403
 —
 —
 1,785
Other long-term liabilities—
 10
 —
 —
 10
Total liabilities2,432
 9,190
 480
 (4,673) 7,429
Commitments and contingencies

 

 

 

 

Stockholders’ equity13,700
 10,495
 1,070
 (11,565) 13,700
Non-controlling interest—
 —
 695
 (228) 467
Total equity13,700
 10,495
 1,765
 (11,793) 14,167
Total liabilities and equity$16,132
 $19,685
 $2,245
 $(16,466) $21,596





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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)

Condensed Consolidated Statement of Operations
Three Months Ended September 30, 2019
(in millions)
     Non–    
   Guarantor Guarantor    
 Parent Subsidiaries Subsidiaries Eliminations Consolidated
Revenues:         
Oil sales$—
 $817
 $—
 $65
 $882
Natural gas sales—
 14
 —
 2
 16
Natural gas liquid sales—
 54
 —
 4
 58
Royalty income—
 —
 71
 (71) —
Lease bonus—
 —
 1
 —
 1
Midstream services—
 —
 112
 (96) 16
Other operating income—
 —
 3
 (1) 2
Total revenues—
 885
 187
 (97) 975
Costs and expenses:         
Lease operating expenses—
 174
 —
 (46) 128
Production and ad valorem taxes—
 56
 5
 —
 61
Gathering and transportation—
 29
 —
 (4) 25
Midstream services—
 —
 47
 (21) 26
Depreciation, depletion and amortization—
 329
 29
 7
 365
General and administrative expenses3
 17
 3
 (4) 19
Asset retirement obligation accretion—
 —
 1
 —
 1
Other operating expense—
 (1) 2
 —
 1
Total costs and expenses3
 604
 87
 (68) 626
Income (loss) from operations(3) 281
 100
 (29) 349
Other income (expense)         
Interest expense, net(11) (22) (5) —
 (38)
Other income (expense), net1
 3
 —
 (2) 2
Gain on derivative instruments, net—
 177
 —
 —
 177
Total other income (expense), net(10) 158
 (5) (2) 141
Income (loss) before income taxes(13) 439
 95
 (31) 490
Provision for income taxes107
 —
 (5) —
 102
Net income (loss)(120) 439
 100
 (31) 388
Net income (loss) attributable to non-controlling interest—
 —
 80
 (60) 20
Net income (loss) attributable to Diamondback Energy, Inc.$(120) $439
 $20
 $29
 $368


48
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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)

Condensed Consolidated Statement of Operations
Three Months Ended September 30, 2018
(in millions)
     Non–    
   Guarantor Guarantor    
 Parent Subsidiaries Subsidiaries Eliminations Consolidated
Revenues:         
Oil sales$—
 $391
 $—
 $63
 $454
Natural gas sales—
 10
 —
 4
 14
Natural gas liquid sales—
 50
 —
 7
 57
Royalty income—
 —
 74
 (74) —
Lease bonus—
 —
 4
 (3) 1
Midstream services—
 —
 46
 (38) 8
Other operating income—
 —
 4
 (1) 3
Total revenues—
 451
 128
 (42) 537
Costs and expenses:         
Lease operating expenses—
 59
 —
 (10) 49
Production and ad valorem taxes—
 28
 5
 —
 33
Gathering and transportation—
 10
 1
 (5) 6
Midstream services—
 1
 19
 —
 20
Depreciation, depletion and amortization—
 119
 23
 4
 146
General and administrative expenses7
 9
 1
 (3) 14
Other operating expense—
 (1) 2
 —
 1
Total costs and expenses7
 225
 51
 (14) 269
Income (loss) from operations(7) 226
 77
 (28) 268
Other income (expense)         
Interest expense, net(11) (4) (4) —
 (19)
Other income (expense), net1
 1
 1
 (1) 2
Loss on derivative instruments, net—
 (48) —
 —
 (48)
Total other expense, net(10) (51) (3) (1) (65)
Income (loss) before income taxes(17) 175
 74
 (29) 203
Provision for income taxes42
 —
 1
 —
 43
Net income (loss)(59) 175
 73
 (29) 160
Net income (loss) attributable to non-controlling interest—
 —
 49
 (46) 3
Net income (loss) attributable to Diamondback Energy, Inc.$(59) $175
 $24
 $17
 $157



49
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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)

Condensed Consolidated Statement of Operations
Nine Months Ended September 30, 2019
(In millions)
     Non–    
   Guarantor Guarantor    
 Parent Subsidiaries Subsidiaries Eliminations Consolidated
Revenues:         
Oil sales$—
 $2,389
 $—
 $183
 $2,572
Natural gas sales—
 31
 —
 5
 36
Natural gas liquid sales—
 176
 —
 14
 190
Royalty income—
 —
 202
 (202) —
Lease bonus—
 —
 4
 —
 4
Midstream services—
 —
 312
 (261) 51
Other operating income—
 —
 10
 (3) 7
Total revenues—
 2,596
 528
 (264) 2,860
Costs and expenses:         
Lease operating expenses—
 465
 —
 (101) 364
Production and ad valorem taxes—
 167
 13
 —
 180
Gathering and transportation—
 65
 —
 (11) 54
Midstream services—
 —
 122
 (62) 60
Depreciation, depletion and amortization—
 943
 82
 21
 1,046
General and administrative expenses27
 39
 11
 (9) 68
Asset retirement obligation accretion—
 5
 1
 —
 6
Other operating expense—
 —
 3
 —
 3
Total costs and expenses27
 1,684
 232
 (162) 1,781
Income (loss) from operations(27) 912
 296
 (102) 1,079
Other income (expense)         
Interest expense, net(32) (89) (12) —
 (133)
Other income (expense), net2
 7
 1
 (5) 5
Gain on derivative instruments, net—
 3
 —
 —
 3
Gain on revaluation of investment—
 —
 4
 —
 4
Total other income (expense), net(30) (79) (7) (5) (121)
Income (loss) before income taxes(57) 833
 289
 (107) 958
Provision for (benefit from) income taxes209
 —
 (38) —
 171
Net income (loss)(266) 833
 327
 (107) 787
Net income (loss) attributable to non-controlling interest—
 —
 181
 (121) 60
Net income (loss) attributable to Diamondback Energy, Inc.$(266) $833
 $146
 $14
 $727


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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)

Condensed Consolidated Statement of Operations
Nine Months Ended September 30, 2018
(In millions)
     Non–    
   Guarantor Guarantor    
 Parent Subsidiaries Subsidiaries Eliminations Consolidated
Revenues:         
Oil sales$—
 $1,149
 $—
 $185
 $1,334
Natural gas sales—
 31
 —
 9
 40
Natural gas liquid sales—
 116
 —
 17
 133
Royalty income—
 —
 211
 (211) —
Lease bonus—
 —
 5
 (3) 2
Midstream services—
 —
 124
 (97) 27
Other operating income—
 —
 9
 (2) 7
Total revenues—
 1,296
 349
 (102) 1,543
Costs and expenses:         
Lease operating expenses—
 159
 —
 (30) 129
Production and ad valorem taxes—
 79
 14
 —
 93
Gathering and transportation—
 28
 1
 (12) 17
Midstream services—
 —
 49
 —
 49
Depreciation, depletion and amortization—
 319
 60
 12
 391
General and administrative expenses21
 22
 6
 (4) 45
Asset retirement obligation accretion—
 1
 —
 —
 1
Other operating expenses—
 —
 2
 —
 2
Total costs and expenses21
 608
 132
 (34) 727
Income (loss) from operations(21) 688
 217
 (68) 816
Other income (expense)         
Interest expense, net(30) (10) (9) —
 (49)
Other income (expense), net1
 91
 (1) (2) 89
Loss on derivative instruments, net—
 (139) —
 —
 (139)
Gain on revaluation of investment—
 —
 5
 —
 5
Total other expense, net(29) (58) (5) (2) (94)
Income (loss) before income taxes(50) 630
 212
 (70) 722
Provision for (benefit from) income taxes154
 —
 (71) —
 83
Net income (loss)(204) 630
 283
 (70) 639
Net income attributable to non-controlling interest—
 —
 78
 22
 100
Net income (loss) attributable to Diamondback Energy, Inc.$(204) $630
 $205
 $(92) $539




51
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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)

Condensed Consolidated Statement of Cash Flows
Nine Months Ended September 30, 2019
(in millions)
     Non–    
   Guarantor Guarantor    
 Parent Subsidiaries Subsidiaries Eliminations Consolidated
Net cash (used in) provided by operating activities$(3) $1,529
 $326
 $—
 $1,852
Cash flows from investing activities:         
Additions to oil and natural gas properties—
 (1,987) —
 —
 (1,987)
Additions to midstream assets—
 —
 (186) —
 (186)
Purchase of other property, equipment and land—
 (8) —
 —
 (8)
Acquisition of leasehold interests—
 (311) —
 —
 (311)
Acquisition of mineral interests—
 —
 (320) —
 (320)
Proceeds from sale of assets—
 301
 —
 —
 301
Investment in real estate—
 —
 (1) —
 (1)
Funds held in escrow—
 —
 (7) —
 (7)
Equity investments—
 (149) (76) —
 (225)
Net cash used in investing activities—
 (2,154) (590) —
 (2,744)
Cash flows from financing activities:         
Proceeds from borrowing under credit facility—
 930
 479
 —
 1,409
Repayment under credit facility—
 (789) (379) —
 (1,168)
Proceeds from joint venture—
 42
 —
 —
 42
Debt issuance costs(116) 114
 (5) —
 (7)
Public offering costs—
 —
 (40) —
 (40)
Proceeds from public offerings—
 —
 1,106
 —
 1,106
Distribution to parent—
 —
 (727) 727
 —
Contributions from subsidiaries—
 727
 —
 (727) —
Distributions from subsidiary99
 —
 —
 (99) —
Proceeds from exercise of stock options9
 —
 —
 —
 9
Repurchased for tax withholdings(13) —
 —
 —
 (13)
Repurchased as part of share buyback(400) —
 —
 —
 (400)
Dividends to stockholders(82) —
 —
 —
 (82)
Distributions to non-controlling interest—
 —
 (178) 99
 (79)
Intercompany transfers470
 (470) —
 —
 —
Net cash (used in) provided by financing activities(33) 554
 256
 —
 777
Net increase (decrease) in cash and cash equivalents(36) (71) (8) —
 (115)
Cash and cash equivalents at beginning of period84
 100
 31
 —
 215
Cash and cash equivalents at end of period$48
 $29
 $23
 $—
 $100

52
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Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements-(Continued)
(Unaudited)

Condensed Consolidated Statement of Cash Flows
Nine Months Ended September 30, 2018
(in millions)
     Non–    
   Guarantor Guarantor    
 Parent Subsidiaries Subsidiaries Eliminations Consolidated
Net cash provided by operating activities$—
 $861
 $292
 $—
 $1,153
Cash flows from investing activities:         
Additions to oil and natural gas properties—
 (1,010) —
 —
 (1,010)
Additions to midstream assets—
 (21) (109) —
 (130)
Purchase of other property, equipment and land—
 3
 (5) —
 (2)
Acquisition of leasehold interests—
 (186) —
 —
 (186)
Acquisition of mineral interests—
 170
 (506) —
 (336)
Proceeds from sale of assets—
 6
 1
 —
 7
Investment in real estate—
 (111) —
 —
 (111)
Funds held in escrow—
 (51) —
 —
 (51)
Intercompany transfers(22) 22
 —
 —
 —
Net cash used in investing activities(22) (1,178) (619) —
 (1,819)
Cash flows from financing activities:         
Proceeds from borrowing under credit facility—
 471
 557
 —
 1,028
Repayment under credit facility—
 (868) (354) —
 (1,222)
Proceeds from senior notes1,062
 —
 —
 —
 1,062
Debt issuance costs(14) —
 —
 —
 (14)
Public offering costs—
 —
 (3) —
 (3)
Proceeds from public offerings—
 —
 306
 —
 306
Contributions to subsidiaries(1) —
 (1) 2
 —
Contributions by members—
 —
 2
 (2) —
Distributions from subsidiary113
 —
 —
 (113) —
Dividends to stockholders(25) —
 —
 —
 (25)
Distributions to non-controlling interest—
 —
 (182) 113
 (69)
Intercompany transfers(696) 695
 1
 —
 —
Net cash provided by financing activities439
 298
 326
 —
 1,063
Net increase (decrease) in cash and cash equivalents417
 (19) (1) —
 397
Cash and cash equivalents at beginning of period54
 34
 24
 —
 112
Cash and cash equivalents at end of period$471
 $15
 $23
 $—
 $509





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, 2018.2019. 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“Part II. Item 1A. Risk Factors”Factors” and “Cautionary“Cautionary Statement Regarding Forward-Looking Statements.Statements.”

Overview

We operate in two business segments: (i) the exploration and productionupstream 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.

Exploration2020 Recent Developments

COVID-19 and Production OperationsCollapse 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. Although many stay-at-home orders have expired and certain restrictions on conducting business have been lifted, the COVID-19 pandemic resulted in a widespread health crisis and 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 a closing NYMEX price low of negative $37.63 per barrel in April 2020. For the first nine months of 2020, the average NYMEX WTI and Henry Hub futures contracts prices for crude oil and condensate and natural gas were $38.21 per barrel and $1.92 per million British thermal units (MMBtu), respectively, representing decreases of 33% and 25%, respectively, from the average WTI futures prices for the same period in 2019. This was a result of multiple factors affecting supply and demand in global oil and natural gas markets, including actions taken by OPEC members and other exporting nations impacting commodity price and production levels and the ongoing COVID-19 pandemic. While OPEC members and certain other nations agreed in April 2020 to cut production, which helped to reduce a portion of the excess supply in the market and improve oil prices, there is no assurance that this agreement will continue or be observed by its parties, and downward pressure on commodity prices has continued and could continue for the foreseeable future. The Company cannot predict if or when commodity prices will stabilize and at what levels.

As a result of the reduction in crude oil demand caused by factors mentioned above, in March 2020, we announced reductions to our capital plans for 2020 and have recently indicated that we expect our budget to remain in this lower range for the rest of 2020. We also lowered our total commodity production and oil production guidance for 2020 and, as of August 3, 2020, were targeting slightly lower oil production volumes in 2020 as compared to full year 2019, and took other actions discussed below. We continued our trend of cost reductions in the third quarter of 2020, with our lease operating and general and administrative expenses remaining near all-time lows and capital costs per lateral foot continuing to decline. Our drilling and completion operations continue to become more efficient, and we are beginning to see the benefits from high-grading our development program after the downturn began earlier in 2020. We remain on track to meet our fourth quarter 2020 average production target of between 170,000 and 175,000 barrels of oil per day, and expect this to be the baseline for our development plan in 2021. We expect to execute on this maintenance plan with 25% to 35% less capital than in 2020, which implies a reinvestment ratio of approximately 70% at $40 per barrel WTI. Our investment framework and capital allocation philosophy at current depressed commodity prices remain focused on protecting our common stock dividend, spending maintenance capital on holding production flat and using excess free cash flow to pay down debt. We believe that we have the size, scale, balance sheet, asset quality and cost structure to weather a prolonged downturn in our industry and succeed in the subsequent upcycle.


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In addition, as a result of the sharp decline in commodity prices in early March 2020, and the continued depressed oil pricing throughout the second and third quarters of 2020, we recorded non-cash ceiling test impairments for the nine months ended September 30, 2020 of approximately $5.0 billion, of which approximately $1.5 billion was recorded for the three months ended September 30, 2020 and approximately $3.5 billion was recorded for the six months ended June 30, 2020. These impairment charges 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.

Given the dynamic nature of these events, we cannot reasonably estimate the period of time that the COVID-19 pandemic, the depressed commodity prices and the adverse macroeconomic will persist, the full extent of the impact they will have on our industry and our business, financial condition, results of operations or cash flows, or the pace or extent of any subsequent recovery.

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 also curtailed 5% of our oil production during the second quarter of 2020. This curtailed production has been restored and is now receiving significantly higher realized prices than it would have received when the decision was made to curtail. We currently have three completion crews working to stem production declines to meet our fourth quarter 2020 average production target of between 170,000 and 175,000 barrels of oil per day.

•Our operated rig count declined rapidly beginning in the second quarter of 2020, from 20 rigs on March 31, 2020 to five rigs currently, building a significant inventory of drilled but uncompleted wells.

•Assuming a continuation of current market conditions, we plan to operate between five and six operated drilling rigs and between three and four completion crews for the remainder of 2020.

•Based on current forward commodity prices, we expect to generate significant free cash flow in the remainder of 2020 and in 2021. Under a maintenance capital scenario in 2021 should that become the base case operating plan, we anticipate that we will be able to hold expected fourth quarter 2020 oil production flat while spending 25% to 35% less than our 2020 capital budget, including lower midstream and infrastructure budgets.

•We intend to remain focused on returning capital to our stockholders through our quarterly dividend while protecting our balance sheet, and intend to continue to drill, complete and produce hydrocarbons with the highest margins at the lowest capital and operating costs in the industry.

•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.

Third Quarter 2020 and Other Recent Developments

•We recorded a net loss of $1.1 billion for the third quarter ended September 30, 2020, which reflected an impairment of oil and natural gas properties of approximately $1.5 billion as a result of lower average trailing 12-month commodity pricing.

•Our average production was 287.3 MBOE/d during the third quarter of 2020.

•During the third quarter of 2020, we drilled 22 gross horizontal wells in the Midland Basin and ten gross horizontal wells in the Delaware Basin.

•We turned 41 gross operated horizontal wells (25 in the Midland Basin and 16 in the Delaware Basin) to production and had capital expenditures of $281 million during the third quarter of 2020.

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•The average lateral length for the wells completed during the third quarter of 2020 was 9,881 feet.

•As of September 30, 2020, we had $2.0 billion of availability for future borrowings under our revolving credit facility and approximately $92 million of cash on hand.

•We retired all of the outstanding Energen’s 7.350% Medium-term notes due 2027 in the aggregate principal amount of $10 million.

•Our cash operating costs for the third quarter ended September 30, 2020 were $7.61 per BOE, including lease operating expenses of $3.86 per BOE, cash general and administrative expenses of $0.42 per BOE and production and ad valorem taxes and gathering and transportation expenses of $3.33 per BOE.

•Our current drilling and completion costs in the Midland Basin are approximately $450 per lateral foot, with an estimated additional $60 to $80 of equip costs per lateral foot.

•Our current drilling and completion costs in the Delaware Basin are between $600 and $700 per lateral foot, with an estimated additional $100 to $150 of equip costs per lateral foot.

•We completed an average of over 3,300 lateral feet per day per completion crew in the Midland Basin using Simulfrac technology during the third quarter of 2020.

•We continued our commitment to environmental stewardship during the third quarter of 2020, flaring 0.5% of net production, down 74% from 2019. During the nine months ended September 30, 2020, we flared 0.9% of net production, down 54% from 2019.

•We recycled 25.1% of water used for completion operations in the third quarter of 2020, up 24% from 2019. During the nine months ended September 30, 2020, we recycled 21.4% of water used for completion operations, up 53% from 2019.

•On October 29, 2020, our board of directors declared a cash dividend for the third quarter of 2020 of $0.375 per share of common stock, payable on November 19, 2020 to our stockholders of record at the close of business of November 12, 2020.

•In July 2020, Rattler completed a notes offering of $500 million in aggregate principal amount of its 5.625% Senior Notes due 2025, or the Rattler Notes, under Rule 144A and Regulation S under the Securities Act, resulting in net proceeds of approximately $490 million. The proceeds from the offering of the Rattler Notes were used to repay outstanding borrowings under its revolving credit facility.

•On October 29, 2020, Rattler implemented a common unit repurchase program under Rule 10b-18 of the Exchange Act to acquire up to $100 million of Rattler’s outstanding common units in open market or privately negotiated transactions with cash on hand and free cash flow from operations. The common unit repurchase program is authorized to extend through December 31, 2021, may be suspended from time to time or modified, extended or discontinued by the board of directors of Rattler’s General Partner at any time, and will be subject to market conditions, applicable legal requirements, contractual obligations and other factors. In connection with the common unit repurchase program, Rattler entered into an amendment to the Rattler credit agreement permitting such program.

Upstream Segment

In our exploration and productionupstream 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.

As of September 30, 2019,2020, we had approximately 379,897378,961 net acres, which primarily consisted of approximately 193,006199,254 net acres in the Midland Basin and approximately 158,799152,743 net acres in the Delaware Basin. As of December 31, 2018,2019, we had an estimated 11,86812,310 gross horizontal locations that we believe to be economic at $60 per Bbl West Texas Intermediate, orbarrel WTI.
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The following table sets forth the total number of operated horizontal wells drilled and completed during the three months and nine months ended September 30, 2019:2020:
Three Months Ended September 30, 2020Nine Months Ended September 30, 2020
Drilled
Completed(1)
Drilled
Completed(2)
AreaGrossNetGrossNetGrossNetGrossNet
Midland Basin22 20 25 25 114 108 69 61 
Delaware Basin10 10 16 16 69 65 67 63 
Total32 30 41 41 183 173 136 124 
 
Three Months Ended September 30, 2019(1)
 
Nine Months Ended September 30, 2019(2)
 Drilled Completed Drilled Completed
AreaGrossNet GrossNet GrossNet GrossNet
Midland Basin43
42
 51
45
 133
121
 134
123
Delaware Basin40
37
 37
37
 122
110
 105
96
Total83
79
 88
82
 255
231
 239
219
(1)The average lateral length for the wells completed during the third quarter of 2020 was 9,881 feet. Operated completions during the third quarter of 2020 consisted of 16 Wolfcamp A wells, five Wolfcamp B wells, six Lower Spraberry wells, nine Middle Spraberry wells and five Second Bone Springs wells.
(1)The average lateral length for the wells completed during the third quarter of 2019 was 9,549 feet. Operated completions during the third quarter of 2019 consisted of 58 Wolfcamp A wells, ten Lower Spraberry wells, seven Wolfcamp B wells, four Middle Spraberry wells, four Jo Mill wells, two Second Bone Springs wells, one Third Bone Springs well, one Wolfcamp D well and one Meramec well.
(2)The average lateral length for wells completed during the nine months of 2019 was 9,665 feet, and consisted of 142 Wolfcamp A wells, 43 Lower Spraberry wells, 25 Wolfcamp B wells, nine Middle Spraberry wells, seven Second Bone Springs wells, six Jo Mill wells, five Third Bone Springs wells, one Wolfcamp D well and one Meramec well.
(2)The average lateral length for the wells completed during the first nine months of 2020 was 9,955 feet. Operated completions during the first nine months of 2020 consisted of 67 Wolfcamp A wells, 16 Wolfcamp B wells, 17 Lower Spraberry wells, 17 Middle Spraberry wells, three Jo Mill wells, 11 Second Bone Springs wells and five Third Bone Springs wells.

As of September 30, 2019,2020, we operated the following wells:
Vertical WellsHorizontal WellsTotal
AreaGrossNetGrossNetGrossNet
Midland Basin1,400 1,313 1,072 976 2,472 2,289 
Delaware Basin25 22 569 535 594 557 
Total1,425 1,335 1,641 1,511 3,066 2,846 
 Vertical Wells Horizontal Wells Total
AreaGrossNet GrossNet GrossNet
Midland Basin1,585
1,485
 956
872
 2,541
2,357
Delaware Basin33
30
 462
437
 495
467
Total1,618
1,515
 1,418
1,309
 3,036
2,824



As of September 30, 2019,2020, we held interests in 4,0023,588 gross (2,916(2,941 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 FivestonesGlasscock 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 fresh water sourcing and distribution assets consists of water wells, frachydraulic 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 saltwaterproduced water gathering and disposal system spans approximately 460508 miles and consists of gathering pipelines along with SWDproduced water disposal wells and facilities which collectively gather and dispose of saltwaterproduced 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.

Sources of Our Revenues

In On May 5, 2020, we amended 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.
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 September 30, Nine Months Ended September 30,
 20192018 20192018
Revenues:     
Oil sales92%86% 92%89%
Natural gas sales2%3% 1%3%
Natural gas liquid sales6%11% 7%8%
 100%100% 100%100%

Commodity Prices

Since our production, in our exploration and production business, consists primarily of oil, 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. Lower commodity prices may not only decrease our revenues, but also potentially the amount of oil and natural gas that we can produce economically. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our credit agreement, which may be redetermined at the discretion of our lenders.

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

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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.

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

 Three Months Ended September 30, Nine Months Ended September 30,
 20192018 20192018
High and Low Futures Contract Prices:     
Oil ($/Bbl, WTI Futures Contract 1)     
High$62.90
$74.14
 $66.30
$74.15
Low$51.09
$65.01
 $46.54
$59.19
Natural Gas ($/MMBtu, Futures Contract 1)     
High$2.68
$3.08
 $3.59
$3.63
Low$2.07
$2.72
 $2.07
$2.55
      
Average realized oil price ($/Bbl)$51.71
$55.96
 $50.86
$59.56
Average WTI Futures Contract 1 ($/Bbl)$56.44
$69.43
 $57.10
$66.79
Differential to WTI Futures Contract 1(4.73)(13.47) (6.24)(7.23)
Average realized oil price to WTI Futures Contract 192%81% 89%89%
      
Average realized natural gas price ($/Mcf)$0.62
$1.86
 $0.52
$1.85
Average Natural Gas Futures Contract 1 ($/Mcf)$2.33
$2.86
 $2.56
$2.85
Differential to Natural Gas Futures Contract 1(1.71)(1.00) (2.04)(1.00)
Average realized natural gas price to Natural Gas Futures Contract 127%65% 20%65%
      
Average realized natural gas liquids price ($/Bbl)$11.61
$30.26
 $14.14
$27.93
Average WTI Futures Contract 1 ($/Bbl)$56.44
$69.43
 $57.10
$66.79
Average realized natural gas liquids price to WTI Futures Contract 121%44% 25%42%

On September 30, 2019, the WTI Futures Contract 1 price for crude oil was $54.07 per Bbl and the Natural Gas Futures Contract 1 price was $2.33 per MMBtu.

2019 Recent Developments

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 Basinsof the Permian Basin. Rattler Midstream GP LLC, or Rattler’s General Partner, a wholly-owned subsidiary of Diamondback, serves as the general partner of Rattler. As of September 30, 2019, Diamondback owned approximately 71% of Rattler’s total units outstanding.

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

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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,among other things, in exchange for a $1 million cash contribution from its 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.

Third Quarter 2019 Dividend Declaration

On November 1, 2019, our board of directors declared a cash dividend for the third quarter of 2019 of $0.1875 per share of common stock, payable on November 22, 2019certain cases add certain new areas to our stockholdersdedication and commitment and revise the threshold for permitting releases of record at the close of business on November 15, 2019.

Stock Repurchase Program

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. This repurchase program is another component of our capital return program that includes the quarterly dividend discussed above. We anticipate that the repurchase program will be funded primarily by free cash flow generated from operations and liquidity events such as the sale of assets. 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 us 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 and nine months ended September 30, 2019, we repurchased approximately $296 million and $400 million, respectively, of common stock under our repurchase program. As of September 30, 2019, $1.6 billion remains available for use to repurchase shares under the Company's common stock repurchase program.

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

On May 23, 2019, we completed our divestiture of 6,589 net acres of certain conventional and non-core Permian assets, which were acquired by us in the Merger, for an aggregate sale price of $37 million. This divestiture did not result in a gain or loss because it did not have a significant effect on our reserve base or depreciation, depletion and amortization rate.

On July 1, 2019, we completed our divestiture of 103,750 net acres of certain conventional and non-core Permian assets, which were acquired by us in the Merger, for an aggregate sale price of $285 million. This divestiture did not result in a gain or loss because it did not have a significant effect on our reserve base or depreciation, depletion and amortization rate.

Viper’s Equity Offering

On March 1, 2019, Viper completed an underwritten public offering of 10,925,000 common units, which included 1,425,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Following this offering, we owned approximately 54% of Viper’s total units then outstanding. Viper received net proceeds from this offering of approximately $341 million, after deducting underwriting discounts and commissions and estimated offering expenses. Viper used the net proceeds to purchase units of Viper LLC. Viper LLC in turn used the net proceeds to repay a portion of the outstanding borrowings under its revolving credit facility and finance acquisitions during the period.


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Drop-Down and Increase in the Borrowing Base under Viper LLC’s Revolving Credit Facility
On October 1, 2019, we completed a transaction to divest certain mineral and royalty interests to Viper for 18.3 million of Viper’s newly-issued Class B units, 18.3 million newly-issued units of Viper LLC and $190 million in cash, after giving effect to closing adjustments for net title benefits, which we refer to as the Drop-Down. Based on the volume weighted average sales price of Viper’s common units for the ten trading-day period ended July 26, 2019 of approximately $30.07, the transaction is valued at $740 million. The mineral and royalty interests divested in the Drop-Down represent approximately 5,490 net royalty acres across the Midland and Delaware Basins, of which over 95% are operated by us, and have an average net royalty interest of approximately 3.2%.
Amendments to Viper’s Revolving Credit Facility

On September 24, 2019, Viper entered into a second amendment to Viper’s revolving credit facility with Wells Fargo, as administrative agent, and certain required lenders party thereto, which provided for an automatic increase of the borrowing base of $125 million upon the closing of the Drop-Down and the satisfaction of certain conditions set forth therein. On October 1, 2019, upon closing of the Drop-Down and the satisfaction of such conditions, the borrowing base was increased from $600 million to $725 million.

On October 8, 2019,dedications in connection with the commencement of the Viper Notes Offering described below, Viper entered into a third amendment to Viper LLC’s revolving credit facility with Wells Fargo, as administrative agent, and certain required lenders party thereto, which provides for the waiver of the automatic reduction of the borrowing base that would otherwise occur upon the consummation of the Viper Notes Offering. In addition, the third amendment increased the maximum amount of unsecured seniortransfers or senior subordinated notes that may be issuedswaps by Viper LLCus or Viper from $400 million to $1.0 billion. The amendment was approved by the requisite percentage of lenders under the revolving credit facility and became effective on October 8, 2019. If the amendment had not been approved, the borrowing base under the revolving credit facility would have decreased by $125 million upon consummation of the Viper Notes Offering.our affiliates.

Viper’s Notes Offering
On October 16, 2019, Viper completed an offering, which we refer to as the Viper Notes Offering of $500 million in aggregate principal amount of its 5.375% Senior Notes due 2027, which we refer to as the Viper Notes. Viper received net proceeds of approximately $492 million from the Viper Notes Offering. Viper loaned the gross proceeds to Viper LLC. Viper LLC used the proceeds from the Viper Notes Offering to pay down borrowings under its revolving credit facility.

The Viper Notes are senior unsecured obligations of Viper, initially are guaranteed on a senior unsecured basis by Viper LLC, and will pay interest semi-annually. Neither we nor Viper’s General Partner guarantee the Viper Notes. In the future, each of Viper’s restricted subsidiaries that either (1) guarantees any of its or a guarantor’s other indebtedness or (2) is a domestic restricted subsidiary and is an obligor with respect to any indebtedness under any credit facility will be required to guarantee the Viper Notes.

Amendment to Rattler Credit Agreement
On October 23, 2019, Rattler entered into the First Amendment to the Rattler credit agreement with Rattler LLC, Wells Fargo Bank, National Association, as the administrative agent, and certain lenders from time to time party thereto. The First Amendment, among other things, provides Rattler LLC with additional flexibility to make investments in joint ventures and other third parties, including investments in the Wink to Webster project and the Joint Venture. Pursuant to the First Amendment, the Joint Venture is designated as an unrestricted subsidiary under the Credit Agreement.

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Results of Operations

The following table sets forth selected historical operating data for the three months and nine months ended September 30, 20192020 and 2018:2019:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
Revenues (in millions):
Oil sales$606 $882 $1,785 $2,572 
Natural gas sales36 16 61 36 
Natural gas liquid sales65 58 156 190 
Total oil, natural gas and natural gas liquid revenues$707 $956 $2,002 $2,798 
Production Data (in thousands):
Oil (MBbls)15,639 17,064 50,009 50,581 
Natural gas (MMcf)32,505 26,271 96,482 69,394 
Natural gas liquids (MBbls)5,377 4,974 16,326 13,420 
Combined volumes (MBOE)26,433 26,417 82,415 75,567 
Daily combined volumes (BOE/d)287,315 287,138 300,785 276,802 
Daily oil volumes (BO/d)169,989 185,478 182,515 185,278 
Average Prices:
Oil ($ per Bbl)$38.75 $51.71 $35.69 $50.86 
Natural gas ($ per Mcf)$1.11 $0.62 $0.63 $0.52 
Natural gas liquids ($ per Bbl)$12.09 $11.61 $9.56 $14.14 
Combined ($ per BOE)$26.75 $36.20 $24.29 $37.03 
Oil, hedged ($ per Bbl)(1)
$38.17 $51.84 $41.31 $50.99 
Natural gas, hedged ($ per MMbtu)(1)
$0.95 $0.69 $0.57 $0.74 
Natural gas liquids, hedged ($ per Bbl)(1)
$12.09 $12.83 $9.56 $14.93 
Average price, hedged ($ per BOE)(1)
$26.22 $36.59 $27.63 $37.46 
(1)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects includes gains and losses on cash settlements for matured commodity derivatives, which we do not designate for hedge accounting. Hedged prices exclude gains or losses resulting from the early settlement of commodity derivative contracts.


37
 Three Months Ended September 30, Nine Months Ended September 30,
 20192018 20192018
 (in thousands)
Production Data:     
Oil (MBbls)17,064
8,120
 50,581
22,399
Natural gas (MMcf)26,271
7,804
 69,394
21,717
Natural gas liquids (MBbls)4,974
1,893
 13,420
4,776
Combined volumes (MBOE)26,417
11,314
 75,567
30,794
      
Average Daily Production:     
Oil (Bbls/d)185,478
88,262
 185,278
82,046
Natural gas (Mcf/d)285,554
84,826
 254,191
79,549
Natural gas liquids (Bbls/d)54,068
20,575
 49,159
17,495
Daily combined volumes (BOE/d)287,138
122,975
 276,802
112,799
      
Average Prices:     
Oil ($ per Bbl)$51.71
$55.96
 $50.86
$59.56
Natural gas ($ per Mcf)$0.62
$1.86
 $0.52
$1.85
Natural gas liquids ($ per Bbl)$11.61
$30.26
 $14.14
$27.93
Combined ($ per BOE)$36.20
$46.51
 $37.03
$48.95
Oil, hedged ($ per Bbl)(1)
$51.84
$51.20
 $50.99
$54.35
Natural gas, hedged ($ per MMbtu)(1)
$0.69
$1.89
 $0.74
$1.89
Natural gas liquids, hedged ($ per Bbl)(1)
$12.83
$30.26
 $14.93
$27.93
Average price, hedged ($ per BOE)(1)
$36.59
$43.11
 $37.46
$45.20

(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.


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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 and nine months ended September 30, 20192020 and 2018:2019:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
Oil (MBbls)59 %65 %61 %67 %
Natural gas (MMcf)21 %17 %19 %15 %
Natural gas liquids (MBbls)20 %18 %20 %18 %
100 %100 %100 %100 %

Three Months Ended September 30, 2020Three Months Ended September 30, 2019
Midland BasinDelaware Basin
Other(1)
TotalMidland BasinDelaware Basin
Other(2)
Total
(in thousands)
Production Data:
Oil (MBbls)8,971 6,627 41 15,639 10,105 6,881 78 17,064 
Natural gas (MMcf)17,403 15,003 99 32,505 12,839 13,224 208 26,271 
Natural gas liquids (MBbls)3,087 2,268 22 5,377 2,748 2,179 47 4,974 
Total (MBoe)14,958 11,395 80 26,433 14,993 11,264 160 26,417 

Nine Months Ended September 30, 2020Nine Months Ended September 30, 2019
Midland BasinDelaware Basin
Other(1)
TotalMidland BasinDelaware Basin
Other(2)
Total
(in thousands)
Production Data:
Oil (MBbls)28,864 21,013 132 50,009 30,411 18,810 1,360 50,581 
Natural gas (MMcf)50,285 45,871 326 96,482 33,605 34,846 943 69,394 
Natural gas liquids (MBbls)9,281 6,975 70 16,326 7,533 5,721 166 13,420 
Total (MBoe)46,525 35,633 257 82,415 43,545 30,339 1,683 75,567 
(1)Includes the Central Basin Platform, the Eagle Ford Shale and the Rockies.
(2)Includes the Eagle Ford Shale.


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 Three Months Ended September 30, Nine Months Ended September 30,
 20192018 20192018
Oil (MBbls)65%72% 67%73%
Natural gas (MMcf)17%11% 15%12%
Natural gas liquids (MBbls)18%17% 18%15%
 100%100% 100%100%

 Three Months Ended September 30, 2019 Three Months Ended September 30, 2018
 Midland BasinDelaware Basin
Other(1)
Total Midland BasinDelaware Basin
Other(2)
Total
 (in thousands)
Production Data:         
Oil (MBbls)10,105
6,881
78
17,064
 5,667
2,395
58
8,120
Natural gas (MMcf)12,839
13,224
208
26,271
 5,080
2,568
156
7,804
Natural gas liquids (MBbls)2,748
2,179
47
4,974
 1,423
442
28
1,893
Total (MBoe)14,993
11,264
160
26,417
 7,937
3,265
112
11,314

 Nine Months Ended September 30, 2019 Nine Months Ended September 30, 2018
 Midland BasinDelaware Basin
Other(1)
Total Midland BasinDelaware Basin
Other(2)
Total
 (in thousands)
Production Data:         
Oil (MBbls)30,411
18,810
1,360
50,581
 16,715
5,538
146
22,399
Natural gas (MMcf)33,605
34,846
943
69,394
 14,538
6,796
383
21,717
Natural gas liquids (MBbls)7,533
5,721
166
13,420
 3,738
974
64
4,776
Total (MBoe)43,545
30,339
1,683
75,567
 22,876
7,645
273
30,794
(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 September 30, 20192020 and 20182019 and Nine Months Ended September 30, 20192020 and 20182019

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 September 30, 2019 increased by $431 million, or 82%, to $956 million from $525 million during the three months ended September 30, 2018, 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.

Our oil, natural gas and natural gas liquids revenues for the nine months ended September 30, 2019 increased by $1.3 billion, or 86%, to $2.8 billion from $1.5 billion during the nine months ended September 30, 2018, primarily due to an increase in oil, natural gas and natural gas liquids production volumes partially offset by lower average sales

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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 increasechange in period-to-period volumes for oil, natural gas and natural gas liquids multiplied by the prior period average prices) are shown below:

 Three Months Ended September 30, 2019 Compared to 2018 Nine Months Ended September 30, 2019 Compared to 2018
 Change in prices
Production volumes(1)
Total net dollar effect of change Change in prices
Production volumes(1)
Total net dollar effect of change
   (in millions)    
Effect of changes in price:       
Oil$(4.25)17,064
$(72) $(8.70)50,581
$(440)
Natural gas$(1.24)26,271
(33) $(1.33)69,394
(92)
Natural gas liquids$(18.65)4,974
(92) $(13.79)13,420
(185)
Total revenues due to change in price  $(197)   $(717)
        
 
Change in production volumes(1)
Prior period Average PricesTotal net dollar effect of change 
Change in production volumes(1)
Prior period Average PricesTotal net dollar effect of change
   (in millions)    
Effect of changes in production volumes:       
Oil8,944
$55.96
$501
 28,182
$59.56
$1,679
Natural gas18,467
$1.86
34
 47,677
$1.85
88
Natural gas liquids3,081
$30.26
93
 8,644
$27.93
241
Total revenues due to change in production volumes  628
   2,008
Total change in revenues  $431
   $1,291
(1)Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.

Three Months Ended September 30, 2020 Compared to 2019Nine Months Ended September 30, 2020 Compared to 2019
Change in prices
Production volumes(1)
Total net dollar effect of changeChange in prices
Production volumes(1)
Total net dollar effect of change
(in millions)
Effect of changes in price:
Oil$(12.96)15,639 $(203)$(15.17)50,009 $(758)
Natural gas$0.49 32,505 16 $0.11 96,482 11 
Natural gas liquids$0.48 5,377 3 $(4.58)16,326 (75)
Total revenues due to change in price$(184)$(822)
Change in production volumes(1)
Prior period Average PricesTotal net dollar effect of change
Change in production volumes(1)
Prior period Average PricesTotal net dollar effect of change
(in millions)
Effect of changes in production volumes:
Oil(1,426)$51.71 $(74)(572)$50.86 $(29)
Natural gas6,235 $0.62 4 27,088 $0.52 14 
Natural gas liquids403 $11.61 5 2,905 $14.14 41 
Total revenues due to change in production volumes(65)26 
Total change in revenues$(249)$(796)
Realized pricing improved(1)Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.

Our oil, natural gas and natural gas liquids revenues for the third quarter of 2020 decreased by $249 million, or 26%, to $707 million from $956 million during the third quarter of 2019, compared to the second quarter of 2019 as some ofand our fixed differential contracts began to roll off and convert to commitments on new-build long-haul pipelines and others moved closer to current Midland market price. Based on current market differentials and estimated in-basin gathering cost, we continue to expect to realize approximately 88% to 92% or greater of WTI in the future remainder of 2019 and approximately 100% or greater of WTI in 2020.

Lease Bonus Revenue. The following table shows lease bonus revenue for the three months and nine months ended September 30, 2019 and 2018:
 Three Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
 (in millions)
Lease bonus revenue$1
 $1
 $4
 $2

Lease bonus revenue for the three months ended September 30, 2019 was attributable to lease bonus payments of less than $1 million to extend the term of three leases and lease bonus payments of less than $1 million on three new leases. Lease bonus revenuetotal revenues for the nine months ended September 30, 2019 was attributable2020 decreased by $796 million, or 28%, to lease bonus payments$2.0 billion from $2.8 billion during the same period in 2019. These declines were primarily driven by the sudden drop in demand and prices for oil stemming from the COVID-19 pandemic, which resulted in temporarily curtailing a portion of less than $1 million to extendour oil production volumes in the termsecond quarter of seven leases2020 and lease bonus payments of $3 million on 11 new leases.reducing our total capital budget and drilling and completion plan for 2020.


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39


Lease bonus revenue for the three months ended September 30, 2018 was attributable to lease bonus payments of $1 million to extend the term of 13 leases. Lease bonus revenue for the nine months ended September 30, 2018 was attributable to lease bonus payments of $2 million to extend the term of 16 leases.

Midstream Services Revenue. The following table shows midstream services revenue for the three months and nine months ended September 30, 20192020 and 2018:2019:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(in millions)
Midstream services revenue$12 $16 $37 $51 
 Three Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
 (in millions)
Midstream services revenue$16
 $8
 $51
 $27

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 operationsMidstream services revenue decreased by $4 million for the three months ended September 30, 2020 and $14 million for the nine months ended September 30, 2020 compared to the same periods in areas where we have significant production.2019 primarily due to a reduction in sourced water volumes due to the lower level of drilling and completion activity in 2020.

Lease Operating Expenses. The following table shows lease operating expenses for the three months and nine months ended September 30, 20192020 and 2018:2019:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
AmountPer BOEAmountPer BOEAmountPer BOEAmountPer BOE
(in millions, except per BOE amounts)
Lease operating expenses$102 $3.86 $128 $4.85 $332 $4.03 $364 $4.82 
 Three Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
(in millions, except per BOE amounts)AmountPer BOE AmountPer BOE AmountPer BOE AmountPer BOE
Lease operating expenses$128
$4.85
 $49
$4.34
 $364
$4.82
 $129
$4.19

Lease operating expenses for the three months ended September 30, 20192020 as compared to the three months ended September 30, 2018 increased2019 decreased by $79$26 million, or $0.51$0.99 per BOE. Lease operating expenses for the nine months ended September 30, 20192020 as compared to the nine months ended September 30, 2018 increased2019 decreased by $235$32 million, or $0.63$0.79 per BOE. In both cases, the decrease in lease operating expenses increasedwas primarily dueassociated with a reduction in well maintenance activity related to increasedoverall efficiencies gained, as well as improvements in infrastructure which reduced power generation costs as a result of reduced electrical availability. We are actively working to mitigate this issue and expect these costs to decrease in the future.trucking fees.

Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the three months and nine months ended September 30, 20192020 and 2018:2019:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
AmountPer BOEAmountPer BOEAmountPer BOEAmountPer BOE
(in millions, except per BOE amounts)
Production taxes$36 $1.36 $45 $1.69 $97 $1.18 $132 $1.75 
Ad valorem taxes19 0.72 16 0.62 51 0.62 48 0.63 
Total production and ad valorem expense$55 $2.08 $61 $2.31 $148 $1.80 $180 $2.38 
Production taxes as a % of oil, natural gas, and natural gas liquids revenue5.1 %4.7 %4.8 %4.7 %
 Three Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
(in millions, except per BOE amounts)AmountPer BOE AmountPer BOE AmountPer BOE AmountPer BOE
Production taxes$45
$1.69
 $26
$2.30
 $132
$1.75
 $74
$2.39
Ad valorem taxes16
0.62
 7
0.66
 48
0.63
 19
0.63
Total production and ad valorem expense$61
$2.31
 $33
$2.96
 $180
$2.38
 $93
$3.02

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 taxesrevenues and are based upon current year commodity prices. Production taxes as a percentage of production revenues remained consistent for the three monthsand nine month periods ended September 30, 2019 as2020 compared to the three months ended September 30, 2018 increasedsame periods in 2019.

Ad valorem taxes are based, among other factors, on property values driven by $19 million due to acquisitions of new wells combined with well completions. Production taxes per BOE for the three months ended September 30, 2019 as compared to the three months ended September 30, 2018 decreased by $0.61 primarily due to a higher percentage increase in production volumes as compared to production taxes.prior year commodity prices. Ad valorem taxes for the three months ended September 30, 20192020 as compared to the three months ended September 30, 20182019 increased by $9$3 million due to the addition of taxes associated with wells drilled in 2018 that are now being assessed by the county for 2019 taxes coupled with wells acquired in 2018.

Production taxes for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018 increased by $58 million due to increased overall production from acquisitions and well

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completions. Production taxes per BOE for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018 decreased by $0.64 primarily due to a higher percentageoverall valuations resulting from an increase in production volumes as compared to production taxes. revenues between valuation periods.
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Ad valorem taxes for the nine months ended September 30, 20192020 as compared to the nine months ended September 30, 2018 increased by $29 million due2019 remained relatively flat.

Gathering and Transportation Expense. The following table shows gathering and transportation expense for the three months and nine months ended September 30, 2020 and 2019:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
AmountPer BOEAmountPer BOEAmountPer BOEAmountPer BOE
(in millions, except per BOE amounts)
Gathering and transportation expense$33 $1.25 $25 $0.95 $105 $1.27 $54 $0.71 

For the three months and nine months ended September 30, 2020, the per BOE increases for gathering and transportation expenses are primarily attributable to the additionrecording minimum volume commitment fees in 2020, as well as an increase in fees for our gas production and an overall change in our product mix, with gas and natural gas liquids production becoming a greater percentage of acquired and completed wells from the latter half of 2018.overall production.

Midstream Services Expense. The following table shows midstream services expense for the three months and nine months ended September 30, 20192020 and 2018:2019:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(in millions)
Midstream services expense$26 $26 $81 $60 
 Three Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
 (in millions)
Midstream services expense$26
 $20
 $60
 $49

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. Midstream services expense increased for the nine months ended September 30, 2020 as compared to the nine months ended September 30, 2019 primarily due to increased oil, gas and produced water volumes largely attributable to the continued build out of our midstream assets. In addition, we incurred certain asset maintenance and workover charges related to our produced water wells to increase their capacity.

Depreciation, Depletion and Amortization. The following table provides the components of our depreciation, depletion and amortization expense for the three months and nine months ended September 30, 20192020 and 2018:2019:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(in millions, except BOE amounts)
Depletion of proved oil and natural gas properties$273 $353 $995 $1,009 
Depreciation of midstream assets9 9 29 25 
Depreciation of other property and equipment4 3 12 12 
Depreciation, depletion and amortization expense$286 $365 $1,036 $1,046 
Oil and natural gas properties depletion rate per BOE$10.33 $13.33 $12.07 $13.34 
 Three Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
        
 (in millions, except BOE amounts)
Depletion of proved oil and natural gas properties$353
 $138
 $1,009
 $371
Depreciation of midstream assets9
 6
 25
 14
Depreciation of other property and equipment3
 2
 12
 6
Depreciation, depletion and amortization expense$365
 $146
 $1,046
 $391
Oil and natural gas properties depreciation, depletion and amortization per BOE$13.33
 $12.23
 $13.34
 $12.04

The increasedecrease in depletion of proved oil and natural gas properties of $215$80 million for the three months ended September 30, 20192020 as compared to the three months ended September 30, 20182019 resulted primarily from higher production levelsa reduction in the average depletion rate for our oil and an increasenatural gas properties in 2020, which stemmed from a decrease in the net book value on new reserves added.of our properties due to the full cost ceiling impairments recorded in the first and second quarters of 2020 and fourth quarter of 2019. The increasedecrease in depletion of proved oil and natural gas properties of $638$14 million for the nine months ended September 30, 20192020 as compared to the nine months ended September 30, 20182019 resulted primarily from higherlower production levels and an increaseas well as the decrease in the net book value of our properties due to the full cost ceiling impairments recorded in 2020.


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Impairment of Oil and Natural Gas Properties. As a result of the sharp decline in commodity prices during 2020, we recorded non-cash ceiling test impairments for the three months and nine months ended September 30, 2020 of $1.5 billion and $5.0 billion, respectively, which is 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 continue to have material write downs in subsequent quarters. No impairment on new reserves added.proved oil and natural gas properties was recorded for the nine months ended September 30, 2019.

General and Administrative Expenses. The following table shows general and administrative expenses for the three months and nine months ended September 30, 20192020 and 2018:2019:

Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
AmountPer BOEAmountPer BOEAmountPer BOEAmountPer BOE
(in millions, except per BOE amounts)
General and administrative expenses$11 $0.42 $15 $0.59 $37 $0.45 $41 $0.55 
Non-cash stock-based compensation9 0.34 4 0.16 27 0.33 27 0.36 
Total general and administrative expenses$20 $0.76 $19 $0.75 $64 $0.78 $68 $0.91 

 Three Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
(in millions, except per BOE amounts)AmountPer BOE AmountPer BOE AmountPer BOE AmountPer BOE
General and administrative expenses$15
$0.59
 $9
$0.78
 $41
$0.55
 $27
$0.86
Non-cash stock-based compensation4
0.16
 5
0.47
 27
0.36
 18
0.60
Total general and administrative expenses$19
$0.75
 $14
$1.25
 $68
$0.91
 $45
$1.46

GeneralTotal general and administrative expenses for the three months ended September 30, 20192020 as compared to the three months ended September 30, 20182019 increased by $5$1 million primarily due to an increase in salariesnon-cash stock-based compensation, partially offset by decreases in contract labor, rent, legal expense and benefits as a result of increased head count.penalties. General and administrative expenses for the nine months ended September 30, 20192020 as

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compared to the nine months ended September 30, 2018 increased2019 decreased by $23$4 million primarily due to an increasedecreases in salariesrent, contract labor expense and benefits as a result of increased head count.penalties.

Net Interest Expense. The following table shows net interest expense for the three months and nine months ended September 30, 20192020 and 2018:2019:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(in millions)
Net interest expense$53 $38 $147 $133 
 Three Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
 (in millions)
Net interest expense$38
 $19
 $133
 $49

Net interest expense for the three months ended September 30, 2019 as compared to the three months ended September 30, 2018, increased by $19 million. This increase was primarily due to a higher interest rate$15 million and increased average borrowings under our credit facility during the three months ended September 30, 2019 as compared to the three months ended September 30, 2018.

Net interest expense for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018, increased by $84 million. This increase was primarily due to a higher interest rate and increased average borrowings under our credit facility during the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018 as well as an increase in interest expense of $9$14 million, related to our DrillCo Agreement.

Derivatives. The following table shows the gain (loss) on derivative instruments, netrespectively, for the three months and nine months ended September 30, 20192020 compared to the same periods in 2019. In both cases, the increases were primarily due to an increase in borrowings as well as the issuance of the May 2020 Notes.

Derivative Instruments. The following table shows the net gain (loss) on derivative instruments and 2018:the net cash receipts (payments) on settlements of derivative instruments for the three months and nine months ended September 30, 2020 and 2019:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(in millions)
Gain (loss) on derivative instruments, net$(99)$177 $82 $3 
Net cash received (paid) on settlements$(9)$11 $288 $33 
 Three Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
 (in millions)
Change in fair value of open non-hedge derivative instruments$166
 $(10) $(30) $(24)
Gain (loss) on settlement of non-hedge derivative instruments11
 (38) 33
 (115)
Gain (loss) on derivative instruments$177
 $(48) $3
 $(139)

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

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Net cash received (paid) on settlements of derivative instruments for the three and nine months ended September 30, 2020 include cash received on contracts terminated prior to their contractual maturity of $6 million and $17 million, respectively.

Provision for (Benefit from) Income Taxes. The following table shows provision for (benefit from) income taxes for the three months and nine months ended September 30, 20192020 and 2018:2019:
Three Months Ended September 30,Nine Months Ended September 30,
2020201920202019
(in millions)
Provision for (benefit from) income taxes$(304)$102 $(902)$171 
 Three Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
 (in millions)
Provision for income taxes$102
 $43
 $171
 $83

The change in our income tax provision for the third quarter of 2020 compared to the same period in 2019 was primarily due to the increase in pre-tax bookloss for the three months ended September 30, 2020, compared to pre-tax income for the three months ended September 30, 2019.

The change in our income tax provision for the first nine months of 2020 compared to the same period in 2019 was primarily due to the pre-tax loss for the nine months ended September 30, 2020, partially 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 nine months ended September 30, 2019, partially offset by a discrete income tax benefit resulting from estimated deferred taxes recognized as a result of Viper’s change in tax status for the three months ended September 30, 2019.status.

The change in our income tax provision was primarily due to the increase in pre-tax income for the nine months ended September 30, 2019 and the change in the discrete income tax benefit resulting from estimated deferred taxes recognized as a result of Viper’s change in tax status for the nine months ended September 30, 2019 and 2018.


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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 reservesour business and production growth,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 nine months ended September 30, 20192020 and 20182019 are presented below:
Nine Months Ended September 30,
20202019
(in millions)
Net cash provided by (used in) operating activities$1,715 $1,852 
Net cash provided by (used in) investing activities(1,855)(2,744)
Net cash provided by (used in) financing activities111 777 
Net increase (decrease) in cash$(29)$(115)
 Nine Months Ended September 30,
 20192018
 (in millions)
Net cash provided by operating activities$1,852
$1,153
Net cash used in investing activities(2,744)(1,819)
Net cash provided by financing activities777
1,063
Net increase (decrease) in cash$(115)$397

Operating Activities

Net cash provided by operating activities was $1.9 billion for the nine months ended September 30, 2019 as compared to $1.2 billion for the nine months ended September 30, 2018. 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 nine months ended September 30, 2019.

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


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The decrease in operating cash flows for the nine months ended September 30, 2020 compared to the same period in 2019 primarily resulted from the decline in our revenue” above.oil and natural gas revenues and a reduction in our accounts payable and other current liabilities payable during 2020 compared to an increase in payable balances during 2019. These reductions in operating cash flow were partially offset by an increase in collections on our accounts receivable during 2020 compared to 2019 and other working capital changes.

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 $2.7$1.9 billion and $1.8$2.7 billion during the nine months ended September 30, 20192020 and 2018,2019, respectively.

Capital Expenditure Activities

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

Nine Months Ended September 30,
20202019
(in millions)
Drilling, completions and non-operated additions to oil and natural gas properties(1)(2)
$1,404 $1,883 
Infrastructure additions to oil and natural gas properties96 104 
Additions to midstream assets133 186 
Total$1,633 $2,173 
(1)During the nine months ended September 30, 2020, in conjunction with our development program, we drilled 183 gross (173 net) operated horizontal wells, of which 69 gross (65 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin, and turned 136 gross (124 net) operated horizontal wells to production, of which 67 gross (63 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin.
(2)During the nine months ended September 30, 2019, we spent (a) $2.0 billion on capital expenditures in conjunction with our development program, in which we drilled 255 gross (231 net) operated horizontal wells, of which 122 gross (110 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin, and turned 239 gross (219 net) operated horizontal wells intoto production, of which 105 gross (96 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin, (b) $186 million on additions to midstream assets, (c) $311 million on leasehold acquisitions, (d) $320 million for the acquisition of mineral interests, (e) $225 million on equity investments, (f) $8 million for the purchase of other property and equipment, (g) $7 million for funds held in escrow and (h) $1 million for investment in real estate.Basin.

During the nine months ended September 30, 2018, we spent (a) $1.0 billion on capital expenditures in conjunction with our drilling program and related infrastructure projects, in which we drilled 134 gross (120 net) operated horizontal wells, of which 53 gross (49 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin, and turned 128 gross (113 net) operated horizontal wells into production, of which 54 gross (48 net) wells were in the Delaware Basin and the remaining wells were in the Midland Basin, (b) $130 million on additions to midstream assets, (c) $186 million on leasehold acquisitions, (d) $336 million for mineral interests acquisitions, (e) $111 million for investment in real estate, (f) $51 million for funds held in escrow and (g) $2 million for the purchase of other property and equipment.

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Our investing activities for the nine months ended September 30, 2019 and 2018 are summarized in the following table:
 Nine Months Ended September 30,
 20192018
 (in millions)
Drilling, completion and non-operated$(1,883)$(900)
Additions to infrastructure assets(104)(110)
Additions to midstream assets(186)(130)
Purchase of other property, equipment and land(8)(2)
Acquisition of leasehold interests(311)(186)
Acquisition of mineral interests(320)(336)
Proceeds from sale of assets301
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Investment in real estate(1)(111)
Funds held in escrow(7)(51)
Equity investments(225)—
Net cash used in investing activities$(2,744)$(1,819)

Financing Activities

Net cash provided by financing activities for the nine months ended September 30, 2020 and 2019 was $111 million and 2018 was $777 million, and $1.1 billion, respectively. During the nine months ended September 30, 2020, the amount provided by financing activities was primarily attributable to $758 million in proceeds from the May Notes Offering and Rattler Notes Offering, net of repayments on Energen’s 4.625% senior notes and 7.350% medium-term notes, as well as $47 million in proceeds from our joint venture. These net increases in cash flows from financing activities were largely offset by $321 million of payments, net of borrowings on our credit facility, $177 million of dividends to stockholders, $98 million of share repurchases as part of our stock repurchase program and $77 million in distributions to non-controlling interest.

The 2019 the amount provided by financing activities was primarily attributable to $341 million in net proceeds from Viper’s public offering completed on March 1, 2019, $720 million in net proceeds from the Rattler Offering, $42 million in proceeds from joint ventures and $241 million of borrowings, net of repayments under our credit facility, and $42 million in proceeds from our joint venture, partially offset by $79 million of distributions to non-controlling interest, $13 million of share repurchases for tax withholdings, $400 million of share repurchases as part of our stock repurchase program, and $82 million of dividends to stockholders. The 2018 amount provided by financing activities was primarily attributable to $1.1 billion of net proceeds from the issuance of new senior notes, partially offset by $194 million of repayments, net of aggregate borrowings under our credit facility in Januarystockholders and September 2018, an aggregate of $303 million of net proceeds from Viper’s public offerings, $69$79 million in distributions to non-controlling interest.


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Indebtedness

Second Amended and Restated Credit Facility

As of September 30, 2020, the maximum credit amount available under our credit agreement was $2 billion, and we had no outstanding borrowings under our credit agreement and $2 billion available for future borrowings. As of September 30, 2020, there was an aggregate of $3 million in letters of credit outstanding under our credit agreement. The weighted average interest rate on the credit facility was 1.83% and $25 million2.27% for the three months and nine months ended September 30, 2020, respectively. The credit agreement matures on November 1, 2022.

As of dividends to stockholders.September 30, 2020, we were in compliance with all financial maintenance covenants under our credit agreement.

2024The May 2020 Notes and Tender Offer for Energen’s 4.625% Senior Notes and Repurchase of Energen’s 7.35% Medium-term Notes

On October 28, 2016,May 26, 2020, we issuedcompleted a registered offering of $500 million in aggregate principal amount of 4.750% senior notes due 2024, which we refer to as the existing 2024 senior notes, under an indenture among us, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, which we refer to as the 2024 indenture. On September 25, 2018, we issued $750 million aggregate principal amount of new 4.750% senior notes due 2024, which we refer to as the new 2024 notes and, together with the existing 2024 senior notes, as the 2024 senior notes, as additional notes under, and subject to the terms of, the 2024 indenture.

The 2024 senior notes bear interest at a rate of 4.750% per annum, payable semi-annually, in arrears on May 1 and November 1 of each year, commencing on May 1, 2017 and will mature on November 1, 2024. All of our existing and future restricted subsidiaries that guarantee our revolving credit facility or certain other debt guarantee the 2024 senior notes; provided, however, that the 2024 senior notes are not guaranteed by Viper, Viper’s General Partner, Viper LLC, Rattler, Rattler’s General Partner or Rattler LLC, and will not be guaranteed by any of our future unrestricted subsidiaries.

As required under the terms of the registration rights agreements relating to the new 2024 senior notes, on March 22, 2019, we filed with the SEC our Registration Statement on Form S-4, as amended on July 3, 2019, which we refer to as the Exchange Offer S-4, relating to the exchange offers of the new 2024 senior notes for substantially identical notes registered under the Securities Act. The Exchange Offer S-4 was declared effective by the SEC on July 11, 2019 and we closed the exchange offer on August 12, 2019.
For additional information regarding the 2024 senior notes, see Note 11—Debt included in Notes to the Consolidated Financial Statements included elsewhere in this Form 10-Q.

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20254.750% Senior Notes

On December 20, 2016, we issued $500 million due 2025. Interest on the May 2020 Notes accrues from May 26, 2020, and is payable in aggregate principal amount of 5.375% senior notes due 2025, which we refer to as the exiting 2025 notes, under an indenture among us, the subsidiary guarantors party thereto and Wells Fargo, as the trustee. On January 29, 2018, we issued $300 million aggregate principal amount of new 5.375% senior notes due 2025, which we refer to as the new 2025 notes and, together with the existing 2025 notes, as additional notes under the 2025 indenture.
The 2025 senior notes bear interest at a rate of 5.375% per annum, payablecash semi-annually in arrears on May 31 and November 30 of each year, and willbeginning November 30, 2020. The May 2020 Notes mature on May 31, 2025. AllWe received net proceeds of our existing and future restricted subsidiaries that guarantee our revolving credit facility or certainapproximately $496 million from the offering.

We used the net proceeds, among other debt guarantee the 2025 senior notes; provided, however, that the 2025 senior notes are not guaranteed by Viper, Viper’s General Partner, Viper LLC, Rattler, Rattler’s General Partner or Rattler LLC, and will not be guaranteed by any of our future unrestricted subsidiaries.
For additional information regarding the 2025 senior notes, see Note 11—Debt includedthings, to make an equity contribution to Energen to purchase $209 million in Notes to the Consolidated Financial Statements included elsewhere in this Form 10-Q.

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 $530Energen’s 4.625% senior notes pursuant to a tender offer. As of September 30, 2020, $191 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. The Energen Notes consist of: (a) $400 million aggregate principal amount of Energen’s 4.625% senior notes due on September 1, 2021, (b) $100remained outstanding.

During the third quarter of 2020, we repurchased all $10 million in principal amount of 7.125% notes due on February 15, 2028, (c) $20 million of 7.320%Energen’s outstanding 7.350% medium-term notes due on July 28, 2022, and (d) $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, including any unsecured guaranties by Energen of our indebtedness, and are effectively subordinated to Energen’s senior secured indebtedness, including Energen’s secured guaranty of all borrowings and other obligations under our revolving credit facility, to the extent of the value of the collateral securing such indebtedness.
For additional information regarding the Energen Notes, See Note 11—Debt included in Notes to the Consolidated Financial Statements included elsewhere in this Form 10-Q.

Second Amended and Restated Credit Facility

We and Diamondback O&G LLC, as borrower, entered into the second amended and restated credit agreement, dated November 1, 2013, as amended, with a syndicate of banks, including Wells Fargo, as administrative agent, and its affiliate Wells Fargo Securities, LLC, as sole book runner and lead arranger. On June 28, 2019, the credit agreement was amended pursuant to an eleventh amendment, which implemented certain changes to the credit facility for the period on and after the date on which our unsecured debt achieves an investment grade rating from two rating agencies and certain other conditions in the credit agreement are satisfied (the “investment grade changeover date”). The maximum credit amount available under the credit agreement is $5 billion, subject, prior to the investment grade changeover date, to a borrowing base based on our oil and natural gas reserves and other factors (the “borrowing base”) and the elected commitment amount. Prior to the investment grade changeover date, the borrowing base is scheduled to be redetermined, under certain circumstances, annually with an effective date of May 1st, and, under certain circumstances, semi-annually with effective dates of May 1st and November 1st. In addition, we and Wells Fargo may each request up to two interim redeterminations of the borrowing base during any 12-month period. On and after the investment grade changeover date, the maximum credit amount available under the credit agreement will be based solely on the commitments of the lenders, and will no longer be limited by the borrowing base. On the investment grade changeover date, the aggregate commitments of the lenders will be set at an amount equal to the aggregate elected commitment amount in effect on such date. As of September 30, 2019, the borrowing base was set at $3.4 billion, we had elected a commitment amount of $2.5 billion and we had approximately $1.6 billion of outstanding borrowings under our revolving credit facility and $0.9 billion available for future borrowings under our revolving credit facility.

Diamondback O&G LLC is the borrower under the credit agreement. As of September 30, 2019, the credit agreement is guaranteed by us, Diamondback E&P LLC and Energen and its subsidiaries and will also be guaranteed

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by any of our future subsidiaries that are classified as restricted subsidiaries under the credit agreement. On and after the investment grade changeover date, we and Diamondback O&G LLC will no longer be required to cause all restricted subsidiaries to guarantee the credit agreement, and, in certain circumstances, may cause guaranties made by subsidiary guarantors to be released. Prior to the investment grade changeover date, the credit agreement is also secured by substantially all of the assets of us, Diamondback O&G LLC and the guarantors. On and after the investment grade changeover date, the credit agreement will be unsecured and all liens securing the credit facility will be released.
The outstanding borrowings under the credit agreement bear interest2027 at a per annum rate elected by us that is equal to an alternate base rate (which is equal to the greatestprice 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. Prior to the investment grade changeover date, the applicable margin ranges from 0.25% to 1.25% in the case of the alternate base rate and from 1.25% to 2.25% in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the least of the maximum credit amount, the borrowing base and the elected commitment amount. On and after the investment grade changeover date, the applicable margin will range from 0.125% to 1.0% per annum in the case of the alternate 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’ rating of our unsecured debt. Prior to the investment grade changeover date, we are 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. On and after the investment grade changeover date, the commitment fee will range from 0.125% to 0.350% per year on the unused portion of the commitment, based on the pricing level, which in turn depends on the rating agencies’ rating of our unsecured debt.
Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage). Prior to the investment grade changeover date, loan principal is required to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2022. On and after the investment grade changeover date, loan principal is required to be repaid (a) to the extent the loan amount exceeds the commitment due to any termination or reduction120% of the aggregate maximum credit amount and (b) at the maturity date of November 1, 2022.
The credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements and require the maintenance of the financial ratios described below.
Financial Covenant (prior to the investment grade changeover date)Required Ratio
Ratio of total net debt to EBITDAX, as defined in the credit agreementNot greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreementNot less than 1.0 to 1.0

The covenant prohibiting additional indebtedness, applicable prior to the investment grade changeover date, allows for the issuance of unsecured debt in the form of senior or senior subordinated notes if no default would result from the incurrence of such debt after giving effect thereto and if, in connection with any such issuance, the borrowing base is reduced by 25% of the stated principal amount of each such issuance.
On and after the investment grade changeover date, the financial covenants listed above will be replaced by a financial covenant that will require the Company to not permit the total net debt to capitalization ratio, as defined in the credit agreement, to exceed 65%. Additionally, on and after the investment grade changeover date, many of the negative covenants set forth in the credit agreement will no longer restrict us, Diamondback O&G LLC and our restricted subsidiaries (the “Restricted Group”), including the covenants that limit (i) equity repurchases, dividends and other restricted payments, (ii) redemptions of the senior or senior subordinated notes, (iii) making investments, (iv) dispositions of property, (v) transactions with affiliates, and (vi) entering into swap agreements. In addition, on and after the investment grade changeover date, (i) the debt covenant will no longer restrict incurrences of debt by Diamondback O&G LLC and guarantors, and will allow non-guarantor restricted subsidiaries to 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 (ii) the liens covenant will be modified to allow the Restricted Group to create liens if the aggregate amount of debt secured by such liens does not exceed 15% of consolidated net tangible assets.

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amount.
On August 28, 2019, we, the borrower and certain of our subsidiaries, which we refer to collectively as the loan parties, entered into a Consent Letter with Wells Fargo allowing the loan parties to enter into certain swap agreements in respect of interest rates for United States Treasury securities for an aggregate notional principal amount of up to $3 billion, subject to certain conditions set forth in the consent, which otherwise would be in excess of the notional principal amount of interest rate swap agreements permitted under the revolving credit facility immediately prior to the effectiveness of the consent. As of September 30, 2019, the borrower was party to interest rate swap agreements with an aggregate notional principal amount of $2 billion, interest rates ranging from 1.35650% to 2.1509% and maturity dates ranging from August 24, 2020 to December 31, 2050.

As of September 30, 2019, we were in compliance with all financial covenants under our revolving credit facility. 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. With certain specified exceptions, the terms and provisions of our revolving credit facility generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.

Viper’s Credit Agreement

On July 20, 2018,The Viper as guarantor, entered into an amended and restated credit agreement with Viper LLC, as borrower, Wells Fargo, as administrative agent, and the other lenders. The credit agreement, as amended, toor the date hereof,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”) and a maturity date of $725 million, subject to scheduled semi-annual and other elective borrowing base redeterminations.November 1, 2022. The borrowing base is scheduled to be re-determined semi-annually with effective dates ofin May 1st and November 1st.November. In addition, Viper LLC and Wells Fargo each may request up to three interim redeterminations of the borrowing base during any 12-month period. Upon closing of the Drop-Down on October 1, 2019, theViper LLC’s borrowing base under Viper LLC’s revolving credit facility was increased by $125reduced from $775 million to $725$580 million from $600 during the regularly scheduled (semi-annual) spring 2020 redetermination in the second quarter of 2020, and is expected to be reaffirmed at $580 million. In connection with the commencement of the Viper Notes Offering described in Note 20—Subsequent Events below, Viper entered into a third amendment to Viper LLC’s revolving credit facility with Wells Fargo, as administrative agent, and certain required lenders party thereto, which provides for the waiver of the automatic reduction of the borrowing base that would otherwise occur upon the consummation of the Viper Notes Offering. In addition, the third amendment increased the maximum amount of unsecured senior or senior subordinated Viper Notes that may be issued by Viper LLC or Viper from $400 million to $1.0 billion. The amendment was approved by the requisite percentage of lenders underduring the revolving credit facility and became effective on October 8, 2019. If the amendment had not been approved, the borrowing base under the revolving credit facility would have decreased by $125 million upon consummation of the Viper Notes Offering.regularly scheduled (semi-annual) fall 2020 redetermination in November 2020.

As of September 30, 2019, the borrowing base was set at $600 million, and2020, Viper LLC had $410$127 million of outstanding borrowings and $190$453 million available for future borrowings under its revolving credit facility. Viper funded the cash portion of the purchase price for the Drop-Down through a combination of cash on hand and borrowings under Viper LLC’s revolving credit facility. Viper LLC used the proceeds from the Viper Notes Offering to pay down borrowings under its revolving credit facility. Following these transactions, as of October 16, 2019, the closing date of the Viper Notes Offering, there was $95 million in outstanding borrowings under Viper LLC’s revolving credit facility, the borrowing base under Viper LLC’s revolving credit facility was $725 million and Viper LLC had $630 million of available borrowing capacity under its revolving credit facility. Additionally, in connection with Viper’s fall redetermination expected to occur in November 2019, the lead bankagreement. Amounts borrowed under the Viper LLC’s revolving credit facility has recommended a borrowing base increase to $775 million from the current borrowing base of $725 million. The anticipated increase in the borrowing base is subject to approval by the requisite lenders under Viper LLC’s revolving credit facility.

The outstanding borrowings under Viper’s credit agreement bearbore interest at a per annumweighted average rate elected byof 2.14% and 2.66% for the three months and nine months ended September 30, 2020, respectively.

As of September 30, 2020, 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,was in each case plus the applicable margin. The applicable margin ranges from 0.75% to 1.75% per annum in the case of the alternate base rate and from 1.75% to 2.75% per annum in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the lesser of the maximum credit amount and the borrowing base. Viper LLC is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure

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period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default existscompliance with all financial maintenance covenants under the credit agreement and (c) 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 and entering into certain swap agreements, and require the maintenance of the financial ratios described below:agreement.

Financial CovenantRequired Ratio
Ratio of total net debt to EBITDAX, as defined in the credit agreementNot greater than 4.0 to 1.0
Ratio of current assets to liabilities, as defined in the credit agreementNot less than 1.0 to 1.0

The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $400 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.

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

Viper’s Notes Offering

On October 16, 2019, Viper completed the Viper Notes Offeringan offering in which it issued its 5.375% Senior Viper Notes due 2027 in aggregate principal amount of $500 million.million, or the Viper Notes. Viper received net proceeds of approximately $492$490 million from the Viper Notes Offering. Vipernotes offering and loaned the gross proceeds to Viper LLC. Viper LLC used the proceeds from the Viper Notes Offering to pay down borrowings under its revolving credit facility.

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 Bank, National Association, as trustee, which we refer to as the Viper Indenture. Pursuant to the Viper Indenture, interestcredit agreement. Interest on the Viper Notes accrues at a rate of 5.375% per annum on the outstanding principal amount thereof, from October 16, 2019, 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.

TheAs of September 30, 2020, Viper Notes are Viper’s senior unsecured obligations and rank equallyrepurchased $20 million in right of payment with all of its existing and future senior indebtedness and senior in right of payment to any of Viper’s future subordinated indebtedness. Viper LLC is guaranteeing the Viper Notes pursuant to the Viper Indenture. Neither we nor Viper’s General Partner guarantee the Viper Notes. All of Viper’s future restricted subsidiaries that either guarantee Viper LLC’s revolving credit facility or certain other debt or are classified as domestic restricted subsidiaries under the Viper Indenture will also guarantee the Viper Notes. The guarantee ranks equally in right of payment with all of the existing and future senior unsecured indebtedness of Viper LLC and senior in right of payment to any future subordinated indebtedness of Viper LLC. The Viper Notes and the guarantee are effectively subordinated to all of Viper and Viper LLC’s secured indebtedness (including all borrowings and other obligations under Viper LLC’s revolving credit facility) to the extent of the value of the collateral securing such indebtedness, and will be structurally subordinated to all indebtedness and other liabilities, including trade payables, of any of our subsidiaries that do not guarantee the Viper Notes (other than liabilities owed to Viper).

Viper may on any one or more occasions redeem some or all of the Viper Notes at any time on or after November 1, 2022 at the redemption prices listed in the Viper Indenture. Prior to November 1, 2022, Viper may on any one or more occasions redeem all or a portion of the Viper Notes at a price equal to 100% of the principal amount of the Viper Notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to November 1, 2022, Viper may on any one or more occasions redeemoutstanding Viper Notes in anopen market purchases at a cash price ranging from 97.5% to 98.5% of the aggregate principal amount, not to exceed 40%which resulted in an immaterial gain on extinguishment of thedebt. As of September 30, 2020, $480 million in aggregate principal amount of the Viper 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 not greater than the net cash proceeds from certain equity offerings.remained outstanding.


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If Viper experiences a changeTable of control (as defined in the Viper Indenture), Viper will be required to make an offer to repurchase the Viper Notes at a price equal to 101% of the aggregate principal amount thereof, plus accrued and unpaid interest, if any, to but not including the date of repurchase. If Viper sells certain assets and fail to use the proceeds in a manner specified in the Indenture, Viper will be required to use the remaining proceeds to make an offer to repurchase the Viper Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase.Contents

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 including equity of restricted subsidiaries, agree to payment restrictions affecting our 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. Certain of these covenants are subject to termination upon the occurrence of certain events.

Rattler’s Credit Agreement

In connection with the Rattler Offering, Rattler, as parent, and Rattler LLC, as borrower, entered into a credit agreement, dated May 28, 2019, with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of banks, including Wells Fargo Bank, National Association, 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. Loan principal may be optionally repaid from timemillion, which is expandable to time without premium or penalty (other than$1 billion upon Rattler’s election, subject to obtaining additional lender commitments and satisfaction of customary LIBOR breakage), and is required to be paid at the maturity date of May 28, 2024. The loan is guaranteed by Rattler and Tall City, and is secured by substantially all of the assets of Rattler LLC, Rattler and Tall City.conditions. As of September 30, 2019,2020, Rattler LLC had $103$85 million of outstanding borrowings and $497$515 million available for future borrowings under the Rattler Credit Agreement.

credit agreement. The weighted average interest rate on the credit facility was 1.46% and 2.18% for the three months and nine months ended September 30, 2020, respectively. The Rattler credit agreement has a maturity date of May 28, 2024. In connection with the offering of the Rattler Notes described below completed on July 14, 2020, Rattler LLC used the proceeds of the offering to repay a portion of the outstanding borrowings under the Rattler credit agreement bear interest at a per annum rate elected byagreement.

As of September 30, 2020, Rattler LLC that is based on the prime rate or LIBOR,was 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. Thesecompliance with all financial maintenance covenants among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, distributions and other restricted payments, transactions with affiliates, and entering into certain swap agreements, in each case of Rattler, Rattler LLC and their restricted subsidiaries. The covenants are subject to exceptions set forth in the Rattler credit agreement, including an exception allowing Rattler LLC or Rattler to issue unsecured debt securities and an exception allowing payment of distributions if no default exists. The Rattler credit agreement may be used to fund capital expenditures, to finance working capital, for general company purposes, to pay fees and expenses related to the Rattler credit agreement, and to make distributions permitted under the Rattler credit agreement.


71Rattler’s Notes

TableOn July 14, 2020, Rattler completed an offering of Contents

$500 million in aggregate principal amount of its 5.625% Senior Notes due 2025, or the Notes Offering. Interest on the Rattler Notes is payable on January 15 and July 15 of each year, beginning on January 15, 2021. The Rattler credit agreement also contains financial maintenance covenants that requireNotes mature on July 15, 2025. Rattler received net proceeds of approximately $490 million from the maintenanceNotes Offering. Rattler loaned the gross proceeds to Rattler LLC under the terms of a subordinated promissory note, dated as of July 14, 2020. The promissory note requires Rattler LLC to repay the intercompany loan to Rattler on the same terms and in the same amounts as the Rattler Notes and has the same maturity date, interest rate, change of control repurchase and redemption provisions. Rattler LLC used the proceeds from the Notes Offering to repay a portion of the financial ratios described below:
Financial CovenantRequired Ratio
Consolidated Total Leverage Ratio commencing with the fiscal quarter ending September 30, 2019Not 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 madeNot greater than 3.50 to 1.00
Consolidated Interest Coverage Ratio (as defined in the Rattler credit agreement) commencing with the fiscal quarter ending September 30, 2019Not 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 September 30, 2019, each of Rattler and Rattler LLC were in compliance with all financial covenantsoutstanding borrowings under the Rattler credit agreement. The lenders may accelerate all of

For additional information regarding our indebtedness, see Note 10—Debt included in Notes to 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 changeCondensed Consolidated Financial Statements included elsewhere in control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial maintenance covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods. With certain specified exceptions, the terms and provisions of the Rattler credit agreement generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.this report.

Capital Requirements and Sources of Liquidity

Our board of directors approved a 20192020 capital budget for drilling and completion, midstream and infrastructure of approximately $2.7$2.8 billion to $3.0 billion. In response to the current commodity price environment, in the third quarter of 2020 we have updated our 20192020 capital budget to narrow our anticipated capital expenditures for 20192020 to approximately $2.85$1.8 billion to $2.9$1.9 billion, from the originalrepresenting a decrease of 36% over our 2019 capital budget of $2.7 billion to $3.0 billion.budget. We estimate that, of these expenditures, approximately:

•$2.451.565 billion to $2.5$1.630 billion will be spent on drilling and completing 310170 to 315200 gross (279(153 to 284180 net) horizontal wells across our operated leasehold acreage in the Northern Midland and Southern Delaware Basins, with an average lateral length of approximately 9,60010,000 feet;

•$250125 million to $150 million will be spent on midstream infrastructure, excluding the cost of long-haul pipeline equityjoint venture investments; and

•$150110 million to $120 million will be spent on infrastructure and other expenditures, excluding the cost of any leasehold and mineral interest acquisitions.

During the nine months ended September 30, 2019, our aggregate capital expenditures for our development program were $2.0 billion. Additionally during the nine months ended September 30, 2019, we spent approximately $631 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.

During the third quarter of 2020, we spent $219 million on drilling and completion, $39 million on midstream, $7 million on non-operated properties and $16 million on infrastructure, for total capital expenditures of $281 million. During the nine months ended September 30, 2020, we spent $1.3 billion on drilling and completion, $133 million on midstream, $96 million on infrastructure and $57 million on non-operated properties, for total capital expenditures of $1.6 billion.

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 $296 million and $400 million, respectively,Under this program, we did not repurchase any of our common stock under this program during the three months andthird quarter of 2020, but repurchased approximately $98 million of common stock during the nine months ended September 30, 2019, with2020. Although we have approximately $1.6$1.3 billion remaining available for future repurchases under this program. We intendprogram, we have suspended the program to continue to purchase shares under the repurchase program opportunistically with available funds primarily from cashpreserve liquidity.


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flow from operations and liquidity events such as the saleTable of assets while maintaining sufficient liquidity to fund our capital expenditure programs.Contents

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 21six drilling rigs and eightthree 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 2019,2020, 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 2019.the 12-month period following the filing of this report. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. Further, our 20192020 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.

We currently anticipate
Guarantor Financial Information

As of September 30, 2020, Diamondback O&G LLC is the sole guarantor under the December 2019 Notes Indenture governing the December 2019 Notes and the May 2020 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 December 2019 Notes, the May 2020 Notes and the 2025 Senior Notes are “full and unconditional,” as that our 2020 capital budgetterm 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 rangeDecember 2019 Notes Indenture and the 2025 Indenture, such as, with certain exceptions, (1) in the event Diamondback O&G LLC (or all or substantially all of $2.8 billionits assets) is sold or disposed of, (2) in the event Diamondback O&G LLC ceases to $3.0 billion,be a guarantor of or otherwise be an obligor under certain other indebtedness, and (3) in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the relevant indenture.
Diamondback O&G LLC’s guarantees of the December 2019 Notes, the May 2020 Notes 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 $2.45 billionits obligations under its revolving credit facility, and effectively subordinated to $2.6 billionany of its existing and future secured indebtedness, to drill, completethe 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.

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The following tables present summarized financial information for Diamondback Energy, Inc., as the parent, and equip wells, $200 million to $225 million of midstream capital expenditures and $150 million to $175 million of infrastructure capital expenditures. We plan to complete over 10% more net lateral feet and over 20 more gross total wells withinDiamondback O&G LLC, as the same consolidated capital budget framework as in 2019. This plan is expected to result in 10% to 15% estimated year-over-year oil production growth, while generating free cash flow after paying our dividend, basedguarantor subsidiary, on a commodity price deckcombined basis after elimination of $45 per Bbl WTI for oil,(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 realized pricenon-guarantor. The information is presented in accordance with the requirements of $13 per Bbl for natural gas liquids and a realized priceRule 13-01 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of $1.50 per Mcf for natural gas. Should commodity prices decline in 2020, we are prepared to act responsibly and reduce our capital spendingresults of operations or financial position had the guarantor subsidiary operated as we have done multiple times over the past few years. If commodity prices increase during 2020, we plan to use excess cash flow to complete our previously announced stock repurchase program or pay down indebtedness. Over the long term, we anticipate that we will continue to grow production and cash flow on a per share basis, while maintaining our best in class cost structure.an independent entity.

September 30, 2020December 31, 2019
Summarized Balance Sheets(in millions)
Assets
Current assets$303 $396 
Property and equipment, net7,923 10,109 
Other noncurrent assets7 17 
Liabilities
Current liabilities$214 $167 
Intercompany accounts payable, non-guarantor subsidiary386 600 
Long-term debt4,268 3,782 
Other noncurrent liabilities1,124 504 

Nine Months Ended September 30, 2020
Summarized Statement of Operations(in millions)
Revenues$1,185 
Income (loss) from operations(2,627)
Net income (loss)(1,535)

Contractual Obligations

Except asOther than the changes in debt discussed in Note 19 of the10—Debt included in Notes to the Condensed Consolidated Financial Statements ofincluded elsewhere in this report, there were no material changes to our contractual obligations and other commitments, asfrom those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2018.2019.

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, 2018.2019.

Off-Balance Sheet Arrangements

We had no material off-balance sheet arrangements as of September 30, 2019.2020. Please read Note 1917 included in Notes to the Condensed 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 negative levels. This was a result of multiple factors affecting supply and demand in global oil and gas markets, including actions taken by OPEC members and other oil exporting nations impacting commodity price and production levels and a significant decrease in demand due to the ongoing COVID-19 pandemic, which resulted in a widespread health and economic crisis. While OPEC members and certain other nations agreed in April of 2020 to cut production, which helped to reduce a portion of the excess supply in the market and improve oil prices, there is no assurance that this agreement will continue or be observed by its parties, and downward pressure on commodity prices has continued and could continue for the foreseeable future. We cannot predict if or when commodity prices will stabilize and at what levels.

We use price swap derivatives, including swaps, basis swaps, double-up swaps, put spreads, interest rate swaps, swaptions, rolling hedges, calls, options, costless collars 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 paymentPlease read Note 14 included in Notes to the counterparty if the settlement priceCondensed Consolidated Financial Statements set forth in Part I, Item 1 of this report, 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.a discussion of our derivatives.

At September 30, 2019 and December 31, 2018,2020, we had a net assetliability derivative position related to our commodity price swap derivatives of $166$115 million, and $216 million, respectively, related to our price swap, price basis swap derivatives and three-waycostless collars. Utilizing actual derivative contractual volumes under our fixedcommodity price swapsderivatives as of September 30, 2019,2020, a 10% increase in forward curves associated with the underlying commodity would have decreasedincreased the net asset position to a net liability position to $151 million, an increase of $60 million, a decrease of $225$36 million, while a 10% decrease in forward curves associated with the underlying commodity would have increasedconverted the net liability position to a net asset derivative position to $390of $78 million, an increasea change of $225$37 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.

For additional information on our open commodity derivative instruments at September 30, 2020, see Note 14—Derivatives included in Notes to the Condensed Consolidated Financial Statements elsewhere in this report.

Counterparty and Customer Credit Risk

Our principal exposures to credit risk are through receivables resulting from joint interest receivables (approximately $171$67 million at September 30, 2019)2020) and receivables from the sale of our oil and natural gas production (approximately $367$224 million at September 30, 2019)2020).

We are subject to credit risk due to the concentration of our oil and natural gas receivables with severala limited number of significant customers. We do not require our customers to post collateral, and the failure or inability of our significant customers to meet their obligations to us ordue to their liquidity issues, bankruptcy, insolvency or liquidation may adversely affect our financial results. For the nine months ended September 30, 2019, four purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (28%), Plains Marketing LP (23%), Vitol Midstream (11%) and Occidental Energy Marketing Inc (10%). For the nine months ended September 30, 2018, three purchasers each accounted for more than 10% of our revenue: Shell Trading (US) Company (26%), Koch Supply & Trading LP (18%) and Rio Oil & Gas LLC (11%). 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 September 30, 2019, we had 11 customers that represented approximately 78%

The ongoing COVID-19 pandemic, depressed commodity pricing environment and adverse macroeconomic conditions may enhance our customer credit risk.
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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 September 30, 2019, we had $1.6 billion in outstanding borrowings under We have used interest rate swaps and treasury locks to reduce our exposure to variable rate interest payments associated with our revolving credit facility. Our weighted average

The following table summarizes the Company’s interest rate on borrowings under our revolving credit facility was 3.54%swaps and treasury locks as of September 30, 2019. An increase or decrease of 1% in the2020:
TypeEffective DateContractual Termination DateNotional Amount (in millions)Interest Rate
Interest Rate SwapDecember 31, 2020December 31, 2030$250 1.551 %
Interest Rate SwapDecember 31, 2020December 31, 2030$250 1.5575 %
Interest Rate SwapDecember 31, 2020December 31, 2030$250 1.297 %
Interest Rate SwapDecember 31, 2020December 31, 2030$250 1.195 %

For additional information on our variable interest rate would have a corresponding increase or decreasedebt at September 30, 2020, see Note 10—Debt included in our interest expenseNotes to the Condensed Consolidated Financial Statements elsewhere in this report. See Note 18—Subsequent Events for discussion of approximately $16 million based on the $1.6 billion outstanding under our revolving credit facility as of such date.derivative transactions which occurred subsequent to September 30, 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 September 30, 2019,2020, 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 September 30, 2019,2020, 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 September 30, 20192020 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 routine legal proceedings, disputes and claims arising in the ordinary course of our business, including those that arise from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry.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.operations or cash flows.

ITEM 1A. RISK FACTORS

Our business faces many risks. Any of the risks discussed in this Form 10-Qreport 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 additionAs of the date of this filing, we continue to the information set forth in this report, you should carefully considerbe subject to the risk factors discussedpreviously disclosed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2018.

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 activity2019, filed with the SEC on February 27, 2020, and in Part II, Item 1A. Risk Factors in our Quarterly Report on Form 10-Q for the nine monthsquarterly period ended September 30, 2019 was as follows:March 31, 2020, filed with the SEC on May 8, 2020. Depending on the duration of the COVID-19 pandemic and its severity and related economic repercussions, however, the negative impact of many of the risks discussed in such reports may be heightened or exacerbated. For a discussion of the recent trends and uncertainties impacting our business, see also “Management’s Discussion and Analysis of Financial Condition and Results of Operations—2020 Recent Developments—COVID-19 and Collapse in Commodity Prices” and “—Our Response to the Commodity Price Volatility and Impact of COVID.”

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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 2019 0 $—
 0 $2,000
February 2019(3)
 108 $102.14
 0 $2,000
March 2019(3)
 17 $102.93
 0 $2,000
April 2019 0 $—
 0 $2,000
May 2019 40 $100.86
 40 $1,996
June 2019 976 $102.04
 976 $1,896
July 2019 995 $105.56
 995 $1,791
August 2019 1,252 $97.53
 1,252 $1,669
September 2019 707 $97.29
 707 $1,600
Total 4,095 $100.69
 3,970  
(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 may be suspended from time to time, modified, extended or discontinued by our board of directors at any time.
(3)Acquired in connection with tax withholdings and payment of exercise price on equity compensation plans.

Table of Contents

ITEM 6.    EXHIBITS
EXHIBIT INDEX
Exhibit NumberDescription
2.1#
Agreement and Plan of Merger, dated as of August 14, 2018, by and among Diamondback Energy, Inc., Sidewinder Merger Sub Inc. and Energen Corporation (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on August 15, 2018).
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
Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on November 16, 2012).
3.4
First Amendment to theSecond 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 April 27, 2018)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
Indenture, dated as of October 28, 2016,July 14, 2020, among Diamondback Energy, Inc., theRattler Midstream LP, as issuer, Rattler Midstream Operating LLC, Tall City Towers LLC, Rattler Ajax Processing LLC, and Rattler OMOG LLC, as guarantors, party thereto and Wells Fargo Bank, National Association, as trustee (including the form of Diamondback Energy, Inc.’s 4.750 % Senior Notes due 2024) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on November 2, 2016).
4.3
First Supplemental Indenture, dated as of September 25, 2018, among Diamondback Energy, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on October 1, 2018).
4.4
Second Supplemental Indenture for the 4.750% Senior Notes due 2024, dated as of October 12, 2018, among Sidewinder Merger Sub Inc., a subsidiary of the Company, the Company, the other guarantors under the indenture and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.4 to the Form 10-K, File No. 001-35700, filed by the Company with the SEC on February 25, 2019).
4.5
Third Supplemental Indenture for the 4.750% Senior Notes due 2024, dated as of January 28, 2019, among Energen Corporation, Energen Resources Corporation, and EGN Services, Inc., each a direct or indirect subsidiary of the Company, the Company, the other guarantors under the indenture and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.5 to the Form 10-K, File No. 001-35700, filed by the Company with the SEC on February 25, 2019).
4.6
Indenture, dated as of December 20, 2016, among Diamondback Energy, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (including the form of Diamondback Energy, Inc.’s 5.375%Rattler Midstream LP’s 5.625% Senior Notes due 2025) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 001-35700,001-38919, filed by the CompanyRattler Midstream LP with the SEC on December 21, 2016)July 14, 2020).
4.710.1*
First Supplemental Indenture,Second Amendment, dated as of January 29, 2018, among Diamondback Energy, Inc., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on January 30, 2018).
4.8
Second Supplemental Indenture for the 5.375% Senior Notes due 2025, dated as of October 12, 2018, among Sidewinder Merger Sub Inc., a subsidiary of the Company, the Company, the other guarantors and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.8 to the Form 10-K, File No. 001-35700, filed by the Company with the SEC on February 25, 2019).
4.9
Third Supplemental Indenture for the 5.375% Senior Notes due 2025, dated as of January 28, 2019, among Energen Corporation, Energen Resources Corporation, and EGN Services, Inc., each a direct or indirect subsidiary of the Company, the Company, the other guarantors under the indenture and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.9 to the Form 10-K, File No. 001-35700, filed by the Company with the SEC on February 25, 2019).
4.10
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).

Exhibit NumberDescription
4.11
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).
4.12
Form of Indenture, dated September 1, 1996, between Energen and The Bank of New York as trustee (incorporated by reference to Exhibit 4(i) to Energen’s Registration Statement on Form S-3, Registration No. 333-11239, filed with the SEC on August 30, 1996).
4.13
Indenture, dated as of October 16, 2019, among Viper Energy Partners LP, as issuer, Viper Energy Partners LLC, as guarantor, and Wells Fargo Bank, National Association, as trustee (including the form of Viper Energy Partners LP’s 5.375% Senior Notes due 2027) (incorporated by reference to Exhibit 4.1 of Viper Energy Partners LP’s Current Report on Form 8-K (File 001-36505) filed on October 17, 2019).
10.1
Consent Letter, dated August 28, 2019, between Diamondback Energy, Inc., as parent guarantor, Diamondback O&G LLC, as borrower, certain other subsidiaries of Diamondback Energy, Inc. as guarantors, Wells Fargo Bank, National Association, as administrative agent, and the lenders party thereto. (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File 001-35700) filed on September 4, 2019).
10.2
Subordinated Promissory Note, dated as of October 16, 2019, by Viper Energy Partners LLC in favor of Viper Energy Partners LP (incorporated by reference to Exhibit 10.2 of Viper Energy Partners LP’s Current Report on Form 8-K (File 001-36505) filed on October 17, 2019).
10.3
Second Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of September 24, 2019, among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lender party thereto (incorporated by reference to Exhibit 10.1 of Viper Energy Partners LP’s Current Report on Form 8-K (File 001-36505) filed on September 30, 2019).
10.4
Third Amendment to Amended and Restated Senior Secured Revolving Credit Agreement, dated as of October 8, 2019, among Viper Energy Partners LLC, as borrower, Viper Energy Partners LP, as parent guarantor, Wells Fargo Bank, National Association, as administrative agent, and the lender party thereto (incorporated by reference to Exhibit 10.1 of Viper Energy Partners LP’s Current Report on Form 8-K (File 001-36505) filed on October 10, 2019).
10.5
First Amendment2, 2020, to the Credit Agreement, dated May 28, 2019, as ofamended on October 23, 2019, by and among Rattler Midstream Operating LLC, as borrower, Rattler Midstream LP, as parent, Wells Fargo Bank, National Association, as the administrative agent, and certain lenders from time to time party theretothereto.
22.1
List of Issuers and Guarantor Subsidiaries (incorporated by reference to Exhibit 10.1 of Rattler Midstream LP’s Current Report22.1 to the Form 10-Q, File No. 001-35700, filed by the Company with the SEC on Form 8-K (File 001-38919) filed on October 28, 2019)May 7, 2020).
31.1*
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
31.2*
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
32.1**
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
32.2**
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
101The following financial information from the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2019,2020, formatted in Inline XBRL: (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statement of Changes in Stockholders’ Equity, (iv) Condensed Consolidated Statements of Cash Flows and (v) Condensed Notes to Consolidated Financial Statements.
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
______________
*Filed herewith.
**
The certifications attached as Exhibit 32.1 and Exhibit 32.2 accompany this AnnualQuarterly Report on Form 10-K10-Q pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.
#
Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant hereby undertakes to furnish supplementally copies of any of the omitted schedules upon request by the SEC.


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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:November 6, 20195, 2020/s/ Travis D. Stice
Travis D. Stice
Chief Executive Officer
(Principal Executive Officer)
Date:November 6, 20195, 2020/s/ Kaes Van’t Hof
Kaes Van’t Hof
Chief Financial Officer
(Principal Financial Officer)



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