UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
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| ☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2021March 31, 2022
OR
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| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934 |
Commission File Number 001-35700
Diamondback Energy, Inc.
(Exact Name of Registrant As Specified in Its Charter)
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| DE | | 45-4502447 |
| (State or Other Jurisdiction of Incorporation or Organization) | | (I.R.S. Employer Identification Number) |
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| 500 West Texas | | |
| Suite 1200 | | |
| Midland, | TX | | 79701 |
| (Address of principal executive offices) | | (Zip code) |
(432) 221-7400
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934:
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| Title of each class | Trading Symbol(s) | Name of each exchange on which registered |
| Common Stock | FANG | The Nasdaq Stock Market LLC |
| | (NASDAQ Global Select Market) |
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check One):
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| Large Accelerated Filer | | ☒ | | Accelerated Filer | | ☐ |
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| Non-Accelerated Filer | | ☐ | | Smaller Reporting Company | | ☐ |
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| | | | 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 OctoberApril 29, 2021,2022, the registrant had 181,174,549177,492,631 shares of common stock outstanding.
DIAMONDBACK ENERGY, INC.
FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2021MARCH 31, 2022
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”):
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| Basin | A large depression on the earth’s surface in which sediments accumulate. |
| Bbl or barrel | One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons. |
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| BO | One barrel of crude oil. |
| BOE | One barrel of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil. |
| BOE/d | BOE per day. |
| British Thermal Unit or Btu | The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. |
| Completion | The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency. |
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| Finding and development costs | Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves. |
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| Gross acres or gross wells | The total acres or wells, as the case may be, in which a working interest is owned. |
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| Horizontal wells | Wells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms. |
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| MBbl | One thousand barrels of crude oil and other liquid hydrocarbons. |
| MBO/d | One thousand BO per day. |
| MBOE/d | One thousand BOE per day. |
| Mcf | One thousand cubic feet of natural gas. |
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| Mineral interests | The interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources. |
| MMBtu | One million British Thermal Units. |
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| Net acres or net wells | The sum of the fractional working interest owned in gross acres. |
Net revenue interest | An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests. |
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| Oil and natural gas properties | Tracts of land consisting of properties to be developed for oil and natural gas resource extraction. |
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Plugging and abandonment | Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells. |
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| Prospect | A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons. |
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| Proved reserves | The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions. |
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| Reserves | The estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves are not assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations). |
| Reservoir | A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or crude oil that is confined by impermeable rock or water barriers and is separate from other reservoirs. |
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| Royalty interest | An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development, which may be subject to expiration. |
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| Working interest | An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations. |
| WTI | West Texas Intermediate. |
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GLOSSARY OF CERTAIN OTHER TERMS
The following is a glossary of certain other terms that are used in this report:
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2019 Indenture | The indenture, dated as of December 5, 2019, among the Company and Wells Fargo, as the trustee, as supplemented by the first supplemental indenture dated as of December 5, 2019, the second supplemental indenture dated as of May 26, 2020, the third supplemental indenture dated as of March 24, 2021, and the fourth supplemental indenture dated as of June 30, 2021, relating to the December 2019 Notes (defined above), the May 2020 Notes (defined below) and the March 2021 Notes (defined below). |
2025 Indenture | The indenture relating to the 2025 Senior Notes (defined below), dated as of December 20, 2016, among the Company, the subsidiary guarantor party thereto and Wells Fargo, as the trustee, as supplemented. |
2025 Senior Notes | The Company’s 5.375% senior unsecured notes due 2025 issued under the 2025 Indenture. |
| ASC | Accounting Standards Codification. |
| ASU | Accounting Standards Update. |
| December 2019 Notes | The Company’s 2.875% senior unsecured notes due 2024, the Company’s 3.250% senior unsecured notes due 2026 and the Company’s 3.500% senior unsecured notes due 2029 issued under the 2019 Indenture.IG Indenture and the related first supplemental indenture. |
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| Equity Plan | The Company’s Equity Incentive Plan. |
| Exchange Act | The Securities Exchange Act of 1934, as amended. |
| FASB | Financial Accounting Standards Board. |
| GAAP | Accounting principles generally accepted in the United States. |
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| IG Indenture | The indenture, dated as of December 5, 2019, among the Company, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented by the supplemental indentures relating to the outstanding December 2019 Notes (defined above), the March 2021 Notes (defined below) and the March 2022 Notes (defined below). |
| LIBOR | The London interbank offered rate. |
May 2020 Notes | The Company’s 4.750% Senior Notes due 2025 issued under the 2019 Indenture. |
| March 2021 Notes | The Company’s 0.900% Senior Notes due 2023, the Company’s 3.125% Senior Notes due 2031 and the Company’s 4.400% Senior Notes due 2051 issued under the 2019 Indenture.IG Indenture and the related third supplemental indenture. |
| March 2022 Notes | The Company’s 4.250% Senior Notes due 2052, issued under the IG Indenture and the related third supplemental indenture. |
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| NYMEX | New York Mercantile Exchange. |
| OPEC | Organization of the Petroleum Exporting Countries. |
| Rattler | Rattler Midstream LP, a Delaware limited partnership. |
Rattler’s General Partner | Rattler Midstream GP LLC, a Delaware limited liability company; the general partner of Rattler Midstream LP and a wholly owned subsidiary of the Company. |
| Rattler LLC | Rattler Midstream Operating LLC, a Delaware limited liability company and a subsidiary of Rattler. |
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| SEC | United States Securities and Exchange Commission. |
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| Senior Notes | The 2025 Senior Notes, theoutstanding December 2019 Notes, the May 2020March 2021 Notes and the March 20212022 Notes. |
| Viper | Viper Energy Partners LP, a Delaware limited partnership. |
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| Viper LLC | Viper Energy Partners LLC, a Delaware limited liability company and a subsidiary of Viper. |
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| Wells Fargo | Wells Fargo Bank, National Association. |
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
Various statements contained in this report are “forward-looking statements” as defined bywithin the SEC. These forward-looking statements are subject to a numbermeaning of Section 27A of the Securities Act and Section 21E of the Exchange Act, which involve risks, uncertainties, and assumptions, many of which are beyond our control.assumptions. All statements, other than statements of historical fact, including statements regarding our strategy,our: future performance; business strategy; future operations (including drilling plans and capital plans); estimates and projections of revenues, losses, costs, expenses, returns, cash flow, and financial position, estimated revenuesposition; reserve estimates and losses, projected costs, prospects,our ability to replace or increase reserves; anticipated benefits of strategic transactions (including acquisitions and divestitures); and plans and objectives of management (including plans for future cash flow from operations and for executing environmental strategies) are forward-looking statements. When used in this report, the words “could,“aim,” “anticipate,” “believe,” “anticipate,“continue,” “intend,“could,” “estimate,” “expect,” “forecast,” “future,” “guidance,” “intend,” “may,” “continue,“model,” “outlook,” “plan,” “positioned,” “potential,” “predict,” “potential,“project,” “project”“seek,” “should,” “target,” “will,” “would,” and similar expressions (including the negative of such terms) as they relate to the Company 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, 20202021 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 mayFactors that could cause our outcomes to differ materially include statements about:(but are not limited to) the following:
•the volatility of realizedChanges in supply and demand levels for oil, natural gas, and natural gas prices;liquids, and the resulting impact on the price for those commodities;
•the implications and logistical challengesimpact of public health crises, including epidemic or pandemic diseases includingsuch as the COVID-19 pandemic, and its impact on the oil and natural gas industry, pricing and demand for oil and natural gas and supply chain logistics;any related company or government policies or actions;
•logistical challengesactions taken by the members of OPEC and Russia affecting the supply chain disruptions;production and pricing of oil, as well as other domestic and global political, economic, or diplomatic developments;
•changes in general economic, business or industry conditions, including conditionschanges in foreign currency exchange rates, interest rates, and inflation rates;
•regional supply and demand factors, including delays, curtailment delays or interruptions of production, or governmental orders, rules or regulations that impose production limits;
•federal and state legislative and regulatory initiatives relating to hydraulic fracturing, including the U.S.effect of existing and future laws and governmental regulations;
•restrictions on the use of water, including limits on the use of produced water and a moratorium on new produced water well permits recently imposed by the Texas Railroad Commission in an effort to control induced seismicity in the Permian Basin;
•significant declines in prices for oil, and natural gas, industry and the effector natural gas liquids, which could require recognition of significant impairment charges;
•changes in U.S. energy, environmental, monetary and trade policies;
•conditions in the capital, financial and credit markets, including the availability and pricing of capital for drilling and development operations and our ability to obtain capital needed for developmentenvironmental and exploration operations on favorable terms or at all;social responsibility projects;
•conditionschallenges with employee retention and an increasingly competitive labor market due to a sustained labor shortage or increased turnover caused by the COVID-19 pandemic;
•changes in availability or cost of rigs, equipment, raw materials, supplies, oilfield services;
•changes in safety, health, environmental, tax, and other regulations or requirements (including those addressing air emissions, water management, or the U.S.impact of global climate change);
•security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, or from breaches of information technology systems of third parties with whom we transact business;
•lack of, or disruption in, access to adequate and reliable transportation, processing, storage, and other facilities for our oil, natural gas, and natural gas liquids;
•failures or delays in achieving expected reserve or production levels from existing and future oil and natural gas industrydevelopments, including due to operating hazards, drilling risks, or the inherent uncertainties in predicting reserve and the effect of U.S. energy, monetary and trade policies on our industry and business;
•our ability to execute our business and financial strategies;
•exploration and development drilling prospects, inventories, projects and programs;
•levels of production;
•the impact of reduced drilling activity on our exploration and development drilling prospects, inventories, projects and programs;
•regional supply and demand factors, any delays, curtailment delays or interruptions of production, and any governmental order, rule or regulation that may impose production limits;
•our ability to replace our oil and natural gas reserves;
•acquisitions and sales of assets and our anticipated synergies and cost savings from these transactions;
•competition in the oil and natural gas industry;
•uncertainties with respect to identified drilling locations and estimates of reserves;
•the impact of severe weather conditions on our production;
•our ability to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;
•our environmental initiatives and targets;
•future operating results;
•future dividends to our stockholders;
•impact of any impairment charges;
•lease operating expenses, general and administrative costs and finding and development costs;
•capital expenditure plans;
•use of proceeds from divestiture of assets;
•the conditions impacting the timing and amount of common stock repurchases under our common stock repurchase program;reservoir performance;
•other plans, objectives, expectationsdifficulty in obtaining necessary approvals and intentions;permits;
•severe weather conditions;
•acts of war or terrorist acts and the governmental or military response thereto;
•changes in the financial strength of counterparties to our credit agreement and hedging contracts;
•changes in our credit rating; and
•certain other risks and factors discussed elsewheredisclosed in this report.
In light of these factors, the events anticipated by our forward-looking statements may not occur at the time anticipated or at all. Moreover, we operate in a very competitive and rapidly changing environment and new risks emerge from time to time. We cannot 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 anticipated by any forward-looking statements we may make. Accordingly, you should not place undue reliance on any forward-looking statements made in this report. All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities laws. You should not place undue reliance on these forward-looking statements. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.applicable law.
PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
| | Diamondback Energy, Inc. and Subsidiaries | Diamondback Energy, Inc. and Subsidiaries | Diamondback Energy, Inc. and Subsidiaries |
| Condensed Consolidated Balance Sheets | Condensed Consolidated Balance Sheets | Condensed Consolidated Balance Sheets |
| (Unaudited) | (Unaudited) | (Unaudited) |
| | | September 30, | | December 31, | | March 31, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| | (In millions, except par values and share data) | | (In millions, except par values and share data) |
| Assets | Assets | Assets |
| Current assets: | Current assets: | | Current assets: | |
| Cash and cash equivalents | Cash and cash equivalents | $ | 457 | | | $ | 104 | | Cash and cash equivalents | $ | 149 | | | $ | 654 | |
| Restricted cash | Restricted cash | 18 | | | 4 | | Restricted cash | 18 | | | 18 | |
| Accounts receivable: | Accounts receivable: | | Accounts receivable: | |
| Joint interest and other, net | Joint interest and other, net | 99 | | | 56 | | Joint interest and other, net | 113 | | | 72 | |
| Oil and natural gas sales, net | Oil and natural gas sales, net | 712 | | | 281 | | Oil and natural gas sales, net | 966 | | | 598 | |
| | Inventories | Inventories | 53 | | | 33 | | Inventories | 62 | | | 62 | |
| | Derivative instruments | Derivative instruments | 14 | | | 1 | | Derivative instruments | 6 | | | 13 | |
| Income tax receivable | Income tax receivable | — | | | 100 | | Income tax receivable | — | | | 1 | |
| Assets held for sale | 83 | | | — | | |
| | Prepaid expenses and other current assets | Prepaid expenses and other current assets | 28 | | | 23 | | Prepaid expenses and other current assets | 33 | | | 28 | |
| Total current assets | Total current assets | 1,464 | | | 602 | | Total current assets | 1,347 | | | 1,446 | |
| Property and equipment: | Property and equipment: | | | | Property and equipment: | | | |
| Oil and natural gas properties, full cost method of accounting ($8,214 million and $7,493 million excluded from amortization at September 30, 2021 and December 31, 2020, respectively) | 32,554 | | | 27,377 | | |
| Oil and natural gas properties, full cost method of accounting ($8,512 million and $8,496 million excluded from amortization at March 31, 2022 and December 31, 2021, respectively) | | Oil and natural gas properties, full cost method of accounting ($8,512 million and $8,496 million excluded from amortization at March 31, 2022 and December 31, 2021, respectively) | 33,645 | | | 32,914 | |
| Midstream assets | Midstream assets | 922 | | | 1,013 | | Midstream assets | 1,118 | | | 1,076 | |
| Other property, equipment and land | Other property, equipment and land | 164 | | | 138 | | Other property, equipment and land | 185 | | | 174 | |
| Accumulated depletion, depreciation, amortization and impairment | Accumulated depletion, depreciation, amortization and impairment | (13,234) | | | (12,314) | | Accumulated depletion, depreciation, amortization and impairment | (13,840) | | | (13,545) | |
| Property and equipment, net | Property and equipment, net | 20,406 | | | 16,214 | | Property and equipment, net | 21,108 | | | 20,619 | |
| Funds held in escrow | Funds held in escrow | 66 | | | 51 | | Funds held in escrow | — | | | 12 | |
| Equity method investments | Equity method investments | 509 | | | 533 | | Equity method investments | 643 | | | 613 | |
| Derivative instruments | Derivative instruments | 4 | | | — | | Derivative instruments | 37 | | | 4 | |
| Deferred income taxes, net | Deferred income taxes, net | 25 | | | 73 | | Deferred income taxes, net | 37 | | | 40 | |
| Investment in real estate, net | Investment in real estate, net | 89 | | | 101 | | Investment in real estate, net | 88 | | | 88 | |
| Other assets | Other assets | 76 | | | 45 | | Other assets | 71 | | | 76 | |
| Total assets | Total assets | $ | 22,639 | | | $ | 17,619 | | Total assets | $ | 23,331 | | | $ | 22,898 | |
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See accompanying notes to condensed consolidated financial statements.
Diamondback Energy, Inc. and Subsidiaries
Condensed Consolidated Balance Sheets - (Continued)
(Unaudited)
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| September 30, | | December 31, | |
| 2021 | | 2020 | |
| Liabilities and Stockholders’ Equity | (In millions, except par values and share data) | |
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| Current liabilities: | | | | |
| Accounts payable - trade | $ | 21 | | | $ | 71 | | |
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| Accrued capital expenditures | 308 | | | 186 | | |
| Current maturities of long-term debt | 20 | | | 191 | | |
| Other accrued liabilities | 476 | | | 302 | | |
| Revenues and royalties payable | 561 | | | 237 | | |
| Derivative instruments | 610 | | | 249 | | |
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| Total current liabilities | 1,996 | | | 1,236 | | |
| Long-term debt | 6,925 | | | 5,624 | | |
| Derivative instruments | 36 | | | 57 | | |
| Asset retirement obligations | 178 | | | 108 | | |
| Deferred income taxes | 1,068 | | | 783 | | |
| Other long-term liabilities | 14 | | | 7 | | |
| Total liabilities | 10,217 | | | 7,815 | | |
| Commitments and contingencies (Note 13) | 0 | | 0 | |
| Stockholders’ equity: | | | | |
| Common stock, $0.01 par value; 400,000,000 shares authorized; 180,791,028 and 158,088,182 shares issued and outstanding at September 30, 2021 and December 31, 2020, respectively | 2 | | | 2 | | |
| Additional paid-in capital | 14,389 | | | 12,656 | | |
| Retained earnings (accumulated deficit) | (2,908) | | | (3,864) | | |
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| Total Diamondback Energy, Inc. stockholders’ equity | 11,483 | | | 8,794 | | |
| Non-controlling interest | 939 | | | 1,010 | | |
| Total equity | 12,422 | | | 9,804 | | |
| Total liabilities and equity | $ | 22,639 | | | $ | 17,619 | | |
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| March 31, | | December 31, | |
| 2022 | | 2021 | |
| Liabilities and Stockholders’ Equity | (In millions, except par values and share data) | |
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| Current liabilities: | | | | |
| Accounts payable - trade | $ | 49 | | | $ | 36 | | |
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| Accrued capital expenditures | 301 | | | 295 | | |
| Current maturities of long-term debt | 45 | | | 45 | | |
| Other accrued liabilities | 411 | | | 419 | | |
| Revenues and royalties payable | 578 | | | 452 | | |
| Derivative instruments | 339 | | | 174 | | |
| Deferred income taxes | 149 | | | 17 | | |
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| Total current liabilities | 1,872 | | | 1,438 | | |
| Long-term debt | 5,803 | | | 6,642 | | |
| Derivative instruments | 94 | | | 29 | | |
| Asset retirement obligations | 254 | | | 166 | | |
| Deferred income taxes | 1,421 | | | 1,338 | | |
| Other long-term liabilities | 35 | | | 40 | | |
| Total liabilities | 9,479 | | | 9,653 | | |
| Commitments and contingencies (Note 14) | 0 | | 0 | |
| Stockholders’ equity: | | | | |
| Common stock, $0.01 par value; 400,000,000 shares authorized; 177,550,589 and 177,551,347 shares issued and outstanding at March 31, 2022 and December 31, 2021, respectively | 2 | | | 2 | | |
| Additional paid-in capital | 14,067 | | | 14,084 | | |
| Retained earnings (accumulated deficit) | (1,326) | | | (1,998) | | |
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| Total Diamondback Energy, Inc. stockholders’ equity | 12,743 | | | 12,088 | | |
| Non-controlling interest | 1,109 | | | 1,157 | | |
| Total equity | 13,852 | | | 13,245 | | |
| Total liabilities and equity | $ | 23,331 | | | $ | 22,898 | | |
See accompanying notes to condensed consolidated financial statements.
Diamondback Energy, Inc. and Subsidiaries
Condensed Consolidated Statements of Operations
(Unaudited)
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended March 31, | |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | |
| | (In millions, except per share amounts, shares in thousands) | | (In millions, except per share amounts, shares in thousands) |
| Revenues: | Revenues: | | Revenues: | | |
| Oil sales | Oil sales | $ | 1,506 | | | $ | 606 | | | $ | 3,845 | | | $ | 1,785 | | Oil sales | $ | 1,946 | | | $ | 944 | | |
| Natural gas sales | Natural gas sales | 152 | | | 36 | | | 363 | | | 61 | | Natural gas sales | 154 | | | 104 | | |
| Natural gas liquid sales | Natural gas liquid sales | 239 | | | 65 | | | 528 | | | 156 | | Natural gas liquid sales | 289 | | | 124 | | |
| | Midstream services | Midstream services | 12 | | | 12 | | | 35 | | | 37 | | Midstream services | 17 | | | 11 | | |
| Other operating income | Other operating income | 1 | | | 1 | | | 4 | | | 5 | | Other operating income | 2 | | | 1 | | |
| Total revenues | Total revenues | 1,910 | | | 720 | | | 4,775 | | | 2,044 | | Total revenues | 2,408 | | | 1,184 | | |
| Costs and expenses: | Costs and expenses: | | | | | | | | Costs and expenses: | | | | |
| Lease operating expenses | Lease operating expenses | 156 | | | 102 | | | 415 | | | 332 | | Lease operating expenses | 149 | | | 102 | | |
| Production and ad valorem taxes | Production and ad valorem taxes | 124 | | | 55 | | | 304 | | | 148 | | Production and ad valorem taxes | 161 | | | 75 | | |
| Gathering and transportation | Gathering and transportation | 67 | | | 33 | | | 154 | | | 105 | | Gathering and transportation | 59 | | | 31 | | |
| Midstream services expense | Midstream services expense | 19 | | | 26 | | | 70 | | | 81 | | Midstream services expense | 22 | | | 28 | | |
| Depreciation, depletion, amortization and accretion | Depreciation, depletion, amortization and accretion | 341 | | | 288 | | | 955 | | | 1,041 | | Depreciation, depletion, amortization and accretion | 313 | | | 273 | | |
| Impairment of oil and natural gas properties | — | | | 1,451 | | | — | | | 4,999 | | |
| | | General and administrative expenses | General and administrative expenses | 38 | | | 20 | | | 99 | | | 64 | | General and administrative expenses | 36 | | | 25 | | |
| | Merger and integration expense | Merger and integration expense | — | | | — | | | 77 | | | — | | Merger and integration expense | — | | | 75 | | |
| Other operating expense | Other operating expense | 1 | | | 1 | | | 11 | | | 4 | | Other operating expense | 8 | | | 4 | | |
| Total costs and expenses | Total costs and expenses | 746 | | | 1,976 | | | 2,085 | | | 6,774 | | Total costs and expenses | 748 | | | 613 | | |
| Income (loss) from operations | Income (loss) from operations | 1,164 | | | (1,256) | | | 2,690 | | | (4,730) | | Income (loss) from operations | 1,660 | | | 571 | | |
| Other income (expense): | Other income (expense): | | Other income (expense): | | |
| | Interest expense, net | Interest expense, net | (57) | | | (53) | | | (170) | | | (147) | | Interest expense, net | (40) | | | (56) | | |
| Other income (expense), net | Other income (expense), net | 2 | | | (2) | | | (4) | | | (8) | | Other income (expense), net | 1 | | | 1 | | |
| | Gain (loss) on derivative instruments, net | Gain (loss) on derivative instruments, net | (234) | | | (99) | | | (895) | | | 82 | | Gain (loss) on derivative instruments, net | (552) | | | (164) | | |
| | Gain (loss) on sale of equity method investments | — | | | — | | | 23 | | | — | | |
| | | Gain (loss) on extinguishment of debt | Gain (loss) on extinguishment of debt | (12) | | | (2) | | | (73) | | | (5) | | Gain (loss) on extinguishment of debt | (54) | | | (61) | | |
| Income (loss) from equity investments | Income (loss) from equity investments | 4 | | | 3 | | | 6 | | | (10) | | Income (loss) from equity investments | 9 | | | (3) | | |
| Total other income (expense), net | Total other income (expense), net | (297) | | | (153) | | | (1,113) | | | (88) | | Total other income (expense), net | (636) | | | (283) | | |
| Income (loss) before income taxes | Income (loss) before income taxes | 867 | | | (1,409) | | | 1,577 | | | (4,818) | | Income (loss) before income taxes | 1,024 | | | 288 | | |
| Provision for (benefit from) income taxes | Provision for (benefit from) income taxes | 193 | | | (304) | | | 352 | | | (902) | | Provision for (benefit from) income taxes | 221 | | | 65 | | |
| Net income (loss) | Net income (loss) | 674 | | | (1,105) | | | 1,225 | | | (3,916) | | Net income (loss) | 803 | | | 223 | | |
| Net income (loss) attributable to non-controlling interest | Net income (loss) attributable to non-controlling interest | 25 | | | 8 | | | 45 | | | (138) | | Net income (loss) attributable to non-controlling interest | 24 | | | 3 | | |
| Net income (loss) attributable to Diamondback Energy, Inc. | Net income (loss) attributable to Diamondback Energy, Inc. | $ | 649 | | | $ | (1,113) | | | $ | 1,180 | | | $ | (3,778) | | Net income (loss) attributable to Diamondback Energy, Inc. | $ | 779 | | | $ | 220 | | |
| Earnings (loss) per common share: | Earnings (loss) per common share: | | | | | | | | Earnings (loss) per common share: | | | | |
| Basic | Basic | $ | 3.59 | | | $ | (7.05) | | | $ | 6.73 | | | $ | (23.91) | | Basic | $ | 4.39 | | | $ | 1.34 | | |
| Diluted | Diluted | $ | 3.56 | | | $ | (7.05) | | | $ | 6.68 | | | $ | (23.91) | | Diluted | $ | 4.36 | | | $ | 1.33 | | |
| Weighted average common shares outstanding: | Weighted average common shares outstanding: | | Weighted average common shares outstanding: | | |
| Basic | Basic | 181,027 | | | 157,833 | | | 175,464 | | | 157,984 | | Basic | 177,565 | | | 164,169 | | |
| Diluted | Diluted | 182,149 | | | 157,833 | | | 176,553 | | | 157,984 | | Diluted | 178,555 | | | 164,926 | | |
| Dividends declared per share | Dividends declared per share | $ | 0.50 | | | $ | 0.375 | | | $ | 1.35 | | | $ | 1.125 | | Dividends declared per share | $ | 3.05 | | | $ | 0.40 | | |
See accompanying notes to condensed consolidated financial statements.
Diamondback Energy, Inc. and Subsidiaries
Condensed Consolidated Statements of Stockholders’ Equity
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Common Stock | | Additional Paid-in Capital | | Retained Earnings (Accumulated Deficit) | | | Non-Controlling Interest | | Total |
| Shares | | Amount | | | | |
| ($ in millions, shares in thousands) |
| Balance December 31, 2020 | 158,088 | | | $ | 2 | | | $ | 12,656 | | | $ | (3,864) | | | | $ | 1,010 | | | $ | 9,804 | |
| Unit-based compensation | — | | | — | | | — | | | — | | | | 3 | | | 3 | |
| Distribution equivalent rights payments | — | | | — | | | — | | | (1) | | | | — | | | (1) | |
| Common units issued for acquisitions | 22,795 | | | — | | | 1,727 | | | — | | | | — | | | 1,727 | |
| Stock-based compensation | — | | | — | | | 11 | | | — | | | | — | | | 11 | |
| Cash paid for tax withholding on vested equity awards | — | | | — | | | (6) | | | — | | | | — | | | (6) | |
| Repurchased units under buyback programs | — | | | — | | | — | | | — | | | | (24) | | | (24) | |
| Distributions to non-controlling interest | — | | | — | | | — | | | — | | | | (17) | | | (17) | |
| Dividend paid | — | | | — | | | — | | | (68) | | | | — | | | (68) | |
| Exercise of stock options and issuance of restricted stock units and awards | 101 | | | — | | | — | | | — | | | | — | | | — | |
| Change in ownership of consolidated subsidiaries, net | — | | | — | | | (4) | | | — | | | | 4 | | | — | |
| Net income (loss) | — | | | — | | | — | | | 220 | | | | 3 | | | 223 | |
| Balance March 31, 2021 | 180,984 | | | 2 | | | 14,384 | | | (3,713) | | | | 979 | | | 11,652 | |
| Unit-based compensation | — | | | — | | | — | | | — | | | | 3 | | | 3 | |
| Distribution equivalent rights payments | — | | | — | | | — | | | (1) | | | | (1) | | | (2) | |
| Stock-based compensation | — | | | — | | | 15 | | | — | | | | — | | | 15 | |
| Cash paid for tax withholding on vested equity awards | — | | | — | | | — | | | — | | | | (2) | | | (2) | |
| Repurchased units under buyback programs | — | | | — | | | — | | | — | | | | (12) | | | (12) | |
| Distributions to non-controlling interest | — | | | — | | | — | | | — | | | | (24) | | | (24) | |
| Dividend paid | — | | | — | | | — | | | (72) | | | | — | | | (72) | |
| Exercise of stock options and vesting of restricted stock units and awards | 65 | | | — | | | 3 | | | — | | | | — | | | 3 | |
| Change in ownership of consolidated subsidiaries, net | — | | | — | | | (3) | | | — | | | | 4 | | | 1 | |
| Net income (loss) | — | | | — | | | — | | | 311 | | | | 17 | | | 328 | |
| Balance June 30, 2021 | 181,049 | | | 2 | | | 14,399 | | | (3,475) | | | | 964 | | | 11,890 | |
| Unit-based compensation | — | | | — | | | — | | | — | | | | 3 | | | 3 | |
| Distribution equivalent rights payments | — | | | — | | | — | | | — | | | | (1) | | | (1) | |
| Stock-based compensation | — | | | — | | | 17 | | | — | | | | — | | | 17 | |
| | | | | | | | | | | | |
| Repurchased shares under buyback program | (268) | | | — | | | (22) | | | — | | | | — | | | (22) | |
| Repurchased units under buyback programs | — | | | — | | | — | | | — | | | | (27) | | | (27) | |
| Distributions to non-controlling interest | — | | | — | | | — | | | — | | | | (31) | | | (31) | |
| Dividend paid | — | | | — | | | — | | | (82) | | | | — | | | (82) | |
| Exercise of stock options and vesting of restricted stock units and awards | 10 | | | — | | | 1 | | | — | | | | — | | | 1 | |
| Change in ownership of consolidated subsidiaries, net | — | | | — | | | (6) | | | — | | | | 6 | | | — | |
| Net income (loss) | — | | | — | | | — | | | 649 | | | | 25 | | | 674 | |
| Balance September 30, 2021 | 180,791 | | | $ | 2 | | | $ | 14,389 | | | $ | (2,908) | | | | $ | 939 | | | $ | 12,422 | |
See accompanying notes to condensed consolidated financial statements.
Diamondback Energy, Inc. and Subsidiaries
Condensed Consolidated Statements of Stockholders’ Equity - (Continued)
(Unaudited)
| | | Common Stock | | Additional Paid-in Capital | | Retained Earnings (Accumulated Deficit) | | | Non-Controlling Interest | | Total | | Common Stock | | Additional Paid-in Capital | | Retained Earnings (Accumulated Deficit) | | | Non-Controlling Interest | | Total |
| | Shares | | Amount | | Total | Shares | | Amount | | Additional Paid-in Capital | Retained Earnings (Accumulated Deficit) | | Non-Controlling Interest |
| | ($ in millions, shares in thousands) | | ($ in millions, shares in thousands) |
| Balance December 31, 2019 | 159,002 | | | $ | 2 | | | $ | 12,357 | | | $ | 890 | | | | $ | 1,657 | | | $ | 14,906 | | |
| | Balance December 31, 2021 | | Balance December 31, 2021 | 177,551 | | | $ | 2 | | | $ | 14,084 | | | $ | (1,998) | | | | $ | 1,157 | | | $ | 13,245 | |
| Unit-based compensation | Unit-based compensation | — | | | — | | | — | | | — | | | | 5 | | | 5 | | Unit-based compensation | — | | | — | | | — | | | — | | | | 3 | | | 3 | |
| Distribution equivalent rights payments | Distribution equivalent rights payments | — | | | — | | | — | | | — | | | | (1) | | | (1) | | Distribution equivalent rights payments | — | | | — | | | — | | | — | | | | (1) | | | (1) | |
| | Stock-based compensation | Stock-based compensation | — | | | — | | | 10 | | | — | | | | — | | | 10 | | Stock-based compensation | — | | | — | | | 16 | | | — | | | | — | | | 16 | |
| Cash paid for tax withholding on vested equity awards | | Cash paid for tax withholding on vested equity awards | — | | | — | | | (15) | | | — | | | | — | | | (15) | |
| Repurchased shares under buyback program | | Repurchased shares under buyback program | (58) | | | — | | | (7) | | | — | | | | — | | | (7) | |
| Repurchased units under buyback programs | | Repurchased units under buyback programs | — | | | — | | | — | | | — | | | | (42) | | | (42) | |
| Distributions to non-controlling interest | | Distributions to non-controlling interest | — | | | — | | | — | | | — | | | | (47) | | | (47) | |
| Dividend paid | | Dividend paid | — | | | — | | | — | | | (107) | | | | — | | | (107) | |
| Exercise of stock options and issuance of restricted stock units and awards | | Exercise of stock options and issuance of restricted stock units and awards | 58 | | | — | | | 1 | | | — | | | | — | | | 1 | |
| Change in ownership of consolidated subsidiaries, net | | Change in ownership of consolidated subsidiaries, net | — | | | — | | | (12) | | | — | | | | 15 | | | 3 | |
| Net income (loss) | | Net income (loss) | — | | | — | | | — | | | 779 | | | | 24 | | | 803 | |
| Balance March 31, 2022 | | Balance March 31, 2022 | 177,551 | | | $ | 2 | | | $ | 14,067 | | | $ | (1,326) | | | | $ | 1,109 | | | $ | 13,852 | |
| | Cash paid for tax withholding on vested equity awards | — | | | — | | | (5) | | | — | | | | — | | | (5) | | |
| Repurchased shares for share buyback program | (1,280) | | | — | | | (98) | | | — | | | | — | | | (98) | | |
| Distribution to non-controlling interest | — | | | — | | | — | | | — | | | | (43) | | | (43) | | |
| | Dividend paid | — | | | — | | | — | | | (59) | | | | — | | | (59) | | |
| Exercise of stock options and vesting of restricted stock units | 93 | | | — | | | 1 | | | — | | | | — | | | 1 | | |
| | Net income (loss) | — | | | — | | | — | | | (272) | | | | (128) | | | (400) | | |
| Balance March 31, 2020 | 157,815 | | | 2 | | | 12,265 | | | 559 | | | | 1,490 | | | 14,316 | | |
| Distribution equivalent rights payments | — | | | — | | | — | | | — | | | | (1) | | | (1) | | |
| | Stock-based compensation | — | | | — | | | 11 | | | — | | | | — | | | 11 | | |
| | Repurchased shares for share buyback program | — | | | — | | | — | | | — | | | | (2) | | | (2) | | |
| Distribution to non-controlling interest | — | | | — | | | — | | | — | | | | (19) | | | (19) | | |
| Dividend paid | — | | | — | | | — | | | (59) | | | | — | | | (59) | | |
| Exercise of stock options and vesting of restricted stock units | 9 | | | — | | | — | | | — | | | | — | | | — | | |
| Change in ownership of consolidated subsidiaries, net | — | | | — | | | 329 | | | — | | | | (329) | | | — | | |
| Net income (loss) | — | | | — | | | — | | | (2,393) | | | | (18) | | | (2,411) | | |
| Balance June 30, 2020 | 157,824 | | | 2 | | | 12,605 | | | (1,893) | | | | 1,121 | | | 11,835 | | |
| | Unit-based compensation | — | | | — | | | — | | | — | | | | 3 | | | 3 | | |
| Stock-based compensation | — | | | — | | | 10 | | | — | | | | — | | | 10 | | |
| Cash paid for tax withholding on vested equity awards | — | | | — | | | — | | | — | | | | — | | | — | | |
| | Distribution to non-controlling interest | — | | | — | | | — | | | — | | | | (15) | | | (15) | | |
| Dividend paid | — | | | — | | | — | | | (59) | | | | — | | | (59) | | |
| Exercise of stock options and vesting of restricted stock units | 26 | | | — | | | — | | | — | | | | — | | | — | | |
| Net income (loss) | — | | | — | | | — | | | (1,113) | | | | 8 | | | (1,105) | | |
| Balance September 30, 2020 | 157,850 | | | $ | 2 | | | $ | 12,615 | | | $ | (3,065) | | | | $ | 1,117 | | | $ | 10,669 | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Common Stock | | Additional Paid-in Capital | | Retained Earnings (Accumulated Deficit) | | | Non-Controlling Interest | | Total |
| Shares | | Amount | | | | |
| ($ in millions, shares in thousands) |
| Balance December 31, 2020 | 158,088 | | | $ | 2 | | | $ | 12,656 | | | $ | (3,864) | | | | $ | 1,010 | | | $ | 9,804 | |
| Unit-based compensation | — | | | — | | | — | | | — | | | | 3 | | | 3 | |
| Distribution equivalent rights payments | — | | | — | | | — | | | (1) | | | | — | | | (1) | |
| Common units issued for acquisitions | 22,795 | | | — | | | 1,727 | | | — | | | | — | | | 1,727 | |
| Stock-based compensation | — | | | — | | | 11 | | | — | | | | — | | | 11 | |
| Cash paid for tax withholding on vested equity awards | — | | | — | | | (6) | | | — | | | | — | | | (6) | |
| Repurchased units under buyback programs | — | | | — | | | — | | | — | | | | (24) | | | (24) | |
| Distributions to non-controlling interest | — | | | — | | | — | | | — | | | | (17) | | | (17) | |
| Dividend paid | — | | | — | | | — | | | (68) | | | | — | | | (68) | |
| Exercise of stock options and issuance of restricted stock units and awards | 101 | | | — | | | — | | | — | | | | — | | | — | |
| Change in ownership of consolidated subsidiaries, net | — | | | — | | | (4) | | | — | | | | 4 | | | — | |
| Net income (loss) | — | | | — | | | — | | | 220 | | | | 3 | | | 223 | |
| Balance March 31, 2021 | 180,984 | | | $ | 2 | | | $ | 14,384 | | | $ | (3,713) | | | | $ | 979 | | | $ | 11,652 | |
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See accompanying notes to condensed consolidated financial statements.
Diamondback Energy, Inc. and Subsidiaries
Condensed Consolidated Statements of Cash Flows
(Unaudited)
| | | Nine Months Ended September 30, | | Three Months Ended March 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| | (In millions) | | (In millions) |
| Cash flows from operating activities: | Cash flows from operating activities: | | Cash flows from operating activities: | |
| Net income (loss) | Net income (loss) | $ | 1,225 | | | $ | (3,916) | | Net income (loss) | $ | 803 | | | $ | 223 | |
| Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | | Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | |
| Provision for (benefit from) deferred income taxes | Provision for (benefit from) deferred income taxes | 348 | | | (840) | | Provision for (benefit from) deferred income taxes | 89 | | | 64 | |
| | Impairment of oil and natural gas properties | — | | | 4,999 | | |
| | | Depreciation, depletion, amortization and accretion | Depreciation, depletion, amortization and accretion | 955 | | | 1,041 | | Depreciation, depletion, amortization and accretion | 313 | | | 273 | |
| | (Gain) loss on extinguishment of debt | (Gain) loss on extinguishment of debt | 73 | | | 5 | | (Gain) loss on extinguishment of debt | 54 | | | 61 | |
| | (Gain) loss on derivative instruments, net | (Gain) loss on derivative instruments, net | 895 | | | (82) | | (Gain) loss on derivative instruments, net | 552 | | | 164 | |
| Cash received (paid) on settlement of derivative instruments | Cash received (paid) on settlement of derivative instruments | (847) | | | 288 | | Cash received (paid) on settlement of derivative instruments | (420) | | | (178) | |
| | Equity-based compensation expense | Equity-based compensation expense | 37 | | | 27 | | Equity-based compensation expense | 15 | | | 10 | |
| | (Gain) loss on sale of equity method investments | (23) | | | — | | |
| | | Other | Other | 39 | | | 31 | | Other | 5 | | | 10 | |
| Changes in operating assets and liabilities: | Changes in operating assets and liabilities: | | Changes in operating assets and liabilities: | |
| Accounts receivable | Accounts receivable | (307) | | | 265 | | Accounts receivable | (403) | | | (137) | |
| | Income tax receivable | Income tax receivable | 152 | | | (62) | | Income tax receivable | 1 | | | 100 | |
| | Prepaid expenses and other | Prepaid expenses and other | 23 | | | (1) | | Prepaid expenses and other | 2 | | | 22 | |
| Accounts payable and accrued liabilities | Accounts payable and accrued liabilities | (39) | | | (18) | | Accounts payable and accrued liabilities | (13) | | | (26) | |
| | Income tax payable | | Income tax payable | 132 | | | — | |
| Revenues and royalties payable | Revenues and royalties payable | 257 | | | (59) | | Revenues and royalties payable | 125 | | | 50 | |
| | Other | Other | (11) | | | 37 | | Other | (3) | | | (12) | |
| Net cash provided by (used in) operating activities | Net cash provided by (used in) operating activities | 2,777 | | | 1,715 | | Net cash provided by (used in) operating activities | 1,252 | | | 624 | |
| Cash flows from investing activities: | Cash flows from investing activities: | | | | Cash flows from investing activities: | | | |
| Drilling, completions and infrastructure additions to oil and natural gas properties | Drilling, completions and infrastructure additions to oil and natural gas properties | (1,030) | | | (1,500) | | Drilling, completions and infrastructure additions to oil and natural gas properties | (418) | | | (289) | |
| | Additions to midstream assets | Additions to midstream assets | (23) | | | (133) | | Additions to midstream assets | (19) | | | (7) | |
| | Property acquisitions | Property acquisitions | (438) | | | (154) | | Property acquisitions | (296) | | | (346) | |
| | Proceeds from sale of assets | Proceeds from sale of assets | 112 | | | 2 | | Proceeds from sale of assets | 35 | | | — | |
| | Contributions to equity method investments | Contributions to equity method investments | (7) | | | (90) | | Contributions to equity method investments | (29) | | | (4) | |
| Distributions from equity method investments | Distributions from equity method investments | 9 | | | 27 | | Distributions from equity method investments | — | | | 9 | |
| | Other | Other | 54 | | | (7) | | Other | 11 | | | 50 | |
| Net cash provided by (used in) investing activities | Net cash provided by (used in) investing activities | (1,323) | | | (1,855) | | Net cash provided by (used in) investing activities | (716) | | | (587) | |
| Cash flows from financing activities: | Cash flows from financing activities: | | | | Cash flows from financing activities: | | | |
| Proceeds from borrowings under credit facilities | Proceeds from borrowings under credit facilities | 759 | | | 917 | | Proceeds from borrowings under credit facilities | 79 | | | 432 | |
| Repayments under credit facilities | Repayments under credit facilities | (853) | | | (1,238) | | Repayments under credit facilities | (100) | | | (455) | |
| Proceeds from senior notes | Proceeds from senior notes | 2,200 | | | 997 | | Proceeds from senior notes | 750 | | | 2,200 | |
| Repayment of senior notes | Repayment of senior notes | (2,540) | | | (239) | | Repayment of senior notes | (1,500) | | | (1,916) | |
| Proceeds from (repayments to) joint venture | | Proceeds from (repayments to) joint venture | 5 | | | (4) | |
| Premium on extinguishment of debt | Premium on extinguishment of debt | (178) | | | (2) | | Premium on extinguishment of debt | (47) | | | (166) | |
| | Proceeds from (repayments to) joint venture | (14) | | | 47 | | |
| | Repurchased shares under buyback program | Repurchased shares under buyback program | (22) | | | (98) | | Repurchased shares under buyback program | (7) | | | — | |
| Repurchased units under buyback program | Repurchased units under buyback program | (63) | | | — | | Repurchased units under buyback program | (42) | | | (24) | |
| | Dividends to stockholders | Dividends to stockholders | (221) | | | (177) | | Dividends to stockholders | (107) | | | (68) | |
| | Distributions to non-controlling interest | Distributions to non-controlling interest | (72) | | | (77) | | Distributions to non-controlling interest | (47) | | | (17) | |
| | Financing portion of net cash received (paid) for derivative instruments | Financing portion of net cash received (paid) for derivative instruments | 25 | | | — | | Financing portion of net cash received (paid) for derivative instruments | — | | | 76 | |
| Other | Other | (42) | | | (19) | | Other | (25) | | | (29) | |
| Net cash provided by (used in) financing activities | Net cash provided by (used in) financing activities | (1,021) | | | 111 | | Net cash provided by (used in) financing activities | (1,041) | | | 29 | |
| Net increase (decrease) in cash and cash equivalents | Net increase (decrease) in cash and cash equivalents | 433 | | | (29) | | Net increase (decrease) in cash and cash equivalents | (505) | | | 66 | |
| Cash, cash equivalents and restricted cash at beginning of period | Cash, cash equivalents and restricted cash at beginning of period | 108 | | | 128 | | Cash, cash equivalents and restricted cash at beginning of period | 672 | | | 108 | |
Cash, cash equivalents and restricted cash at end of period(1) | Cash, cash equivalents and restricted cash at end of period(1) | $ | 541 | | | $ | 99 | | Cash, cash equivalents and restricted cash at end of period(1) | $ | 167 | | | $ | 174 | |
| | Supplemental disclosure of non-cash transactions: | | | | |
| Accrued capital expenditures included in accounts payable and accrued expenses | $ | 269 | | | $ | 352 | | |
| | Common stock issued for business combinations | $ | 1,727 | | | $ | — | | |
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See accompanying notes to condensed consolidated financial statements.
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements
(Unaudited)
1. DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION
Organization and Description of the Business
Diamondback Energy, Inc., together with its subsidiaries (collectively referred to as “Diamondback” or the “Company” unless the context otherwise requires), is an independent oil and natural gas company currently focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas.
As of September 30, 2021,March 31, 2022, the wholly owned subsidiaries of Diamondback include Diamondback E&P LLC (Diamondback(“Diamondback E&P)&P”), 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 QEP Resources, Inc. (“QEP”), a Delaware corporation. Diamondback O&G LLC (“O&G”), Energen Corporation (“Energen”), Energen Resources Corporation and EGN Services, Inc., former wholly owned subsidiaries of Diamondback, were merged with and into Diamondback E&P LLC effective June 30, 2021 as part of the internal restructuring of the Company’s subsidiaries (the “E&P Merger”).
Basis of Presentation
The condensed consolidated financial statements include the accounts of the Company and its subsidiaries after all significant intercompany balances and transactions have been eliminated upon consolidation.
Diamondback’s publicly traded subsidiaries Viper Energy Partners LP (“Viper”) and Rattler Midstream LP (“Rattler”) are consolidated in the Company’s financial statements. As of September 30, 2021,March 31, 2022, the Company owned approximately 59%55% of Viper’s total units outstanding. The Company’s wholly owned subsidiary, Viper Energy Partners GP LLC, is the general partner of Viper. As of September 30, 2021,March 31, 2022, the Company owned approximately 73%74% of Rattler’s total units outstanding. The Company’s wholly owned subsidiary, Rattler Midstream GP LLC, is the general partner of Rattler. The results of operations attributable to the non-controlling interest in Viper and Rattler are presented within equity and net income and are shown separately from the Company’s equity and net income attributable to the Company.
These condensed consolidated financial statements have been prepared by the Company without audit, pursuant to the rules and regulations of the SEC. They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been omitted pursuant to SEC rules and regulations, although the Company believes the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10–Q should be read in conjunction with the Company’s most recent Annual Report on Form 10–K for the fiscal year ended December 31, 2020,2021, which contains a summary of the Company’s significant accounting policies and other disclosures.
Reclassifications
Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had an immaterial effect on the previously reported total assets, total liabilities, stockholders’ equity, results of operations or cash flows.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
Certain amounts included in or affecting the Company’s consolidated financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts the Company reports for assets and liabilities and the Company’s disclosure of contingent assets and liabilities as of the date of the consolidated financial statements. Actual results could differ from those estimates.
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
Making accurate estimates and assumptions is particularly difficult in the oil and natural gas industry, given the challenges resulting from volatility in oil and natural gas prices. For instance, in 2020,prices and the effects of COVID-19 and actions by OPEC members and other exporting nations on the supply and demand in global oil and natural gas markets resulted in significant negative pricing pressures in the first half of 2020, followed by a recovery in pricing and an increase in demand in the second half of 2020 and into 2021. However, the COVID-19 Delta variant emerged in March 2021 and became highly transmissible in July 2021, which contributed to additional pricing volatility during the third quarter of 2021. The financial results of companies in the oil and natural gas industry have been impacted materially as a result of changing market conditions.pandemic. Such circumstances generally increase the uncertainty in the Company’s accounting estimates, particularly those involving financial forecasts.
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
The Company evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Company considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, asset retirement obligations, the fair value determination of acquired assets and liabilities assumed, equity-based compensation, fair value estimates of derivative instruments and estimates of income taxes.
Cash, Cash Equivalents and Restricted Cash
The following table provides a reconciliation of cash, cash equivalents and restricted cash as reported at the end of the period in the condensed consolidated statements of cash flows for the ninethree months ended September 30,March 31, 2022 and 2021 and 2020 to the line items within the condensed consolidated balance sheets:
| | | | | | | | | | | |
| Nine Months Ended September 30, |
| 2021 | | 2020 |
| (In millions) |
| Cash and cash equivalents | $ | 457 | | | $ | 92 | |
| Restricted cash | 18 | | | 7 | |
Restricted cash included in funds held in escrow(1) | 66 | | | — | |
| Total cash, cash equivalents and restricted cash | $ | 541 | | | $ | 99 | |
(1) As of September 30, 2021, the restricted cash included in funds held in escrow on the condensed consolidated balance sheet is related to cash deposited into escrow accounts for a title dispute between outside parties in the Williston Basin and an escrow deposit related to Viper’s Swallowtail Acquisition, as defined in Note 14—Subsequent Events. | | | | | | | | | | | |
| Three Months Ended March 31, |
| 2022 | | 2021 |
| (In millions) |
| Cash and cash equivalents | $ | 149 | | | $ | 121 | |
| Restricted cash | 18 | | | 19 | |
| Restricted cash included in funds held in escrow | — | | | 34 | |
| Total cash, cash equivalents and restricted cash | $ | 167 | | | $ | 174 | |
Recent Accounting Pronouncements
Recently Adopted Pronouncements
In December 2019, the FASB issued ASU 2019-12, "Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes." This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance and is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The CompanyThere are no recently adopted this update effective January 1, 2021. The adoption of this update did not have a material impact on its financial position, results of operations or liquidity.pronouncements.
Accounting Pronouncements Not Yet Adopted
In October 2021, the FASB issued ASU 2021-08, "Business Combinations (Topic 805) – Accounting for Contract Assets and Contract Liabilities from Contracts with Customers.” This update requires the acquirer in a business combination to record contract asset and liabilities following Topic 606 – “Revenue from Contracts with Customers” at acquisition as if it had originated the contract, rather than at fair value. This update is effective for public business entities beginning after December 15, 2022 with early adoption permitted. The Company continues to evaluate the provisions of this update, but does not believe the adoption will have a material impact on its financial position, results of operations or liquidity.
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
The Company considers the applicability and impact of all ASUs. ASUs not discussed above were assessed and determined to be either not applicable, the effects of adoption are not expected to be material or are clarifications of ASUs previously disclosed.
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
3. REVENUE FROM CONTRACTS WITH CUSTOMERS
Revenue from Contracts with Customers
Sales of oil, natural gas and natural gas liquids are recognized at the point control of the product is transferred to the customer. Virtually all of the pricing provisions in the Company’s contracts are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, the quality of the oil or natural gas and the prevailing supply and demand conditions. As a result, the price of the oil, natural gas and natural gas liquids fluctuates to remain competitive with other available oil, natural gas and natural gas liquids supplies. The following tables present the Company’s revenue from contracts with customers disaggregated by product type and basin:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2021 | | Three Months Ended September 30, 2020 |
| Midland Basin | Delaware Basin | Other | Total | | Midland Basin | Delaware Basin | Other | Total |
| (In millions) |
| Oil sales | $ | 983 | | $ | 419 | | $ | 104 | | $ | 1,506 | | | $ | 348 | | $ | 257 | | $ | 1 | | $ | 606 | |
| Natural gas sales | 91 | | 57 | | 4 | | 152 | | | 19 | | 17 | | — | | 36 | |
| Natural gas liquid sales | 150 | | 73 | | 16 | | 239 | | | 36 | | 28 | | 1 | | 65 | |
| | | | | | | | | |
| Total | $ | 1,224 | | $ | 549 | | $ | 124 | | $ | 1,897 | | | $ | 403 | | $ | 302 | | $ | 2 | | $ | 707 | |
| | | Nine Months Ended September 30, 2021 | | Nine Months Ended September 30, 2020 | | Three Months Ended March 31, 2022 | | Three Months Ended March 31, 2021 |
| | Midland Basin | Delaware Basin | Other | Total | | Midland Basin | Delaware Basin | Other | Total | | Midland Basin | Delaware Basin | Other | Total | | Midland Basin | Delaware Basin | Other | Total |
| | (In millions) | | (In millions) |
| Oil sales | Oil sales | $ | 2,428 | | $ | 1,185 | | $ | 232 | | $ | 3,845 | | | $ | 1,030 | | $ | 750 | | $ | 5 | | $ | 1,785 | | Oil sales | $ | 1,398 | | $ | 545 | | $ | 3 | | $ | 1,946 | | | $ | 569 | | $ | 358 | | $ | 17 | | $ | 944 | |
| Natural gas sales | Natural gas sales | 207 | | 145 | | 11 | | 363 | | | 32 | | 29 | | — | | 61 | | Natural gas sales | 98 | | 56 | | — | | 154 | | | 41 | | 61 | | 2 | | 104 | |
| Natural gas liquid sales | Natural gas liquid sales | 327 | | 172 | | 29 | | 528 | | | 88 | | 67 | | 1 | | 156 | | Natural gas liquid sales | 191 | | 97 | | 1 | | 289 | | | 75 | | 47 | | 2 | | 124 | |
| | Total | Total | $ | 2,962 | | $ | 1,502 | | $ | 272 | | $ | 4,736 | | | $ | 1,150 | | $ | 846 | | $ | 6 | | $ | 2,002 | | Total | $ | 1,687 | | $ | 698 | | $ | 4 | | $ | 2,389 | | | $ | 685 | | $ | 466 | | $ | 21 | | $ | 1,172 | |
4. ACQUISITIONS AND DIVESTITURES
First Quarter 2022 Acquisition
On January 18, 2022, the Company acquired, from an unrelated third-party seller, approximately 6,200 net acres in the Delaware Basin for $232 million in cash, including customary post-closing adjustments. The acquisition was funded through cash on hand.
Guidon Operating LLC
On December 21, 2020,February 26, 2021, the Company entered into a definitive purchase agreement to acquirecompleted its acquisition of all leasehold interests and related assets of Guidon Operating LLC (the “Guidon Acquisition”) which include approximately 32,500 net acres in the Northern Midland Basin in exchange for 10.68 million shares of the Company’s common stock and $375 million of cash. The Guidon Acquisition closed on February 26, 2021. The cash portion of this transaction was funded through a combination of cash on hand and borrowings under the Company’s credit facility. As a result of the Guidon Acquisition, the Company added approximately 210 gross producing wells.
The following table presents the acquisition consideration paid in the Guidon Acquisition (in millions, except per share data, shares in thousands):
| | | | | |
| Consideration: | |
| Shares of Diamondback common stock issued at closing | 10,676 |
| Closing price per share of Diamondback common stock on the closing date | $ | 69.28 | |
| Fair value of Diamondback common stock issued | $ | 740 | |
| Cash consideration | 375 | |
| Total consideration (including fair value of Diamondback common stock issued) | $ | 1,115 | |
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
Purchase Price Allocation
The Guidon Acquisition has been accounted for as a business combination using the acquisition method. The following table represents the allocation of the total purchase price paid in the Guidon Acquisition to the identifiable assets acquired based on the fair values at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired. Although thedate. The purchase price allocation is substantiallywas complete as of the datefirst quarter of this filing, there may be further adjustments to the fair value of certain assets acquired and liabilities assumed, including but not limited to the Company’s oil and natural gas properties. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date and may revise the value of the assets and liabilities as appropriate within that time frame. Through September 30, 2021, there have been no material changes to the allocation presented in the March 31, 2021 10-Q filed with the SEC on May 7, 2021.2022.
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
The following table sets forth the Company’s preliminary purchase price allocation (in millions):
| | | | | |
| |
| |
| |
| |
| |
| |
| Total consideration | $ | 1,115 | |
| |
| Fair value of liabilities assumed: | |
| Asset retirement obligations | 9 | |
| |
| Fair value of assets acquired: | |
| Oil and gas properties | 1,110 | |
| Midstream assets | 14 | |
| Amount attributable to assets acquired | 1,124 | |
| Net assets acquired and liabilities assumed | $ | 1,115 | |
Oil and natural gas properties were valued using an income approach utilizing the discounted cash flow method, which takes into account production forecasts, projected commodity prices and pricing differentials, and estimates of future capital and operating costs which were then discounted utilizing an estimated weighted-average cost of capital for industry market participants. The fair value of acquired midstream assets was based on the cost approach, which utilized asset listings and cost records with consideration for the reported age, condition, utilization and economic support of the assets. The majority of the measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and are therefore considered Level 3 inputs.
With the completion of the Guidon Acquisition, the Company acquired proved properties of $537 million and unproved properties of $573 million. The results of operations attributable to the Guidon Acquisition since the acquisition date have been included in the condensed consolidated statements of operations and include $107 million and $240$28 million of total revenue for the three and nine months ended September 30, 2021, respectively, and $52 million and $117$16 million of net income for the three and nine months ended September 30, 2021, respectively.March 31, 2021.
QEP Resources, Inc.
On March 17, 2021, the Company completed its acquisition of QEP in an all-stock transaction (the “QEP Merger”). The addition of QEP’s assets increased the Company’s net acreage in the Midland Basin by approximately 49,000 net acres. Under the terms of the QEP Merger, each eligible share of QEP common stock issued and outstanding immediately prior to the effective time converted into the right to receive 0.050 of a share of Diamondback common stock, with cash being paid in lieu of any fractional shares (the “merger consideration”). At the closing date of the QEP Merger, the carrying value of QEP’s outstanding debt was approximately $1.6 billion. See Note 7—Debt for further discussion.
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
The following table presents the acquisition consideration paid to QEP stockholders in the QEP Merger (in millions, except per share data, shares in thousands):
| | | | | |
| Consideration: | |
| Eligible shares of QEP common stock converted into shares of Diamondback common stock | 238,153 | |
| Shares of QEP equity awards included in precombination consideration | 4,221 | |
| Total shares of QEP common stock eligible for merger consideration | 242,374 | |
| Exchange ratio | 0.050 | |
| Shares of Diamondback common stock issued as merger consideration | 12,119 | |
| Closing price per share of Diamondback common stock | $ | 81.41 | |
| Total consideration (fair value of the Company's common stock issued) | $ | 987 | |
| |
| |
Purchase Price Allocation
The QEP Merger has been accounted for as a business combination using the acquisition method. The following table represents the preliminary allocation of the total purchase price for the acquisition of QEP to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date, with any excess of the purchase price over the estimated fair value of the identifiable net assets acquired. Although thedate. The purchase price allocation is substantiallywas complete as of the datefirst quarter of this filing, certain data necessary to complete the purchase price allocation is not yet available, and includes, but is not limited to, final tax returns that provide the underlying tax basis of QEP’s assets and liabilities. As such, there may be further adjustments to the fair value of certain assets acquired and liabilities assumed, including the Company’s oil and natural gas properties. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date. Through September 30, 2021, there have been no material changes to the allocation presented in the March 31, 2021 10-Q filed with the SEC on May 7, 2021.2022.
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
The following table sets forth the Company’s preliminary purchase price allocation (in millions):
| | | | | |
| |
| Total consideration | $ | 987 | |
| |
| Fair value of liabilities assumed: | |
| Accounts payable - trade | $ | 26 | |
| Accrued capital expenditures | 38 | |
| Other accrued liabilities | 108107 | |
| Revenues and royalties payable | 67 | |
| Derivative instruments | 242 | |
| Long-term debt | 1,710 | |
| Asset retirement obligations | 54 | |
| |
| Other long-term liabilities | 4763 | |
| Amount attributable to liabilities assumed | $ | 2,2922,307 | |
| |
| Fair value of assets acquired: | |
| Cash, cash equivalents and restricted cash | $ | 22 | |
| Accounts receivable - joint interest and other, net | 87 | |
| Accounts receivable - oil and natural gas sales, net | 44 | |
| Inventories | 18 | |
| Income tax receivable | 33 | |
| Prepaid expenses and other current assets | 7 | |
| Oil and natural gas properties | 2,9362,922 | |
| Other property, equipment and land | 916 | |
| Deferred income taxes | 1739 | |
| Other assets | 106 | |
| Amount attributable to assets acquired | 3,2793,294 | |
| Net assets acquired and liabilities assumed | $ | 987 | |
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
The purchase price allocation above wasis based on preliminary estimates of the fair values of the assets and liabilities of QEP as of the closing date of the QEP Merger. The majority of the measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and are therefore considered Level 3 inputs. The fair value of acquired property and equipment, including midstream assets classified in oil and natural gas properties, is based on the cost approach, which utilized asset listings and cost records with consideration for the reported age, condition, utilization and economic support of the assets. Oil and natural gas properties were valued using an income approach utilizing the discounted cash flow method, which takes into account production forecasts, projected commodity prices and pricing differentials, and estimates of future capital and operating costs which were then discounted utilizing an estimated weighted-average cost of capital for industry market participants. The fair value of QEP’s outstanding senior unsecured notes was based on unadjusted quoted prices in an active market, which are considered Level 1 inputs. The value of derivative instruments was based on observable inputs including forward commodity-price curves which are considered Level 2 inputs. Deferred income taxes represent the tax effects of differences in the tax basis and merger-date fair values of assets acquired and liabilities assumed.
With the completion of the QEP Merger, the Company acquired proved properties of $2.3$2.0 billion and unproved properties of $442$733 million, primarily in the Midland Basin and the Williston Basin. In October 2021, the Company completed the divestiture of the Williston Basin properties, acquired as part of the QEP Merger and consisting of approximately 95,000 net acres, to Oasis Petroleum Inc. for net cash proceeds of approximately $586 million, after customary closing adjustments. See “—Williston Basin Divestiture” below.
The results of operations attributable to the QEP Merger since the acquisition date have been included in the condensed consolidated statements of operations and include $422 million and $835$54 million of total revenue and $162 million and $301$23 million of net income for the three and nine months ended September 30, 2021, respectively.March 31, 2021.
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
Pro Forma Financial Information
The following unaudited summary pro forma financial information for the three and nine months ended September 30,March 31, 2021 and 2020 has been prepared to give effect to the QEP Merger and the Guidon Acquisition as if they had occurred on January 1, 2020. The unaudited pro forma financial information does not purport to be indicative of what the combined company’s results of operations would have been if these transactions had occurred on the dates indicated, nor is it indicative of the future financial position or results of operations of the combined company.
The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for QEP’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including adjustments to depreciation, depletion and amortization based on the full cost method of accounting and the purchase price allocated to property, plant, and equipment as well as adjustments to interest expense and the provision for (benefit from) income taxes.
Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company for the QEP Merger and the Guidon Acquisition of approximately $77$75 million for the ninethree months ended September 30,March 31, 2021 and acquisition-related costs incurred by QEP of $31 million through the closing date of the QEP Merger. These acquisition-related costs primarily consist of one-time severance costs and the accelerated or change-in-control vesting of certain QEP share-based awards for former QEP employees based on the terms of the merger agreement relating to the QEP Merger and other bank, legal and advisory fees. The pro forma results of operations do not include any cost savings or other synergies that may result from the QEP Merger and the Guidon Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the acquired assets. The pro forma financial data does not include the results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material.
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| (In millions, except per share amounts) |
| Revenues | $ | 1,910 | | | $ | 942 | | | $ | 5,047 | | | $ | 2,705 | |
| Income (loss) from operations | $ | 1,164 | | | $ | (1,244) | | | $ | 2,870 | | | $ | (4,780) | |
| Net income (loss) | $ | 649 | | | $ | (1,124) | | | $ | 1,183 | | | $ | (3,593) | |
| Basic earnings (loss) per common share | $ | 3.59 | | | $ | (6.22) | | | $ | 6.54 | | | $ | (19.88) | |
| Diluted earnings (loss) per common share | $ | 3.56 | | | $ | (6.22) | | | $ | 6.50 | | | $ | (19.88) | |
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| | | Three Months Ended March 31, 2021 | | | | |
| | | (In millions, except per share amounts) |
| Revenues | | | $ | 1,481 | | | | | |
| Income (loss) from operations | | | $ | 684 | | | | | |
| Net income (loss) | | | $ | 146 | | | | | |
| Basic earnings (loss) per common share | | | $ | 0.81 | | | | | |
| Diluted earnings (loss) per common share | | | $ | 0.80 | | | | | |
Williston Basin Divestiture
On October 21, 2021, the Company completed the divestiture of its Williston Basin oil and natural gas assets, consisting of approximately 95,000 net acres, to Oasis Petroleum Inc., for net cash proceeds of approximately $586 million, after customary closing adjustments. This transaction did not result in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves and, accordingly, the Company recorded the proceeds as a reduction of its full cost pool with no gain or loss recognized on the sale. The Company used its net proceeds from this transaction toward debt reduction.
2021 Drop Down Transaction
On December 1, 2021, Diamondback completed the sale of certain water midstream assets to Rattler in exchange for cash proceeds of approximately $164 million, including post-closing adjustments, in a drop down transaction (the “Drop Down”). The midstream assets consist primarily of produced water gathering and disposal systems, produced water recycling facilities, and sourced water gathering and storage assets acquired by the Company through the Guidon Acquisition and the QEP Merger with a carrying value of approximately $164 million. The Company and Rattler have also mutually agreed to amend their commercial agreements covering produced water gathering and disposal and sourced water gathering services to add certain Diamondback leasehold acreage to Rattler’s dedication. The Drop Down transaction was accounted for as a transaction between entities under common control.
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
DivestituresViper’s Swallowtail Acquisition
On June 3,October 1, 2021, Viper acquired certain mineral and June 7, 2021, respectively,royalty interests from the Company closed transactionsSwallowtail entities pursuant to divest certain non-core Permian assets including over 7,000a definitive purchase and sale agreement for 15.25 million of Viper’s common units and approximately $225 million in cash (the “Swallowtail Acquisition”). The mineral and royalty interests acquired in the Swallowtail Acquisition represent approximately 2,313 net royalty acres of non-core Southernprimarily in the Northern Midland Basin, acreage in Upton county, Texasof which approximately 62% are operated by Diamondback. The Swallowtail Acquisition had an effective date of August 1, 2021. The cash portion of this transaction was funded through a combination of Viper’s cash on hand and approximately 1,300 net acres$190 million of non-core, non-operated Delaware Basin assets in Lea county, New Mexico for a combined sales price of $82 million, net of customary purchase price adjustments. These assets have estimated full year 2021 net production of approximately 900 BO/d (2,650 BOE/d) from 140 producing wells. The Company used its net proceeds from these transactions toward debt reduction.
See Note 14—Subsequent Events for further discussion of acquisitions and divestitures in the fourth quarter of 2021.borrowings under Viper LLC’s revolving credit facility.
5. PROPERTY AND EQUIPMENT
Property and equipment includes the following as of the dates indicated:
| | | September 30, | | December 31, | | March 31, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| | (In millions) | | (In millions) |
| Oil and natural gas properties: | Oil and natural gas properties: | | Oil and natural gas properties: | |
| Subject to depletion | Subject to depletion | $ | 24,340 | | | $ | 19,884 | | Subject to depletion | $ | 25,133 | | | $ | 24,418 | |
| Not subject to depletion | Not subject to depletion | 8,214 | | | 7,493 | | Not subject to depletion | 8,512 | | | 8,496 | |
| Gross oil and natural gas properties | Gross oil and natural gas properties | 32,554 | | | 27,377 | | Gross oil and natural gas properties | 33,645 | | | 32,914 | |
| Accumulated depletion | Accumulated depletion | (5,136) | | | (4,237) | | Accumulated depletion | (5,716) | | | (5,434) | |
| Accumulated impairment | Accumulated impairment | (7,954) | | | (7,954) | | Accumulated impairment | (7,954) | | | (7,954) | |
| Oil and natural gas properties, net | Oil and natural gas properties, net | 19,464 | | | 15,186 | | Oil and natural gas properties, net | 19,975 | | | 19,526 | |
| Midstream assets | Midstream assets | 922 | | | 1,013 | | Midstream assets | 1,118 | | | 1,076 | |
| Other property, equipment and land | Other property, equipment and land | 164 | | | 138 | | Other property, equipment and land | 185 | | | 174 | |
| Accumulated depreciation and impairment | Accumulated depreciation and impairment | (144) | | | (123) | | Accumulated depreciation and impairment | (170) | | | (157) | |
| Total property and equipment, net | Total property and equipment, net | $ | 20,406 | | | $ | 16,214 | | Total property and equipment, net | $ | 21,108 | | | $ | 20,619 | |
|
Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter which determines a limit, or ceiling, on the book value of proved oil and natural gas properties. No impairment expense was recorded for the three and nine months ended September 30, 2021. The Company recorded $1.5 billion and $5.0 billion in impairment expense for the three and nine months ended September 30, 2020, respectively,March 31, 2022 or 2021 based on the results of the respective quarterly ceiling tests.
In connection with the QEP Merger and the Guidon Acquisition, the Company recorded the oil and natural gas properties acquired at fair value, based on forward strip oil and natural gas pricing existing at the closing date of the respective transactions, in accordance with ASC 820 Fair Value Measurement. Pursuant to SEC guidance, the Company determined that the fair value of the properties acquired in the QEP Merger and the Guidon Acquisition clearly exceeded the related full cost ceiling limitation beyond a reasonable doubt. As such, the Company requested and received a waiver from the SEC to exclude the properties acquired from the ceiling test calculation for the quarter ended March 31, 2021. As a result, no impairment expense related to the QEP Merger and the Guidon Acquisition was recorded for the three months ended March 31, 2021. Had the Company not received a waiver from the SEC, an impairment charge of approximately $1.1 billion would have been recorded for such period. Management affirmed there has not been a decline in the fair value of these acquired assets. The properties acquired in the QEP Merger and the Guidon Acquisition had total unamortized costs at March 31, 2021 of $3.0 billion and $1.1 billion, respectively.
In addition to commodity prices, the Company’s production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine its actual ceiling test calculation and impairment analysis in future periods. If the future trailing 12-month commodity prices decline as compared to the commodity prices used in prior quarters, the Company may have material write downs in subsequent quarters. It is possible that circumstances requiring additional impairment testing will occur in future interim periods, which could result in potentially material impairment charges being recorded.
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
6. ASSET RETIREMENT OBLIGATIONS
The following table describes the changes to the Company’s asset retirement obligations liability for the following periods:
| | | Nine Months Ended September 30, | | Three Months Ended March 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| | (In millions) | | (In millions) |
| Asset retirement obligations, beginning of period | Asset retirement obligations, beginning of period | $ | 109 | | | $ | 94 | | Asset retirement obligations, beginning of period | $ | 171 | | | $ | 109 | |
| Additional liabilities incurred | Additional liabilities incurred | 9 | | | 12 | | Additional liabilities incurred | 21 | | | 2 | |
| Liabilities acquired | Liabilities acquired | 64 | | | 3 | | Liabilities acquired | 2 | | | 63 | |
| Liabilities settled and divested | Liabilities settled and divested | (17) | | | (1) | | Liabilities settled and divested | (5) | | | (1) | |
| Accretion expense | Accretion expense | 7 | | | 5 | | Accretion expense | 3 | | | 2 | |
| Revisions in estimated liabilities | Revisions in estimated liabilities | 13 | | | — | | Revisions in estimated liabilities | 75 | | | 20 | |
| Asset retirement obligations, end of period | Asset retirement obligations, end of period | 185 | | | 113 | | Asset retirement obligations, end of period | 267 | | | 195 | |
Less current portion(1) | Less current portion(1) | 7 | | | 1 | | Less current portion(1) | 13 | | | 5 | |
| Asset retirement obligations - long-term | Asset retirement obligations - long-term | $ | 178 | | | $ | 112 | | Asset retirement obligations - long-term | $ | 254 | | | $ | 190 | |
(1) The current portion of the asset retirement obligation is included in other accrued liabilities in the Company’s condensed consolidated balance sheets.
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
7. DEBT
Long-term debt consisted of the following as of the dates indicated:
| | | September 30, | | December 31, | | March 31, | | December 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| | (In millions) | | (In millions) |
| 4.625% Notes due 2021 | $ | — | | | $ | 191 | | |
| 5.375% Senior Notes due 2022(1) | 5.375% Senior Notes due 2022(1) | 25 | | | — | | 5.375% Senior Notes due 2022(1) | $ | 25 | | | $ | 25 | |
7.320% Medium-term Notes, Series A, due 2022 | 7.320% Medium-term Notes, Series A, due 2022 | 20 | | | 20 | | 7.320% Medium-term Notes, Series A, due 2022 | 20 | | | 20 | |
0.900% Senior Notes due 2023(2) | 650 | | | — | | |
| 5.250% Senior Notes due 2023(1) | 5.250% Senior Notes due 2023(1) | 10 | | | — | | 5.250% Senior Notes due 2023(1) | 10 | | | 10 | |
| 2.875% Senior Notes due 2024 | 2.875% Senior Notes due 2024 | 1,000 | | | 1,000 | | 2.875% Senior Notes due 2024 | — | | | 1,000 | |
| 4.750% Senior Notes due 2025 | 4.750% Senior Notes due 2025 | 500 | | | 500 | | 4.750% Senior Notes due 2025 | — | | | 500 | |
| 5.375% Senior Notes due 2025 | — | | | 800 | | |
| | 3.250% Senior Notes due 2026 | 3.250% Senior Notes due 2026 | 800 | | | 800 | | 3.250% Senior Notes due 2026 | 800 | | | 800 | |
5.625% Senior Notes due 2026(1) | 5.625% Senior Notes due 2026(1) | 18 | | | — | | 5.625% Senior Notes due 2026(1) | 14 | | | 14 | |
| 7.125% Medium-term Notes, Series B, due 2028 | 7.125% Medium-term Notes, Series B, due 2028 | 100 | | | 100 | | 7.125% Medium-term Notes, Series B, due 2028 | 100 | | | 100 | |
| 3.500% Senior Notes due 2029 | 3.500% Senior Notes due 2029 | 1,200 | | | 1,200 | | 3.500% Senior Notes due 2029 | 1,200 | | | 1,200 | |
| 3.125% Senior Notes due 2031 | 3.125% Senior Notes due 2031 | 900 | | | — | | 3.125% Senior Notes due 2031 | 900 | | | 900 | |
| 4.400% Senior Notes due 2051 | 4.400% Senior Notes due 2051 | 650 | | | — | | 4.400% Senior Notes due 2051 | 650 | | | 650 | |
| 4.750% Senior Notes due 2052 | | 4.750% Senior Notes due 2052 | 750 | | | — | |
DrillCo Agreement(3) | DrillCo Agreement(3) | 65 | | | 79 | | DrillCo Agreement(3) | 64 | | | 58 | |
| Unamortized debt issuance costs | Unamortized debt issuance costs | (35) | | | (29) | | Unamortized debt issuance costs | (30) | | | (31) | |
| Unamortized discount costs | Unamortized discount costs | (29) | | | (27) | | Unamortized discount costs | (30) | | | (28) | |
| Unamortized premium costs | Unamortized premium costs | 9 | | | 15 | | Unamortized premium costs | 7 | | | 8 | |
Fair value of interest rate swap agreements(4) | Fair value of interest rate swap agreements(4) | (10) | | | — | | Fair value of interest rate swap agreements(4) | (90) | | | (18) | |
| Revolving credit facility | Revolving credit facility | — | | | 23 | | Revolving credit facility | — | | | — | |
| Viper revolving credit facility | Viper revolving credit facility | 92 | | | 84 | | Viper revolving credit facility | 248 | | | 304 | |
| Viper 5.375% Senior Notes due 2027 | Viper 5.375% Senior Notes due 2027 | 480 | | | 480 | | Viper 5.375% Senior Notes due 2027 | 480 | | | 480 | |
| Rattler revolving credit facility | Rattler revolving credit facility | — | | | 79 | | Rattler revolving credit facility | 230 | | | 195 | |
| Rattler 5.625% Senior Notes due 2025 | Rattler 5.625% Senior Notes due 2025 | 500 | | | 500 | | Rattler 5.625% Senior Notes due 2025 | 500 | | | 500 | |
| Total debt, net | Total debt, net | 6,945 | | | 5,815 | | Total debt, net | 5,848 | | | 6,687 | |
| Less: current maturities of long-term debt | Less: current maturities of long-term debt | (20) | | | (191) | | Less: current maturities of long-term debt | (45) | | | (45) | |
| Total long-term debt | Total long-term debt | $ | 6,925 | | | $ | 5,624 | | Total long-term debt | $ | 5,803 | | | $ | 6,642 | |
(1) At the effective time of the QEP Merger, QEP became a wholly owned subsidiary of the Company and remained the issuer of thethese senior notes.
(2) See Note 14—Subsequent Events for further discussionIn November 2018, Energen became the Company’s wholly owned subsidiary and remained the issuer of these senior notes. In connection with the redemption ofE&P Merger, Diamondback E&P became the 0.900% Senior Notes due 2023 insuccessor issuer under the fourth quarter of 2021.indenture. (3) The Company entered into a participation and development agreement (the “DrillCo Agreement”), dated September 10, 2018, with Obsidian Resources, L.L.C. (“CEMOF”) to fund oil and natural gas development. As of September 30, 2021,March 31, 2022, the amount due to CEMOF related to this alliance was $65$64 million. As of March 31, 2022, 20 joint wells under this agreement have been drilled and completed.
(4) The Company has 2 interest rate swap agreements in place on the Company’s $1.2 billion 3.500% fixed rate senior notes due 2029. See Note 11—Derivatives for additional information on the Company’s interest rate swaps designated as fair value hedges.
References in this section to the Company shall mean Diamondback Energy, Inc. and Diamondback E&P, collectively, unless otherwise specified.
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
Second Amended and Restated Credit Facility
On June 2, 2021,As of March 31, 2022, Diamondback E&P, as borrower, and Diamondback Energy, Inc., as parent guarantor, and O&G, as borrower (the “Borrower”), entered intohave a twelfth amendment (the “Amendment”) to the Second Amended and Restated Credit Agreement, dated as of November 1, 2013, with Wells Fargo Bank, National Association, as administrative agent (the “Administrative Agent”), and the lenders party thereto (as amended, supplemented or otherwise modified to the date thereof and as further amended by the Amendment). The Amendment, among other things, (i) extended the maturity date to June 2, 2026, which may be further extended by 2 one-year extensions pursuant to the terms set forth in the credit agreement, (ii) decreased the total revolving loan commitments from $2.0 billion to $1.6 billion, which may be increased in an amount up to $1.0 billion (for a total maximum commitment amount of $2.6 billion) upon election of the Borrower (subject to obtaining additional lender commitments and satisfaction of customary conditions) pursuant to the terms set forth in the credit agreement, (iii) added the ability of the Borrower to incur up to $100 million of the loans under the credit agreement, as swingline loans and (iv) changed the interest rate applicable to the loans and certain fees payable under the credit agreement. Outstanding borrowings under the credit agreement bear interest atamended, which provides for a per annum rate elected by the Borrower that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50%, and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. After giving effect to the Amendment, (i) the applicable margin ranges from 0.250% to 1.125% per annum in the case of the alternate base rate, and from 1.250% to 2.125% per annum in the case of LIBOR, in each case based on the pricing level, and (ii) the commitment fee ranges from 0.150% to 0.350% per annum on the average daily unused portion of the commitments, based on the pricing level. The pricing level depends on certain ratings agencies’ ratings of the Company’s long-term senior unsecured debt.
On June 30, 2021, Diamondback E&P, as successor borrower, Diamondback Energy, Inc., as parent guarantor, and the Administrative Agent entered into a Successor Borrower Joinder Agreement (the “Joinder Agreement”) in connection with the E&P Merger. Pursuant to the Joinder Agreement, Diamondback E&P assumed all obligations (including, without limitation, all of the indebtedness) of O&G as the borrower under the credit agreement, the Second Amended and Restated Guaranty Agreement, dated as of November 20, 2019, made by O&G and Diamondback Energy, Inc., and the other documents entered into connection therewith.
As of September 30, 2021, the maximum credit amount available under the credit agreement wasof $1.6 billion which was fully available for future borrowings, except for an aggregate of $3 million in outstanding letters of credit, which reduce available borrowings under the credit agreement on a dollar for dollar basis. There were no borrowings outstanding under the credit agreement during the three months ended September 30, 2021.March 31, 2022. During the three months ended September 30, 2020,March 31, 2021, the weighted average interest rate on borrowings under the credit agreement was 1.83%1.65%. During the nine months ended September 30, 2021 and 2020, the weighted average interest rate on borrowings under the credit agreement was 1.67% and 2.27%, respectively.
As of September 30, 2021,March 31, 2022, the Company was in compliance with all financial maintenance covenants under the credit agreement.
March 20212022 Notes Offering
On March 24, 2021,17, 2022, Diamondback Energy, Inc. issued $650$750 million aggregate principal amount of 0.900%4.250% Senior Notes due March 24, 202315, 2052 (the “2023 Notes”), $900 million aggregate principal amount of 3.125% Senior Notes due March 24, 2031 (the “2031 Notes”) and $650 million aggregate principal amount of 4.400% Senior Notes due March 24, 2051 (the “2051 Notes” and together with the 2023 Notes and the 2031 Notes, the “March 20212022 Notes”) and received net proceeds net of $24$739 million, inafter deducting debt issuance costs and discounts of $2.18 billion. The net proceeds were primarily used to fund the repurchase of other senior notes outstanding as discussed further below.$11 million and underwriting discounts and offering expenses. Interest on the March 20212022 Notes is payable semi-annually inon March 15 and September 15 of each year, beginning inon September 2021.15, 2022.
The March 20212022 Notes are the Company’s senior unsecured obligations and are fully and unconditionally guaranteed by Diamondback E&P. The March 20212022 Notes are senior in right of payment to any of the Company’s future subordinated indebtedness and rank equal in right of payment with all of the Company’s existing and future senior indebtedness. The March 2021 Notes are effectively subordinated to the Company’s existing and future secured indebtedness, if any, to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all of the existing and future indebtedness and other liabilities of the Company’s subsidiaries other than Diamondback E&P.
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
The Company may not redeem the 2023March 2022 Notes in whole or in part at any time prior to September 24, 2021. The Company may redeem (i) the 2031 Notes in whole or in part at any time prior to December 24, 2030 and (ii) the15, 2051 Notes in whole or in part at any time prior to September 24, 2050, in each case at the redemption price set forth in the 2019fifth supplemental indenture to the IG Indenture. If the March 2021 Notes are redeemed on or after the dates noted above, in each case, the March 2021 Notes may be redeemed at a redemption price equal to 100% of the principal amount of the March 2021 Notes to be redeemed plus interest accrued thereon to but not including the redemption date.
Upon the occurrence of a change of control triggering event as defined in the 2019 Indenture, holders may require the Company to purchase some or all of their March 2021 Notes for cash at a price equal to 101% of the principal amount of the March 2021 Notes being purchased, plus accrued and unpaid interest, if any, to the date of purchase.
RepurchasesRedemptions of Notes
On March 17, 2021, at the time of the QEP Merger discussed in Note 4—Acquisitions and Divestitures, QEP had outstanding debt at fair values consisting of $478 million of 5.375% Senior Notes due18, 2022, (the “QEP 2022 Notes”), $673 million of 5.250% Senior Notes due 2023 (the “QEP 2023 Notes”) and $558 million of 5.625% Senior Notes due 2026 (the “QEP 2026 Notes” and together with the QEP 2022 Notes and QEP 2023 Notes, the “QEP Notes”).
Subsequent to the QEP Merger, in March 2021, the Company repurchased pursuant to tender offers commenced byredeemed the Company, approximately $1.65 billion in fair value carryingaggregate $500 million principal amount of the QEPits outstanding 4.750% 2025 Senior Notes for total cash consideration of $1.7 billion,$540 million, including redemption and earlya make-whole premium fees of $152$33 million, which resulted in a loss on extinguishment of debt during the ninethree months ended September 30, 2021March 31, 2022 of approximately $47$35 million. The aggregate fair valueCompany funded the redemption with a portion of the QEP Notes repurchased consisted of (i) $453 million, or 94.65%, ofnet proceeds from the outstanding fair value carrying amount of the QEPMarch 2022 Notes (ii) $663 million, or 98.43%, of the outstanding fair value carrying amount of the QEP 2023 Notes and (iii) $538 million, or 96.35%, of the outstanding fair value carrying amount of the QEP 2026 Notes.offering.
InOn March 2021,23, 2022, the Company also repurchased anredeemed the aggregate of $368 million$1.0 billion principal amount of its 5.375% 2025 Senior Notes representing approximately 45.97% of the outstanding 20252.875% 2024 Senior Notes for total cash consideration of $381 million,$1.0 billion, including redemption and earlya make-whole premium fees of $13 million. This resulted in a loss on extinguishment of debt during the nine months ended September 30, 2021 of $14 million. The Company funded the repurchases of the QEP Notes and 2025 Senior Notes with the proceeds from the March 2021 Notes offering discussed above.
In connection with the tender offers to repurchase the QEP Notes discussed above, the Company also solicited consents from holders of the QEP Notes to amend the indenture for the QEP Notes to, among other things, eliminate substantially all of the restrictive covenants and related provisions and certain events of default contained in the indenture under which the QEP Notes were issued. The Company received the requisite number of consents and, on March 23, 2021, entered into a supplemental indenture relating to the QEP Notes adopting these amendments.
In June 2021, the Company redeemed the remaining $191 million principal amount of the outstanding Energen 4.625% senior notes due on September 1, 2021. The Company recorded an immaterial pre-tax loss on extinguishment of debt related to the redemption, which included the write-off of unamortized debt discounts associated with the redeemed notes. The Company funded the redemption with internally generated cash flow from operations as well as proceeds from the divestitures of certain non-core assets as discussed in Note 4—Acquisitions and Divestitures.
In August 2021, the Company redeemed the remaining $432 million principal amount of its outstanding 5.375% 2025 Senior Notes for total cash consideration of $449 million, including redemption and early premium fees of $12 million, which resulted in a loss on extinguishment of debt during the ninethree months ended September 30, 2021March 31, 2022 of $12$19 million. The Company funded the redemption with the remaining proceeds from the March 2022 Notes offering and cash on hand and borrowings under its revolving credit facility.hand.
Energen Notes
In connection with the E&P Merger, Diamondback E&P became the successor issuer under the indenture, dated as of September 1, 1996, pursuant to which Energen issued $100 million aggregate principal amount of 7.125% Medium-Term Notes, Series B due 2028 and $20 million aggregate principal amount of 7.32% Medium-Term Notes, Series A due 2022.
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
Viper’s Credit Agreement
Viper LLC’s existing credit agreement, as amended, by the seventh amendment on June 2, 2021 (the “Viper Amendment”), provides for a revolving credit facility in the maximum credit amount of $2.0 billion with a borrowing base of $580 million based on Viper LLC’s oil and natural gas reserves and other factors. Among other changes, the Viper Amendment added new provisions that allow Viper LLC to elect a commitment amount that is less than its borrowing base as determined by the lenders. As of September 30, 2021, the elected commitment amount was $500 million with $92 million of outstanding borrowings and $408 million available for future borrowings. The borrowing base is scheduled to be redetermined semi-annually in May and November,November. As of March 31, 2022, the elected commitment amount was $500 million with $248 million of outstanding borrowings and is expected to be reaffirmed at $580$252 million by the lenders during the redetermination in November 2021.available for future borrowings. During the three and nine months ended September 30,March 31, 2022 and 2021, and 2020, the weighted average interest rate on borrowings under the Viper credit agreement was 1.98%, 2.14%, 2.14%2.58% and 2.66%1.88%, respectively. The Viper credit agreement will mature on June 2, 2025. As of September 30, 2021,March 31, 2022, Viper LLC was in compliance with all financial maintenance covenants under the Viper credit agreement.
Rattler’s Credit Agreement
Rattler LLC’s credit agreement, as amended, provides for a revolving credit facility in the maximum credit amount of $600 million, which is expandable to $1.0 billion upon Rattler’s election, subject to obtaining additional lender commitments and satisfaction of customary conditions. As of September 30, 2021,March 31, 2022, Rattler LLC had no$230 million of outstanding borrowings and $600$370 million available for future borrowings under the Rattler credit agreement. During the three and nine months ended September 30,March 31, 2022 and 2021, and 2020, the weighted average interest rate on borrowings under the Rattler credit agreement was, 1.34%, 1.38%, 1.46% and 2.18%, respectively.in each case, 1.40%. The revolving credit facility will mature on May 28, 2024. As of September 30, 2021,March 31, 2022, Rattler LLC was in compliance with all financial maintenance covenants under the Rattler credit agreement.
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
8. CAPITAL STOCKSTOCKHOLDERS’ EQUITY AND EARNINGS PER SHARE
Diamondback did not complete any equity offerings during the nine months ended September 30, 2021 and September 30, 2020. As discussed in Note 4—Acquisitions and Divestitures, Diamondback issued 12.12 million shares of the Company’s stock as consideration for the QEP Merger and 10.68 million shares of the Company’s stock as consideration for the Guidon Acquisition during the nine months ended September 30, 2021.
Stock Repurchase Program
In September 2021, the Company’s board of directors approved a stock repurchase program to acquire up to $2 billion of the Company’s outstanding common stock. Purchases under the repurchase program may be made from time to time in open market or privately negotiated transactions, and are subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program does not require the Company to acquire any specific 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 and nine months ended September 30, 2021,March 31, 2022, the Company repurchased approximately $22$7 million of common stock under this repurchase program, respectively.program. As of September 30, 2021, $1.98March 31, 2022, approximately $1.6 billion remained available for use to repurchase shares under the Company’s common stock repurchase program.
Change in Ownership of Consolidated Subsidiaries
Non-controlling interests in the accompanying condensed consolidated financial statements represent minority interest ownership in Viper and Rattler and are presented as a component of equity. When the Company’s relative ownership interests in Viper and Rattler change, adjustments to non-controlling interest and additional paid-in-capital, tax effected, will occur. The following table summarizes changes in the ownership interest in consolidated subsidiaries during the periods presented:
| | | | | | | | | | | | | | | |
| | | | | | | |
| Three Months Ended March 31, | | |
| 2022 | | 2021 | | | | |
| (In millions) |
| Net income (loss) attributable to the Company | $ | 779 | | | $ | 220 | | | | | |
| Change in ownership of consolidated subsidiaries | (12) | | | (4) | | | | | |
| Change from net income (loss) attributable to the Company's stockholders and transfers to non-controlling interest | $ | 767 | | | $ | 216 | | | | | |
Earnings (Loss) Per Share
The Company’s basic earnings (loss) per share amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted earnings per share include the effect of potentially dilutive shares outstanding for the period. Additionally, the per share earnings of Viper and Rattler are included in the consolidated earnings per share computation based on the consolidated group’s holdings of the subsidiaries.
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, | | Three Months Ended March 31, | |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | |
| | ($ in millions, except per share amounts, shares in thousands) | | ($ in millions, except per share amounts, shares in thousands) |
| Net income (loss) attributable to common stock | Net income (loss) attributable to common stock | $ | 649 | | | $ | (1,113) | | | $ | 1,180 | | | $ | (3,778) | | Net income (loss) attributable to common stock | $ | 779 | | | $ | 220 | | |
| Weighted average common shares outstanding: | Weighted average common shares outstanding: | | Weighted average common shares outstanding: | | |
| Basic weighted average common shares outstanding | Basic weighted average common shares outstanding | 181,027 | | | 157,833 | | | 175,464 | | | 157,984 | | Basic weighted average common shares outstanding | 177,565 | | | 164,169 | | |
| Effect of dilutive securities: | Effect of dilutive securities: | | Effect of dilutive securities: | | |
Potential common shares issuable (1) | Potential common shares issuable (1) | 1,122 | | | — | | | 1,089 | | | — | | Potential common shares issuable (1) | 990 | | | 757 | | |
| Diluted weighted average common shares outstanding | Diluted weighted average common shares outstanding | 182,149 | | | 157,833 | | | 176,553 | | | 157,984 | | Diluted weighted average common shares outstanding | 178,555 | | | 164,926 | | |
| Basic net income (loss) attributable to common stock | Basic net income (loss) attributable to common stock | $ | 3.59 | | | $ | (7.05) | | | $ | 6.73 | | | $ | (23.91) | | Basic net income (loss) attributable to common stock | $ | 4.39 | | | $ | 1.34 | | |
| Diluted net income (loss) attributable to common stock | Diluted net income (loss) attributable to common stock | $ | 3.56 | | | $ | (7.05) | | | $ | 6.68 | | | $ | (23.91) | | Diluted net income (loss) attributable to common stock | $ | 4.36 | | | $ | 1.33 | | |
(1) For the three and nine months ended September 30, 2021,March 31, 2022, there were 58,522 and 69,199no potential common units, respectively,shares excluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive under the treasury stock method. For the three and nine months ended September 30, 2020, noMarch 31, 2021, 241,091 potential common unitsshares were included inexcluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive.
Change in Ownership of Consolidated Subsidiaries
Non-controlling interests inanti-dilutive under the accompanying condensed consolidated financial statements represent minority interest ownership in Viper and Rattler and are presented as a component of equity. When the Company’s relative ownership interests in Viper and Rattler change, adjustments to non-controlling interest and additional paid-in-capital, tax effected, will occur. The following table summarizes changes in the ownership interest in consolidated subsidiaries during the periods presented:
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| (In millions) |
| Net income (loss) attributable to the Company | $ | 649 | | | $ | (1,113) | | | $ | 1,180 | | | $ | (3,778) | |
| Change in ownership of consolidated subsidiaries | (6) | | | — | | | (13) | | | 329 | |
| Change from net income (loss) attributable to the Company's stockholders and transfers to non-controlling interest | $ | 643 | | | $ | (1,113) | | | $ | 1,167 | | | $ | (3,449) | |
9. EQUITY-BASED COMPENSATION
On June 3, 2021, the Company’s stockholders approved and adopted the Company’s 2021 amended and restated equity incentive plan (the “Equity Plan”), which, among other things, increased total shares authorized for issuance from 8.3 million to 11.8 million. At September 30, 2021,March 31, 2022, the Company had 8.35.1 million shares of common stock available for future grants.
Under the Equity Plan, approved by the Board of Directors, the Company is authorized to issue incentive and non-statutory stock options, restricted stock awards and restricted stock units, performance awards and stock appreciation rights to eligible employees. At September 30, 2021,March 31, 2022, the Company had outstanding restricted stock units and performance-based restricted stock units under the Equity Plan. The Company also has immaterial amounts of restricted share awards, and restricted stock units which were assumed in connection with the QEP Merger and immaterial amounts of stock options and stock appreciation rights.rights outstanding which were issued under plans assumed in connection with previously completed mergers. The Company classifies these as equity-based awards and estimates the fair values of restricted stock awards and units as the closing price of the Company’s common stock on the grant date of the award, which is expensed over the applicable vesting period. The Company values its stock options using a Black-Scholes option valuation model.
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
In addition to the Equity Plan, Viper and Rattler maintain their own long-term incentive plans which are not significant to the Company.
The following table presents the financial statement impacts of the equity compensation plans and related costs:
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended March 31, | |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | |
| | (In millions) | | (In millions) |
| General and administrative expenses | General and administrative expenses | $ | 14 | | | $ | 9 | | | $ | 37 | | | $ | 27 | | General and administrative expenses | $ | 15 | | | $ | 10 | | |
| Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties | Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties | $ | 5 | | | $ | 4 | | | $ | 14 | | | $ | 12 | | Equity-based compensation capitalized pursuant to full cost method of accounting for oil and natural gas properties | $ | 4 | | | $ | 4 | | |
|
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
Restricted Stock Units
The following table presents the Company’s restricted stock unit activity during the ninethree months ended September 30, 2021March 31, 2022 under the Equity Plan and the QEP equity incentive plan assumed by the Company in the QEP Merger:Plan:
| | | | | | | | | | | |
| Restricted Stock
Units | | Weighted Average Grant-Date
Fair Value |
| Unvested at December 31, 2020 | 1,113,480 | | | $ | 48.58 | |
Granted(1) | 655,634 | | | $ | 80.06 | |
| Vested | (323,459) | | | $ | 77.21 | |
| Forfeited | (67,450) | | | $ | 50.23 | |
| Unvested at September 30, 2021 | 1,378,205 | | | $ | 56.76 | |
(1) Includes 164,088 replacement restricted stock unit awards granted in connection with the QEP Merger, the majority of which vested upon closing of the QEP Merger. For additional information regarding the QEP Merger, see Note 4—Acquisitions and Divestitures. | | | | | | | | | | | |
| Restricted Stock
Units | | Weighted Average Grant-Date
Fair Value |
| Unvested at December 31, 2021 | 1,079,589 | | | $ | 62.09 | |
| Granted | 309,535 | | | $ | 131.72 | |
| Vested | (157,534) | | | $ | 87.10 | |
| Forfeited | (15,041) | | | $ | 62.98 | |
| Unvested at March 31, 2022 | 1,216,549 | | | $ | 75.71 | |
The aggregate fair value of restricted stock units that vested during the ninethree months ended September 30, 2021March 31, 2022 was $25$14 million. As of September 30, 2021,March 31, 2022, the Company’s unrecognized compensation cost related to unvested restricted stock units was $53$81 million, which is expected to be recognized over a weighted-average period of 2.02.2 years.
Performance Based Restricted Stock Units
The following table presents the Company’s performance restricted stock units activity under the Equity Plan for the ninethree months ended September 30, 2021:March 31, 2022:
| | | | | | | | | | | |
| Performance Restricted Stock Units | | Weighted Average Grant-Date Fair Value |
| Unvested at December 31, 2020 | 411,587 | | | $ | 99.10 | |
| Granted | 198,454 | | | $ | 131.06 | |
| | | |
| | | |
Unvested at September 30, 2021(1) | 610,041 | | | $ | 109.49 | |
| | | | | | | | | | | |
| Performance Restricted Stock Units | | Weighted Average Grant-Date Fair Value |
| Unvested at December 31, 2021 | 456,459 | | | $ | 100.17 | |
| Granted | 126,905 | | | $ | 237.13 | |
| | | |
| | | |
Unvested at March 31, 2022(1) | 583,364 | | | $ | 129.96 | |
(1)A maximum of 1,431,8331,408,973 units could be awarded based upon the Company’s final TSR ranking.
As of September 30, 2021,March 31, 2022, the Company’s unrecognized compensation cost related to unvested performance based restricted stock awards and units was $32$52 million, which is expected to be recognized over a weighted-average period of 1.71.9 years.
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
In March 2021,2022, eligible employees received performance restricted stock unit awards totaling 198,454126,905 units from which a minimum of 0% and a maximum of 200% of the units could be awarded based upon the measurement of total stockholder return of the Company’s common stock as compared to a designated peer group during the three-year3-year performance period of January 1, 20212022 to December 31, 20232024 and cliff vest at December 31, 20232024 subject to continued employment. The initial payout of the March 20212022 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 issuance 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 awards granted during the period presented:
| | | | | | | | | |
| 20212022 | | | | |
| Grant-date fair value | $ | 131.06237.13 | | | | | |
| | | | | |
| Risk-free rate | 0.151.44 | % | | | | |
| Company volatility | 69.6072.10 | % | | | | |
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
10. INCOME TAXES
The Company’s effective income tax rates were 22.3%21.6% and 21.6%22.6% for the three months ended September 30,March 31, 2022 and 2021, and 2020, respectively, and 22.3% and 18.7% for the nine months ended September 30, 2021 and 2020, respectively. Total income tax expense from continuing operations for the three and nine months ended September 30,March 31, 2022 and 2021 differed from amounts computed by applying the United States federal statutory tax rate to pre-tax income primarily due to (i) state income taxes, net of federal benefit, and (ii) the impact of permanent differences between book and taxable income, partially offset by (iii) tax benefit resulting from a reduction in the valuation allowance on Viper’s deferred tax assets due to pre-tax income for the period. As of March 31, 2022 and 2021, Viper maintained a valuation allowance against its deferred tax assets, based on its assessment of all available evidence, both positive and negative, supporting realizability of Viper’s deferred tax assets.
For the ninethree months ended September 30,March 31, 2022 and 2021, the Company’s items of discrete income tax expense or benefit were not material.
On March 17, 2021, the Company completed its acquisition of QEP. For federal income tax purposes, the transaction qualified as a nontaxable merger whereby the Company acquired carryover tax basis in QEP’s assets and liabilities. As of September 30, 2021,March 31, 2022, the Company’s opening balance sheet net deferred tax asset was $17$39 million, primarily consisting of deferred tax assets related to tax attributes acquired from QEP, partially offset by a valuation allowance, and deferred tax liabilities resulting from the excess of financial reporting carrying value over tax basis of oil and natural gas properties and other assets acquired from QEP. The acquired income tax attributes, including federal net operating loss and credit carryforwards, are subject to an annual limitation under Internal Revenue Code Section 382. The Company has considered the positive and negative evidence regarding realizability of these federal tax attributes including taxable income in prior carryback years, the annual limitation imposed by Section 382, and the anticipated timing of reversal of its deferred tax liabilities, resulting in a valuation allowance on the portion of QEP’s federal tax attributes estimated not more likely than not to be realized prior to expiration. In addition, acquired tax attributes include state net operating loss carryforwards for which a valuation allowance has been provided, since the Company does not believe the state net operating losses are more likely than not to be realized based on its assessment of anticipated future operations in those states.
Total income tax expense from continuing operations for the three and 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 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 consisted primarily of its investment in Viper LLC and federal net operating loss carryforwards. As of September 30, 2021 and 2020, Viper maintained a valuation allowance against its deferred tax assets, based on its assessment of all available evidence, both positive and negative, supporting realizability of Viper’s deferred tax assets. In addition, for the nine months ended
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
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%.
The Company considered the impact of the American Rescue Plan, enacted on March 11, 2021, and concluded its provisions related to U.S. income taxes for corporations did not materially affect the Company’s current or deferred tax balances. The Company also considered the impact of the CARES Act, enacted March 27, 2020, in the period of enactment, resulting in a net discrete income tax benefit of $25 million for the three months ended March 31, 2020 related to the carryback of approximately $179 million of the Company’s federal net operating losses as noted above. As a result of the refund associated with such carryback as well as the accelerated refund available for minimum tax credits, the Company received a refund of federal taxes in the first quarter of 2021 of approximately $100 million. In addition, the Company received in the third quarter of 2021 a refund of federal taxes of approximately $50 million related to refundable minimum tax credits resulting from carryback of certain federal net operating losses acquired from QEP.
11. DERIVATIVES
At September 30, 2021,March 31, 2022, the Company has commodity derivative contracts and receive-fixed, pay-variable interest rate hedges outstanding. All derivative financial instruments are recorded at fair value.
Commodity Contracts
The Company has entered into multiple crude oil natural gas and natural gas liquids derivatives, indexed to the respective indices as noted in the table below, to reduce price volatility associated with certain of its oil and natural gas sales. The Company has not designated its commodity derivative instruments as hedges for accounting purposes and, as a result, marks its commodity derivative instruments to fair value and recognizes the cash and non-cash changes in fair value in the condensed consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.”
By using derivative instruments to economically hedge exposure to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company’s counterparties are participants in the secured second amended and restated credit agreement, which is secured by substantially all of the assets of the guarantor subsidiaries; therefore, the Company is not required to post any collateral. The Company does not require collateral from its counterparties. The Company has entered into commodity derivative instruments only with counterparties that are also lenders under its credit facility and have been deemed an acceptable credit risk. As such, the Company does not require collateral from its counterparties.
The Company has multiplehad certain commodity derivative contracts that containcontained an other-than-insignificant financing element at inception during 2021 and, therefore, the cash receipts were classified as cash flows from financing activities in the condensed consolidated statements of cash flow for the three and nine months ended September 30,March 31, 2021.
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
As of September 30, 2021,March 31, 2022, the Company had the following outstanding commodity derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.
| | | Swaps | | Collars | | Swaps | | Collars |
| Settlement Month | Settlement Month | Settlement Year | Type of Contract | Bbls/MMBtu Per Day | Index | Weighted Average Differential | Weighted Average Fixed Price | | Weighted Average Floor Price | Weighted Average Ceiling Price | Settlement Month | Settlement Year | Type of Contract | Bbls/MMBtu Per Day | Index | Weighted Average Differential | Weighted Average Fixed Price | | Weighted Average Floor Price | Weighted Average Ceiling Price |
| OIL | OIL | | | | OIL | | | |
| Oct. - Dec. | 2021 | Swap | 30,674 | WTI | $— | $42.36 | | $— | |
| Oct. - Dec. | 2021 | Swap | 5,000 | Argus WTI Houston | $— | $37.78 | | $— | |
| Oct. - Dec. | 2021 | Swap(1) | 5,000 | Brent | $— | $41.62 | | $— | |
| Oct. - Dec. | 2021 | Basis Swap(2) | 34,000 | Argus WTI Midland | $0.91 | $— | | $— | |
| Oct. - Dec. | 2021 | Roll Swap(3)(4) | 64,000 | WTI | $0.56 | $— | | $— | |
| Oct. - Dec. | 2021 | Costless Collar | 29,663 | WTI | $— | | $39.83 | $56.45 | |
| Oct. - Dec. | 2021 | Costless Collar | 5,000 | Argus WTI Houston | $— | | $45.00 | $78.75 | |
| Oct. - Dec. | 2021 | Costless Collar(5) | 54,000 | Brent | $— | | $41.04 | $52.86 | |
| Jan. - June | 2022 | Swap | 1,000 | WTI | $— | $45.00 | | $— | |
| Jan. - Dec. | 2022 | Basis Swap(2) | 10,000 | Argus WTI Midland | $0.84 | $— | | $— | |
| Jan. - Dec. | 2022 | Roll Swap(3) | 25,000 | WTI | $0.56 | $— | | $— | |
| Jan. - Mar. | 2022 | Costless Collar | 19,500 | WTI | $— | | $46.28 | $72.67 | |
| Jan. - Mar. | 2022 | Costless Collar | 55,000 | Brent | $— | | $45.55 | $71.08 | |
| Jan. - Mar. | 2022 | Costless Collar | 22,000 | Argus WTI Houston | $— | | $45.91 | $70.95 | |
| Apr. - June | | Apr. - June | 2022 | Swap | 1,000 | WTI | $— | $45.00 | | $— |
| Apr. - June | | Apr. - June | 2022 | Swap | 13,900 | Brent | $— | $67.54 | | $— |
| Apr. - June | | Apr. - June | 2022 | Basis Swap(1) | 17,000 | Argus WTI Midland | $0.66 | $— | | $— |
| July - Dec. | | July - Dec. | 2022 | Basis Swap(1) | 10,000 | Argus WTI Midland | $0.84 | $— | | $— |
| Apr. - Dec. | | Apr. - Dec. | 2022 | Roll Swap | 55,000 | WTI | $0.89 | $— | | $— |
| Apr. - June | Apr. - June | 2022 | Costless Collar | 13,000 | WTI | $— | | $46.92 | $75.00 | Apr. - June | 2022 | Costless Collar | 5,000 | WTI | $— | | $50.00 | $80.44 |
| Apr. - June | Apr. - June | 2022 | Costless Collar | 34,000 | Brent | $— | | $46.47 | $77.00 | Apr. - June | 2022 | Costless Collar | 24,000 | Brent | $— | | $46.67 | $77.49 |
| Apr. - June | Apr. - June | 2022 | Costless Collar | 26,000 | Argus WTI Houston | $— | | $46.92 | $72.78 | Apr. - June | 2022 | Costless Collar | 20,000 | Argus WTI Houston | $— | | $47.50 | $75.25 |
| July - Sep. | July - Sep. | 2022 | Costless Collar | 11,000 | Brent | $— | | $47.73 | $78.65 | July - Sep. | 2022 | Costless Collar | 4,000 | WTI | $— | | $45.00 | $92.65 |
| July - Sep. | July - Sep. | 2022 | Costless Collar | 10,000 | Argus WTI Houston | $— | | $50.00 | $76.66 | July - Sep. | 2022 | Costless Collar | 19,000 | Brent | $— | | $53.95 | $98.59 |
| July - Sep. | | July - Sep. | 2022 | Costless Collar | 11,000 | Argus WTI Houston | $— | | $50.00 | $89.28 |
| Oct. - Dec. | Oct. - Dec. | 2022 | Costless Collar | 5,000 | Brent | $— | | $45.00 | $75.56 | Oct. - Dec. | 2022 | Costless Collar | 4,000 | WTI | $— | | $50.00 | $128.01 |
| Oct. - Dec. | | Oct. - Dec. | 2022 | Costless Collar | 15,000 | Brent | $— | | $55.00 | $103.06 |
| Oct. - Dec. | | Oct. - Dec. | 2022 | Costless Collar | 7,000 | Argus WTI Houston | $— | | $50.00 | $95.55 |
| Jan. - June | | Jan. - June | 2023 | Costless Collar | 6,000 | Brent | $— | | $60.00 | $114.57 |
| | | NATURAL GAS | NATURAL GAS | | | | NATURAL GAS | | | |
| Oct. - Dec. | 2021 | Swap | 245,000 | Henry Hub | $— | $2.65 | | $— | |
| Oct. - Dec. | 2021 | Swap | 50,000 | Waha Hub | $— | $1.92 | | $— | |
| Oct. - Dec. | 2021 | Basis Swap(2) | 250,000 | Waha Hub | $(0.66) | $— | | $— | |
| Jan. - Dec. | 2022 | Basis Swap(2) | 210,000 | Waha Hub | $(0.34) | $— | | $— | |
| Apr. - June | | Apr. - June | 2022 | Basis Swap(1) | 230,000 | Waha Hub | $(0.36) | $— | | $— |
| Apr. - June | | Apr. - June | 2022 | Costless Collar | 390,000 | Henry Hub | $— | | $2.65 | $5.20 |
| July - Dec. | | July - Dec. | 2022 | Basis Swap(1) | 330,000 | Waha Hub | $(0.68) | $— | | $— |
| July - Dec. | | July - Dec. | 2022 | Costless Collar | 380,000 | Henry Hub | $— | | $2.79 | $6.24 |
| Jan. - June | Jan. - June | 2022 | Costless Collar | 350,000 | Henry Hub | $— | | $2.65 | $4.68 | Jan. - June | 2023 | Basis Swap(1) | 270,000 | Waha Hub | $(1.12) | $— | | $— |
| Jan. - Mar. | | Jan. - Mar. | 2023 | Costless Collar | 270,000 | Henry Hub | $— | | $2.95 | $7.59 |
| Apr. - June | | Apr. - June | 2023 | Costless Collar | 230,000 | Henry Hub | $— | | $2.96 | $7.07 |
| July - Dec. | July - Dec. | 2022 | Costless Collar | 240,000 | Henry Hub | $— | | $2.67 | $5.00 | July - Dec. | 2023 | Basis Swap(1) | 250,000 | Waha Hub | $(1.17) | $— | | $— |
| Jan. - Dec. | 2023 | Costless Collar | 60,000 | Henry Hub | $— | | $2.75 | $5.72 | |
| NATURAL GAS LIQUIDS | | | | |
| Oct. - Dec. | 2021 | Swap | 2,000 | Mont Belvieu Propane | $— | $29.40 | | $— | |
| July - Dec. | | July - Dec. | 2023 | Costless Collar | 210,000 | Henry Hub | $— | | $2.96 | $7.01 |
| | |
(1) Excludes swaptions for 13,900 BO/d for first half of 2022, and 8,250 BO/d for second half 2022, whereby the counterparty has the right to exercise the hedge at a weighted-average price of $67.54/Bbl in the first half of 2022 and $68.62/Bbl in the second half of 2022.
(2) The Company has fixed price basis swaps for the spread between the Cushing crude oil price and the Midland WTI crude oil price as well as the spread between the Henry Hub natural gas price and the Waha Hub natural gas price. The weighted average differential represents the amount of reduction to the Cushing, Oklahoma oil price and the Waha Hub natural gas price for the notional volumes covered by the basis swap contracts.
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
(3) | | | | | | | | | | | | | | | | | | | | | | | |
| Settlement Month | Settlement Year | Type of Contract | Bbls Per Day | Index | Strike Price | Weighted Average Differential | Deferred Premium |
| OIL | | | | | | | |
| Apr. - June | 2022 | Put | 10,000 | WTI | $47.50 | $— | $1.49 |
| Apr. - June | 2022 | Put | 24,000 | Brent | $50.00 | $— | $1.80 |
| Apr. - June | 2022 | Put | 8,000 | Argus WTI Houston | $50.00 | $— | $1.87 |
| July - Sep. | 2022 | Put | 8,000 | WTI | $47.50 | $— | $1.52 |
| July - Sep. | 2022 | Put | 36,000 | Brent | $50.00 | $— | $1.83 |
| July - Sep. | 2022 | Put | 12,000 | Argus WTI Houston | $50.00 | $— | $1.89 |
| Oct. - Dec. | 2022 | Put | 32,000 | Brent | $50.00 | $— | $1.83 |
| Oct. - Dec. | 2022 | Put | 10,000 | Argus WTI Houston | $50.00 | $— | $1.85 |
| Apr. - Dec. | 2022 | Basis Put(1) | 50,000 | Brent | $— | $(10.40) | $0.78 |
| | | | | |
| | | | | | | |
| | | | | | | |
(1) The Company has rolling hedge basis swapsputs for the differential in NYMEX pricesspread between the calendar month average and the physicalBrent crude oil delivery month. The weighted average differential represents the amount of reduction to Cushing, Oklahomaprice and NYMEX WTI crude oil price for the notional volumes covered by the rolling hedge basis swap contracts.
(4) Includes a rolling hedge basis swap contract for the differential between the NYMEX prices for WTI Cushing and WTI CMA calendar month average of each basis for a notional quantity of 4,000 barrels per day with a weighted average differential of $0.00.
(5) Excludes approximately $4.8 million of deferred premiums from restructuring 5,000 BO/d of Q4 2021 hedges.price.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Settlement Month | Settlement Year | Type of Contract | Bbls Per Day | Index | Strike Price | Deferred Premium | | | | | |
| OIL | | | | | | | | | | | |
| Jan. - Mar. | 2022 | Put | 9,500 | WTI | $47.51 | $1.57 | | | | | |
| Jan. - Mar. | 2022 | Put | 8,000 | Brent | $50.00 | $1.70 | | | | | |
| Jan. - Sep. | 2022 | Put | 2,000 | Argus WTI Houston | $50.00 | $2.06 | | | | | |
| Apr. - June | 2022 | Put | 8,000 | WTI | $47.50 | $1.55 | | | | | |
| Apr. - June | 2022 | Put | 10,000 | Brent | $50.00 | $1.76 | | | | | |
| July - Sep. | 2022 | Put | 6,000 | Brent | $50.00 | $1.87 | | | | | |
| Oct. - Dec. | 2022 | Put | 2,000 | Brent | $50.00 | $1.89 | | | | | |
| | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Swaps | | Collars |
| Settlement Month | Settlement Year | Type of Contract | Bbls Per Day | Index | | Weighted Average Fixed Price | | Weighted Average Floor Price | Weighted Average Ceiling Price |
| OIL | | | | | | | | | |
| Apr. - June | 2022 | Costless Collar | 8,000 | WTI | | $— | | $45.00 | $71.60 |
| Apr. - June | 2022 | Costless Collar | 8,000 | Brent | | $— | | $45.00 | $74.78 |
| Apr. - June | 2022 | Costless Collar | 6,000 | Argus WTI Houston | | $— | | $45.00 | $69.53 |
| Apr. - Sep. | 2022 | Costless Collar | 2,000 | Brent | | $— | | $50.00 | $80.00 |
| Apr. - Sep. | 2022 | Costless Collar | 2,000 | Argus WTI Houston | | $— | | $50.00 | $76.70 |
| July - Sep. | 2022 | Costless Collar | 4,000 | Argus WTI Houston | | $— | | $50.00 | $75.00 |
| July - Dec. | 2022 | Swaption | 8,250 | Brent | | $68.62 | | $— | $— |
Interest Rate Swaps
In the second quarter of 2021, the Company entered into 2 interest rate swap agreements for notional amounts of $600 million each to limit the Company’s exposure to changes in the fair value of debt due to movements in LIBOR interest rates. These interest rate swaps have been designated as fair value hedges of the Company’s $1.2 billion 3.50% fixed rate senior notes due 2029 (the “2029 Notes”) whereby the Company will receive the fixed rate of interest and will pay an average variable rate of interest based on three month LIBOR plus 2.1865%. Gains and losses due to changes in the fair value of the interest rate swaps completely offset changes in the fair value of the hedged portion of the underlying debt and were not materialtotaled $90 million for the three and nine months ended September 30, 2021. These interest rate swaps are assumed to be perfectly effective and were determined to qualify for the “shortcut” method of accounting. The swaps expire on December 1, 2029, with an alternative early termination date of September 1, 2029, which mirrors the call optionMarch 31, 2022, as discussed further in the 2029 Notes.Note 7—Debt.
During 2020 and the first quarter of 2021, the Company used interest rate swaps to reduce its exposure to variable rate interest payments associated with the Company’s revolving credit facility. These interest rate swaps were not designated as hedging instruments and as a result, the Company recognized all changes in fair value immediately in earnings. During the first quarter of 2021, the Company terminated all of its previously outstanding interest rate swaps which resulted in cash received upon settlement of $80 million, net of fees, during the ninethree months ended September 30,March 31, 2021. The interest swaps contained an other-than-insignificant financing element at inception, and therefore, the cash receipts were classified as cash flows from financing activities in the condensed consolidated statements of cash flow for the ninethree months ended September 30, 2021.March 31, 2022.
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
Balance Sheet Offsetting of Derivative Assets and Liabilities
The fair value of derivative instruments is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions, including any deferred premiums that are with the same counterparty and are subject to contractual terms which provide for net settlement. See Note 12—Fair Value Measurements for further details.
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
Gains and Losses on Derivative Instruments
The following table summarizes the gains and losses on derivative instruments not designated as hedging instruments included in the condensed consolidated statements of operations:
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended March 31, | |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | |
| | (In millions) | | (In millions) |
| Gain (loss) on derivative instruments, net: | Gain (loss) on derivative instruments, net: | | Gain (loss) on derivative instruments, net: | | |
| Commodity contracts | Commodity contracts | $ | (234) | | | $ | (104) | | | $ | (1,025) | | | $ | 147 | | Commodity contracts | $ | (552) | | | $ | (294) | | |
| Interest rate swaps | Interest rate swaps | — | | | 5 | | | 130 | | | (65) | | Interest rate swaps | — | | | 130 | | |
| Total | Total | $ | (234) | | | $ | (99) | | | $ | (895) | | | $ | 82 | | Total | $ | (552) | | | $ | (164) | | |
| | Net cash received (paid) on settlements: | Net cash received (paid) on settlements: | | Net cash received (paid) on settlements: | | |
Commodity contracts(2)(1) | Commodity contracts(2)(1) | $ | (397) | | | $ | (9) | | | $ | (902) | | | $ | 288 | | Commodity contracts(2)(1) | $ | (420) | | | $ | (182) | | |
Interest rate swaps(3)(2) | Interest rate swaps(3)(2) | — | | | — | | | 80 | | | — | | Interest rate swaps(3)(2) | — | | | 80 | | |
| Total | Total | $ | (397) | | | $ | (9) | | | $ | (822) | | | $ | 288 | | Total | $ | (420) | | | $ | (102) | | |
(1)The three and nine months ended September 30, 2021 includeMarch 31, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $16$135 million.
(2)The three and nine months ended September 30, 2020 include cash received on commodity contracts terminated prior to their contractual maturity of $6 million and $17 million, respectively.
(3)The nine months ended September 30,March 31, 2021 includeincludes cash received on interest rate swap contracts terminated prior to their contractual maturity of $80 million.
12. 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.
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
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,
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
engineering and geological studies, historical well performance, and applicable mineral lease terms. Given the unobservable nature of the inputs, the estimated fair values of oil and natural gas properties assumed is deemed to use Level 3 inputs.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Certain assets and liabilities are reported at fair value on a recurring basis, including the Company’s commodity derivative instruments and interest rate swaps. The fair values of the Company’s commodity derivative contracts are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. Interest rate swaps designated as fair value hedges and those that are not designated as hedges are determined based on inputs that are readily available in public markets, can be derived from information available in publicly quoted markets, or are provided by financial institutions that trade these contracts. These valuations are Level 2 inputs. The fair value of interest rate swaps is recorded as an asset or liability on the condensed consolidated balance sheet and the net change in fair value of the Company’s interest rate swaps designated as hedges are includedoffset by change in value of the hedged item, long-term debt, inwithin the condensed consolidated balance sheet.sheet..
The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties, and (iv) the resulting net amounts presented in the Company’s condensed consolidated balance sheets as of September 30, 2021March 31, 2022 and December 31, 20202021. The net amounts of derivative instruments are classified as current or noncurrent based on their anticipated settlement dates.
| | | As of September 30, 2021 | | As of March 31, 2022 |
| | Level 1 | Level 2 | Level 3 | Total Gross Fair Value | Gross Amounts Offset in Balance Sheet | Net Fair Value Presented in Balance Sheet | | Level 1 | Level 2 | Level 3 | Total Gross Fair Value | Gross Amounts Offset in Balance Sheet | Net Fair Value Presented in Balance Sheet |
| | (In millions) | | (In millions) |
| Assets: | Assets: | | Assets: | |
| Current: | Current: | | Current: | |
| | Derivative instruments | Derivative instruments | $ | — | | $ | 94 | | $ | — | | $ | 94 | | $ | (94) | | $ | — | | Derivative instruments | $ | — | | $ | 83 | | $ | — | | $ | 83 | | $ | (80) | | $ | 3 | |
| Interest rate swaps designated as hedges | Interest rate swaps designated as hedges | $ | — | | $ | 14 | | $ | — | | $ | 14 | | $ | — | | $ | 14 | | Interest rate swaps designated as hedges | $ | — | | $ | 6 | | $ | — | | $ | 6 | | $ | (3) | | $ | 3 | |
| Non-current: | Non-current: | | Non-current: | |
| | Derivative instruments | Derivative instruments | $ | — | | $ | 16 | | $ | — | | $ | 16 | | $ | (12) | | $ | 4 | | Derivative instruments | $ | — | | $ | 56 | | $ | — | | $ | 56 | | $ | (19) | | $ | 37 | |
| Interest rate swaps designated as hedges | Interest rate swaps designated as hedges | $ | — | | $ | 13 | | $ | — | | $ | 13 | | $ | (13) | | $ | — | | Interest rate swaps designated as hedges | $ | — | | $ | — | | $ | — | | $ | — | | $ | — | | $ | — | |
| Liabilities: | Liabilities: | | Liabilities: | |
| Current: | Current: | | Current: | |
| Derivative instruments | Derivative instruments | $ | — | | $ | 704 | | $ | — | | $ | 704 | | $ | (94) | | $ | 610 | | Derivative instruments | $ | — | | $ | 419 | | $ | — | | $ | 419 | | $ | (80) | | $ | 339 | |
| | Interest rate swaps designated as hedges | | Interest rate swaps designated as hedges | $ | — | | $ | 3 | | $ | — | | $ | 3 | | $ | (3) | | $ | — | |
| Non-current: | Non-current: | | Non-current: | |
| Derivative instruments | Derivative instruments | $ | — | | $ | 24 | | $ | — | | $ | 24 | | $ | (12) | | $ | 12 | | Derivative instruments | $ | — | | $ | 20 | | $ | — | | $ | 20 | | $ | (19) | | $ | 1 | |
| Interest rate swaps designated as hedges | Interest rate swaps designated as hedges | $ | — | | $ | 37 | | $ | — | | $ | 37 | | $ | (13) | | $ | 24 | | Interest rate swaps designated as hedges | $ | — | | $ | 93 | | $ | — | | $ | 93 | | $ | — | | $ | 93 | |
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
| | | As of December 31, 2020 | | As of December 31, 2021 |
| | Level 1 | Level 2 | Level 3 | Total Gross Fair Value | Gross Amounts Offset in Balance Sheet | Net Fair Value Presented in Balance Sheet | | Level 1 | Level 2 | Level 3 | Total Gross Fair Value | Gross Amounts Offset in Balance Sheet | Net Fair Value Presented in Balance Sheet |
| | (In millions) | | (In millions) |
| Assets: | Assets: | | Assets: | |
| Current: | Current: | | Current: | |
| | Derivative instruments | Derivative instruments | $ | — | | $ | 43 | | $ | — | | $ | 43 | | $ | (42) | | $ | 1 | | Derivative instruments | $ | — | | $ | 60 | | $ | — | | $ | 60 | | $ | (57) | | $ | 3 | |
| | Interest rate swaps designated as hedges | | Interest rate swaps designated as hedges | $ | — | | $ | 10 | | $ | — | | $ | 10 | | $ | — | | $ | 10 | |
| Non-current: | Non-current: | | Non-current: | |
| | Derivative instruments | Derivative instruments | $ | — | | $ | 187 | | $ | — | | $ | 187 | | $ | (187) | | $ | — | | Derivative instruments | $ | — | | $ | 12 | | $ | — | | $ | 12 | | $ | (8) | | $ | 4 | |
| | Interest rate swaps designated as hedges | | Interest rate swaps designated as hedges | $ | — | | $ | 1 | | $ | — | | $ | 1 | | $ | (1) | | $ | — | |
| Liabilities: | Liabilities: | | Liabilities: | |
| Current: | Current: | | Current: | |
| Derivative instruments | Derivative instruments | $ | — | | $ | 291 | | $ | — | | $ | 291 | | $ | (42) | | $ | 249 | | Derivative instruments | $ | — | | $ | 231 | | $ | — | | $ | 231 | | $ | (57) | | $ | 174 | |
| | Non-current: | Non-current: | | Non-current: | |
| Derivative instruments | Derivative instruments | $ | — | | $ | 244 | | $ | — | | $ | 244 | | $ | (187) | | $ | 57 | | Derivative instruments | $ | — | | $ | 9 | | $ | — | | $ | 9 | | $ | (8) | | $ | 1 | |
| | Interest rate swaps designated as hedges | | Interest rate swaps designated as hedges | $ | — | | $ | 29 | | $ | — | | $ | 29 | | $ | (1) | | $ | 28 | |
Assets and Liabilities Not Recorded at Fair Value
The following table provides the fair value of financial instruments that are not recorded at fair value in the condensed consolidated balance sheets:
| | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2021 | | December 31, 2020 |
| Carrying | | | | Carrying | | |
| Value | | Fair Value | | Value | | Fair Value |
| (In millions) |
| Debt | $ | 6,945 | | | $ | 7,448 | | | $ | 5,815 | | | $ | 6,213 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| March 31, 2022 | | December 31, 2021 |
| Carrying | | | | Carrying | | |
| Value | | Fair Value | | Value | | Fair Value |
| (In millions) |
| Debt | $ | 5,848 | | | $ | 5,966 | | | $ | 6,687 | | | $ | 7,148 | |
The fair values of the Company’s credit agreement, the Viper credit agreement and the Rattler credit agreement approximate their carrying values based on borrowing rates available to the Company for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair values of the outstanding notes were determined using the September 30, 2021 quoted market price at each period end, a Level 1 classification in the fair value hierarchy.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities are measured at fair value on a nonrecurring basis in certain circumstances. These assets and liabilities can include those acquired in a business combination, inventory, proved and unproved oil and gas properties and other long-lived assets that are written down to fair value when they are impaired or held for sale. Refer to Note 4—Acquisitions and Divestitures and Note 5—Property and Equipment for additional discussion of nonrecurring fair value adjustments.
Fair Value of Financial Assets
The carrying amount of cash and cash equivalents, receivables, funds held in escrow, prepaid expenses and other current assets, payables and other accrued liabilities approximate their fair value because of the short-term nature of the instruments.
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
13. SUPPLEMENTAL INFORMATION TO STATEMENTS OF CASH FLOWS
| | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| 2022 | | 2021 | | | | |
| (In millions) |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| Supplemental disclosure of non-cash transactions: | | | | | | | |
| Accrued capital expenditures included in accounts payable and accrued expenses | $ | 293 | | | $ | 252 | | | | | |
| | | | | | | |
| Common stock issued for business combinations | $ | — | | | $ | 1,727 | | | | | |
| | | | | | | |
14. 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 crude oil and natural gas industry, personal injury claims, title disputes, royalty disputes, contract claims, contamination claims relating to oil and natural gas exploration and development and environmental claims, including claims involving assets previously sold to third parties and no longer part of the Company’s current operations. While the ultimate outcome of the pending proceedings,
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
disputes or claims, and any resulting impact on the Company, cannot be predicted with certainty, the Company’s management believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Company’s financial condition, results of operations or cash flows. The Company’s assessment is based on information known about the pending matters and its experience in contesting, litigating and settling similar matters. Actual outcomes could differ materially from the Company’s assessment. The Company records reserves for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.
The Company acquired certain contractual obligations in conjunction with the QEP Merger including an aggregate of approximately $68 million in various transportation, gathering and purchase commitments.
14.15. SUBSEQUENT EVENTS
ThirdFirst Quarter 20212022 Dividend Declaration
On October 28, 2021,April 27, 2022, the Board of Directors of the Company declared a cash dividend for the thirdfirst quarter of 20212022 of $0.50$3.05 per share of common stock, payable on November 18, 2021May 23, 2022 to its stockholders of record at the close of business on November 11, 2021.May 12, 2022. The dividend consists of a base quarterly dividend of $0.70 per share of common stock and a variable quarterly dividend of $2.35 per share of common stock. Future base and variable dividends are at the discretion of the Board of Directors of the Company.
On October 19, 2021, Diamondback entered into a purchase and sale agreement with Rattler to sell certain water midstream assets to Rattler in exchange for cash proceeds of approximately $160 million, in a drop down transaction. The midstream assets consist primarily of produced water gathering and disposal systems, produced water recycling facilities, and sourced water gathering and storage assets acquired by the Company through the Guidon Acquisition and the QEP Merger with a carrying value of approximately $160 million. The drop down transaction will be accounted for as a transaction between entities under common control and is expected to close in the fourth quarter of 2021, subject to customary closing conditions.
Williston Basin Divestiture
On October 21, 2021, the Company completed the divestiture of its Williston Basin oil and natural gas assets, consisting of approximately 95,000 net acres, to Oasis Petroleum Inc., for net cash proceeds of approximately $586 million, after customary closing adjustments. This transaction did not result in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves and, accordingly, the Company recorded the proceeds as a reduction of its full cost pool with no gain or loss recognized on the sale.
Gas Gathering Assets Divestiture
On November 1, 2021, the Company completed the sale of certain gas gathering assets to Brazos Delaware Gas, LLC for proceeds of approximately $54 million, after customary closing adjustments.
Redemption of the 2023 Notes
On November 1, 2021, the Company redeemed all of its outstanding 2023 Notes in the aggregate principal amount of $650 million at a redemption price equal to 100% of the principal amount, plus accrued and unpaid interest on the 2023 Notes up to, but not including, the redemption date. The Company funded the redemption with proceeds received from the divestiture of its Williston Basin assets and cash on hand.
Viper’s Swallowtail Acquisition
On October 1, 2021, Viper acquired certain mineral and royalty interests from Swallowtail Royalties LLC and Swallowtail Royalties II LLC (the “Swallowtail entities”) pursuant to a definitive purchase and sale agreement for 15.25 million of Viper’s common units and approximately $225 million in cash (the “Swallowtail Acquisition”). The mineral and royalty interests acquired in the Swallowtail Acquisition represent approximately 2,313 net royalty acres primarily in the Northern Midland Basin, of which approximately 62% are operated by Diamondback. The Swallowtail Acquisition has an effective date of August 1, 2021. In accordance with the terms of the purchase agreement, the Company deposited $30 million into an escrow account in August 2021, which was released to Swallowtail upon the closing of the transaction. The cash portion of this
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
transaction was funded through a combination of cash on hand and approximately $190 million of borrowings under Viper LLC’s revolving credit facility.
Rattler’s Remuda Joint Venture Acquisition
On October 5, 2021, Rattler and a private affiliate of an investment fund formed a joint venture entity, Remuda Midstream Holdings LLC (the “Remuda joint venture”). Rattler contributed approximately $104 million in cash for a 25% membership interest in the Remuda joint venture, which then completed the acquisition of a majority interest in WTG Midstream LLC (“WTG Midstream”) from West Texas Gas, Inc. and its affiliates. WTG Midstream’s assets primarily consist of an interconnected gas gathering system and 6 major gas processing plants servicing the Midland Basin with 925 MMcf/d of total processing capacity with additional gas gathering and processing expansions planned.
Rattler’s Gas Gathering Divestiture
On November 1, 2021, Rattler completed the sale of its gas gathering assets to Brazos Delaware Gas, LLC for aggregate total gross potential consideration of $93 million, consisting of (i) $83 million due at closing, after customary closing adjustments, (ii) a $5 million contingent payment due in 2023 if the aggregate actual deliveries of gas volumes into the gas gathering system by and/or on behalf of the Company and its affiliates exceed certain specified thresholds during 2022, and (iii) a $5 million contingent payment due in 2024 if the aggregate actual deliveries of gas volumes into the gas gathering system by and/or on behalf of the Company and its affiliates exceed certain specified thresholds during 2022 and 2023. The contingent payments will be recorded if and when they become realizable.
15.16. SEGMENT INFORMATION
The Company reports its operations in 2 operating segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas and (ii) the midstream operations segment, which is focused on owning, operating, developing and acquiring midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. All of the Company’s equity method investments are included in the midstream operations segment.
The following tables summarize the results of the Company’s operating segments during the periods presented:
| | | Upstream | | Midstream Operations | | Eliminations | | Total | | Upstream | | Midstream Operations | | Eliminations | | Total |
| Three Months Ended September 30, 2021: | (In millions) | |
| | | (In millions) |
| Three Months Ended March 31, 2022: | | Three Months Ended March 31, 2022: | |
| Third-party revenues | Third-party revenues | $ | 1,896 | | | $ | 14 | | | $ | — | | | $ | 1,910 | | Third-party revenues | $ | 2,391 | | | $ | 17 | | | $ | — | | | $ | 2,408 | |
| Intersegment revenues | Intersegment revenues | — | | | 95 | | | (95) | | | — | | Intersegment revenues | — | | | 87 | | | (87) | | | — | |
| Total revenues | Total revenues | 1,896 | | | 109 | | | (95) | | | 1,910 | | Total revenues | 2,391 | | | 104 | | | (87) | | | 2,408 | |
| | Depreciation, depletion, amortization and accretion | Depreciation, depletion, amortization and accretion | 324 | | | 17 | | | — | | | 341 | | Depreciation, depletion, amortization and accretion | 292 | | | 21 | | | — | | | 313 | |
| | Income (loss) from operations | Income (loss) from operations | 1,126 | | | 54 | | | (16) | | | 1,164 | | Income (loss) from operations | 1,637 | | | 39 | | | (16) | | | 1,660 | |
| Interest expense, net | Interest expense, net | (50) | | | (7) | | | — | | | (57) | | Interest expense, net | (31) | | | (9) | | | — | | | (40) | |
| Other income (expense) | Other income (expense) | (243) | | | 4 | | | (1) | | | (240) | | Other income (expense) | (600) | | | 9 | | | (5) | | | (596) | |
| Provision for (benefit from) income taxes | Provision for (benefit from) income taxes | 190 | | | 3 | | | — | | | 193 | | Provision for (benefit from) income taxes | 219 | | | 2 | | | — | | | 221 | |
| Net income (loss) attributable to non-controlling interest | Net income (loss) attributable to non-controlling interest | 16 | | | 9 | | | — | | | 25 | | Net income (loss) attributable to non-controlling interest | 16 | | | 8 | | | — | | | 24 | |
| Net income (loss) attributable to Diamondback Energy, Inc. | Net income (loss) attributable to Diamondback Energy, Inc. | 627 | | | 39 | | | (17) | | | 649 | | Net income (loss) attributable to Diamondback Energy, Inc. | 771 | | | 29 | | | (21) | | | 779 | |
| As of September 30, 2021: | | |
| As of March 31, 2022: | | As of March 31, 2022: | |
| Total assets | Total assets | $ | 21,192 | | | $ | 1,806 | | | $ | (359) | | | $ | 22,639 | | Total assets | $ | 21,727 | | | $ | 1,996 | | | $ | (392) | | | $ | 23,331 | |
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | |
| Upstream | | Midstream Operations | | Eliminations | | Total |
| Three Months Ended September 30, 2020: | (In millions) |
| Third-party revenues | $ | 706 | | | $ | 14 | | | $ | — | | | $ | 720 | |
| Intersegment revenues | — | | | 83 | | | (83) | | | — | |
| Total revenues | 706 | | | 97 | | | (83) | | | 720 | |
| | | | | | | |
| Depreciation, depletion, amortization and accretion | 277 | | | 11 | | | — | | | 288 | |
| Impairment of oil and natural gas properties | 1,451 | | | — | | | — | | | 1,451 | |
| | | | | | | |
| Income (loss) from operations | (1,282) | | | 44 | | | (18) | | | (1,256) | |
| Interest expense, net | (47) | | | (6) | | | — | | | (53) | |
| Other income (expense) | (103) | | | 4 | | | (1) | | | (100) | |
| Provision for (benefit from) income taxes | (307) | | | 3 | | | — | | | (304) | |
| Net income (loss) attributable to non-controlling interest | (1) | | | 9 | | | — | | | 8 | |
| Net income (loss) attributable to Diamondback Energy, Inc. | (1,124) | | | 30 | | | (19) | | | (1,113) | |
| As of December 31, 2020: | | | | | | | |
| Total assets | $ | 16,128 | | | $ | 1,809 | | | $ | (318) | | | $ | 17,619 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Upstream | | Midstream Operations | | Eliminations | | Total |
| Nine Months Ended September 30, 2021: | (In millions) |
| Third-party revenues | $ | 4,737 | | | $ | 38 | | | $ | — | | | $ | 4,775 | |
| Intersegment revenues | — | | | 281 | | | (281) | | | — | |
| Total revenues | 4,737 | | | 319 | | | (281) | | | 4,775 | |
| | | | | | | |
| Depreciation, depletion, amortization and accretion | 911 | | | 44 | | | — | | | 955 | |
| | | | | | | |
| Impairment of midstream assets | — | | | 3 | | | — | | | 3 | |
| Income (loss) from operations | 2,605 | | | 131 | | | (46) | | | 2,690 | |
| Interest expense, net | (147) | | | (23) | | | — | | | (170) | |
| Other income (expense) | (967) | | | 29 | | | (5) | | | (943) | |
| Provision for (benefit from) income taxes | 344 | | | 8 | | | — | | | 352 | |
| Net income (loss) attributable to non-controlling interest | 18 | | | 27 | | | — | | | 45 | |
| Net income (loss) attributable to Diamondback Energy, Inc. | 1,129 | | | 102 | | | (51) | | | 1,180 | |
| As of September 30, 2021: | | | | | | | |
| Total assets | $ | 21,192 | | | $ | 1,806 | | | $ | (359) | | | $ | 22,639 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Upstream | | Midstream Operations | | Eliminations | | Total |
| (In millions) |
| Three Months Ended March 31, 2021: | |
| Third-party revenues | $ | 1,172 | | | $ | 12 | | | $ | — | | | $ | 1,184 | |
| Intersegment revenues | — | | | 87 | | | (87) | | | — | |
| Total revenues | 1,172 | | | 99 | | | (87) | | | 1,184 | |
| Depreciation, depletion, amortization and accretion | 262 | | | 11 | | | — | | | 273 | |
| | | | | | | |
| | | | | | | |
| Income (loss) from operations | 552 | | | 38 | | | (19) | | | 571 | |
| Interest expense, net | (49) | | | (7) | | | — | | | (56) | |
| Other income (expense) | (222) | | | (3) | | | (2) | | | (227) | |
| Provision for (benefit from) income taxes | 63 | | | 2 | | | — | | | 65 | |
| Net income (loss) attributable to non-controlling interest | (3) | | | 6 | | | — | | | 3 | |
| Net income (loss) attributable to Diamondback Energy, Inc. | 221 | | | 20 | | | (21) | | | 220 | |
| As of December 31, 2021: | | | | | | | |
| Total assets | $ | 21,329 | | | $ | 1,942 | | | $ | (373) | | | $ | 22,898 | |
Diamondback Energy, Inc. and Subsidiaries
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | |
| Upstream | | Midstream Operations | | Eliminations | | Total |
| Nine Months Ended September 30, 2020: | (In millions) |
| Third-party revenues | $ | 2,002 | | | $ | 42 | | | $ | — | | | $ | 2,044 | |
| Intersegment revenues | — | | | 273 | | | (273) | | | — | |
| Total revenues | 2,002 | | | 315 | | | (273) | | | 2,044 | |
| | | | | | | |
| Depreciation, depletion, amortization and accretion | 1,005 | | | 36 | | | — | | | 1,041 | |
| Impairment of oil and natural gas properties | 4,999 | | | — | | | — | | | 4,999 | |
| Income (loss) from operations | (4,787) | | | 134 | | | (77) | | | (4,730) | |
| Interest expense, net | (137) | | | (10) | | | — | | | (147) | |
| Other income (expense) | 73 | | | (10) | | | (4) | | | 59 | |
| Provision for (benefit from) income taxes | (910) | | | 8 | | | — | | | (902) | |
| Net income (loss) attributable to non-controlling interest | (163) | | | 25 | | | — | | | (138) | |
| Net income (loss) attributable to Diamondback Energy, Inc. | (3,778) | | | 81 | | | (81) | | | (3,778) | |
| As of December 31, 2020: | | | | | | | |
| Total assets | $ | 16,128 | | | $ | 1,809 | | | $ | (318) | | | $ | 17,619 | |
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and notes thereto presented in this report as well as our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2020.2021. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See “Part II. Item 1A. Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”
Overview
We operate in two operating segments: (i) the upstream segment, which is engaged in the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves primarily in the Permian Basin in West Texas and (ii) through our subsidiary, Rattler, the midstream operations segment, which is focused on ownership, operation, development and acquisition of midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin.
Guidon Acquisition and QEP MergerRecent Developments
On February 26, 2021, we completed the Guidon Acquisition, which included approximately 32,500 net acres in the Northern Midland Basin, in exchange for 10.68 million shares of the Company’s common stock and $375 million of cash.March 2022 Notes Offering
On March 17, 2021, we completed the acquisition of QEP pursuant to the Agreement and Plan of Merger, dated as of December 20, 2020, by and among Diamondback, certain of our subsidiaries and QEP. The addition of QEP’s assets increased our net acreage in the Midland Basin by approximately 49,000 net acres. Under the terms of the merger agreement,2022, we issued approximately 12.12the March 2022 Notes for an aggregate principal amount of $750 million sharesand received net proceeds of our common stock (valued at a price$739 million, after deducting debt issuance costs and discounts of $81.41 per share on the closing date) to the former QEP stockholders, with a total value of approximately $987 million.$11 million and underwriting discounts and offering expenses.
Recent Developments
Recent and Pending Acquisitions and Divestitures
On October 19, 2021, we entered into a purchase and sale agreement with Rattler to sell certain water midstream assets with a carrying value of approximately $160 million to Rattler in exchange for cash proceeds of approximately $160 million. The drop down transaction is expected to close in the fourth quarter of 2021, subject to customary closing conditions.
On October 21, 2021 we completed the divestiture of our Williston Basin oil and natural gas assets, consisting of approximately 95,000 net acres acquired in the QEP Merger, for net cash proceeds of approximately $586 million after customary closing adjustments.
On November 1, 2021, we completed the sale of certain gas gathering assets to Brazos Delaware Gas, LLC for proceeds of approximately $54 million, after customary closing adjustments.
On October 1, 2021, Viper completed the Swallowtail Acquisition, which included certain mineral and royalty interests for 15.25 million of Viper’s common units and approximately $225 million in cash. The cash portion of the purchase price was funded through a combination of cash on hand and approximately $190 million of borrowings under Viper LLC’s revolving credit facility.
On October 5, 2021, Rattler contributed approximately $104 million in cash for a 25% membership interest in the Remuda joint venture, which then completed the acquisition of a majority interest in WTG Midstream.
On November 1, 2021, Rattler completed the sale of its gas gathering assets to Brazos Delaware Gas, LLC for proceeds of approximately $83 million at closing, subject to customary closing adjustments, and an aggregate of $10 million in contingent payments.
Redemption of Notes
In August 2021, we redeemed the remaining $432 million in aggregate principal amount of our outstanding 5.375% 2025 Senior Notes with cash on hand and borrowings under our revolving credit facility.
On November 1, 2021,March 18, 2022, we redeemed the aggregate $650$500 million principal amount of our outstanding 20234.750% 2025 Senior Notes with a portion of the net proceeds from the March 2022 Notes offering.
On March 23, 2022, we redeemed the aggregate $1.0 billion principal amount of our outstanding 2.875% 2024 Senior Notes with the remaining net proceeds received from the divestiture of our Williston Basin assetsMarch 2022 Notes offering and cash on hand.
See Note 14—Subsequent EventsforFor additional discussion of our debt transactions completed induring the fourthfirst quarter of 2021.2022, see Note 7—Debt of the condensed notes to the consolidated financial statements included elsewhere in this report.
Stock and Unit Repurchase ProgramPrograms
In September 2021, our board of directors approved a stock repurchase program to acquire up to $2 billion of our outstanding common stock. This repurchase program is another component of our capital return program, which also includes our quarterly dividend. We anticipate 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 and may be suspended from time to time, modified, extended or discontinued by the board of directors at any time. During the three and nine months ended September 30, 2021,March 31, 2022, we repurchased approximately $22$7 million shares of ourDiamondback common stock, and as of September 30, 2021, $1.98March 31, 2022, $1.6 billion remained available for future purchases of common stock under our common stock repurchase program.
COVID-19During the three months ended March 31, 2022, Viper repurchased approximately $39 million of common units under its repurchase program. As of March 31, 2022, $41 million remained available for future purchases of common units under Viper’s common unit repurchase program. On April 27, 2022, Viper increased the authorization of its common unit repurchase program from $150 million to $250 million.
During the three months ended March 31, 2022, Rattler repurchased approximately $3 million of common units under its repurchase program. As of March 31, 2022, $85 million remained available for future purchases of common units under Rattler’s common unit repurchase program.
Commodity Prices
In early March 2020, oil prices dropped sharply and continued to decline, briefly reaching negative levels as a result of multiple factors affecting the supply and demand in global oil and natural gas markets, including (i) actions taken by OPEC members and other exporting nations impacting commodity price and production levels and (ii) a significant decrease in demand due to the ongoing COVID-19 pandemic. Additionally, the Delta variant emerged in MarchDuring 2021 and became highly transmissible in July 2021, which contributed to additional pricing and demand volatility during the thirdfirst quarter of 2021. However, certain restrictions on conducting business that were implemented in response to the COVID-19 pandemic have been lifted as improved treatments and vaccinations for COVID-19 have been rolled-out globally since late 2020. As a result, oil and natural gas market prices have improved in 2021 in response to the overall increase in demand.
During 2020 and 2021,2022, the posted NYMEX WTI price for crude oil ranged from $(37.63)$47.62 to $80.64$123.70 per Bbl, and the NYMEX Henry Hub price of natural gas ranged from $1.48$2.45 to $6.31 per MMBtu. On OctoberApril 13, 2021,2022, the NYMEX WTI price for crude oil was $80.44$104.25 per Bbl and the NYMEX Henry Hub price of natural gas was $5.59$7.00 per MMBtu. Commodity prices have historically been volatileThe Russian-Ukrainian military conflict and we cannot predict events which may lead to future fluctuations in these prices.
In addition to the volatility in commodity prices and the impact of the COVID-19 pandemic on our businesshave contributed to economic and industry, our results of operations may be adversely impacted by any government rule, regulation or order that may impose production limits, as well as pipeline capacity and storage constraints,pricing volatility in the Permian Basin where we operate.
As a resultfirst quarter of the reduction in crude oil2022 as industry and market participants evaluate global demand caused by factors discussed above, in 2020, we lowered our 2020 capital budgets and production guidance. We have since restored curtailed production in the second half of 2020 to stem production declines and respond to improved demand and increasing commodity prices, but have elected to keep production relatively flat during the remainder of 2021, focusing on cost control and using excess cash flow for debt payment and return of capital to our stockholders.
During the third quarter of 2021, we continued building on our execution track record, generating free cash flow while keeping capital costs under control, and our efficiency gains, particularly in the Midland Basin drilling and completion programs, were able to mitigate certain inflationary pressures on well costs and have led to our second decrease in capital guidance in 2021, now down 10% from our guidance presented in April of 2021. We expect to continue to exercise capital discipline and maintain flat oil production inoutlooks. On March 31, 2022, and believe that this can be accomplished by spending similar capital to our fourth quarter 2021 guidance. This capital range accounts for the inflationary pressures seen this year and anticipated in 2022. We expect to be in a position to continue to deliver on the recently announced enhanced capital return program, where we expect to distribute 50% of our quarterly free cash flow to our stockholders, beginning with the fourth quarter 2021. Our capital return program is currently focused on our sustainable and growing dividend and a combination of stock repurchases and variable dividends, which are expected to be used interchangeably, depending on which option we believe presents the best return of capital to our stockholders at the relevant time.
ThirdOPEC and its non-OPEC allies, known collectively as OPEC+, agreed to continue their program (commenced in August 2021) of gradual monthly output increases, raising its output target by 432,000 Bbl per day for May 2022, which is expected to further boost oil supply in response to rising demand. In its report issued on April 12, 2022 OPEC noted its expectation that world oil demand will rise by 3.7 million Bbls per day in 2022, down 480,000 Bbls per day from its previous forecast due to the impact of the Russian-Ukrainian military conflict, rising inflation and the resurgence of the Omicron coronavirus variant in China. Although this demand outlook is expected to underpin oil prices, already seen at a seven-year high in February 2022, we cannot predict any future volatility in or levels of commodity prices or demand for crude oil.
Despite the recovery in commodity prices and rising demand, we expect to hold our oil production levels flat during 2022, using excess cash flow for debt repayment and/or return to our stockholders rather than expanding our drilling program.
First Quarter 20212022 and Recent Operating and Environmental and Social Responsibility (ESG) Highlights
•We recorded net income of $649$779 million for the thirdfirst quarter of 2021.2022.
•Our average production was 404.3381.4 MBOE/d during the thirdfirst quarter of 2021.2022.
•During the thirdfirst quarter of 2021,2022, we drilled 47 gross horizontal wells in the Midland Basin and 1114 gross horizontal wells in the Delaware Basin.
•We turned 7369 gross operated horizontal wells (63(54 in the Midland Basin and 1015 in the Delaware Basin) to production and had capital expenditures, excluding acquisitions, of $391$437 million during the thirdfirst quarter of 2021.2022.
•The average lateral length for the wells completed during the thirdfirst quarter of 20212022 was 11,2259,658 feet.
•Our cash operating costs for the thirdfirst quarter of 20212022 were $9.97$11.36 per BOE, including lease operating expenses of $4.19$4.34 per BOE, cash general and administrative expenses of $0.65$0.61 per BOE and production and ad valorem taxes and gathering and transportation expenses of $5.13$6.41 per BOE.
•On October 28, 2021,April 27, 2022, our board of directors declared a cash dividend for the thirdfirst quarter of 20212022 of $0.50$3.05 per share of common stock, payable on November 18, 2021May 23, 2022 to our stockholders of record at the close of business on November 11, 2021.May 12, 2022. The dividend consists of a base quarterly dividend of $0.70 per share of common stock and a variable quarterly dividend of $2.35 per share of common stock. Future base and variable dividends are at the discretion of our board of directors.
•In January 2022, we acquired approximately 6,200 net acres from a third-party seller in Ward County, Texas for a purchase price of $232 million, net of customary post-closing adjustments, with average production of 1.3 MBO/d (2.3 MBOE/d) during the first quarter of 2022. The acquisition was funded with cash on hand and included 58 estimated gross (43 net) horizontal locations with an average lateral length of over 10,300 feet. The acquired acreage is 100% operated by us, with an average 74% working interest and 66% net revenue interest (85% effective net revenue interest).
•During the first quarter of 2022, we flared approximately 1.5% of our gross natural gas production.
•As of April 30, 2022, we have installed Continuous Emissions Monitoring Systems that cover approximately 70% of our operated oil volume production and monitor methane emissions, carbon monoxide and hydrogen sulfide (H2S) in real time. We intend to increase this monitoring effect to cover over 90% of our operated oil production by year-end 2023.
•By investing in infrastructure in our high activity areas, we now have the ability to run a dedicated e-frac fleet for the foreseeable future. We have partnered with Halliburton to secure our first e-fleet frac-core, which will run on our Martin County acreage off power generated from a central location and delivered via existing lines, reducing our Scope 1 emissions profile. This partnership is expected to lower our cost per foot primarily due to fuel savings, decrease our footprint on location and increase our operational efficiency as a result of lower maintenance and non-productive time. We expect this fleet to be operational in the fourth quarter of 2022.
Upstream Segment
In our upstream segment, our activities are primarily directed at the horizontal development of the Wolfcamp and Spraberry formations in the Midland Basin and the Wolfcamp and Bone Spring formations in the Delaware Basin within the Permian 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. Additionally, our publicly-traded subsidiary, Viper, is focused on owning and acquiring mineral interests and royalty interests in oil and natural gas properties primarily in the Permian Basin and derives royalty income and lease bonus income from such interests.
As of September 30, 2021,March 31, 2022, we had approximately 540,915451,295 net acres, which primarily consisted of approximately 263,208268,850 net acres in the Midland Basin and 149,405153,782 net acres in the Delaware Basin. Additionally, completed the divestiture of all of our Williston Basin assets totaling approximately 95,000 net acres in October 2021.
The following table sets forth the total number of operated horizontal wells drilled and completed during the three and nine months ended September 30, 2021:first quarter of 2022:
| | | Three Months Ended September 30, 2021 | | Nine Months Ended September 30, 2021 | | Three Months Ended March 31, 2022 | |
| | Drilled | | Completed(1) | | Drilled | | Completed(2) | | Drilled | | Completed(1) | |
| Area | Area | Gross | | Net | | Gross | | Net | | Gross | | Net | | Gross | | Net | Area | Gross | | Net | | Gross | | Net | |
| Midland Basin | Midland Basin | 47 | | | 44 | | | 63 | | | 59 | | | 135 | | | 127 | | | 152 | | | 140 | | Midland Basin | 47 | | | 46 | | | 54 | | | 50 | | |
| Delaware Basin | Delaware Basin | 11 | | | 10 | | | 10 | | | 9 | | | 28 | | | 26 | | | 49 | | | 46 | | Delaware Basin | 14 | | | 13 | | | 15 | | | 13 | | |
| Other | — | | | — | | | — | | | — | | | — | | | — | | | 4 | | | 3 | | |
| | Total | Total | 58 | | | 54 | | | 73 | | | 68 | | | 163 | | | 153 | | | 205 | | | 189 | | Total | 61 | | | 59 | | | 69 | | | 63 | | |
(1)The average lateral length for the wells completed during the thirdfirst quarter of 20212022 was 11,225 feet. Operated completions during the third quarter of 2021 consisted of 23 Wolfcamp A wells, 21 Lower Spraberry wells, 10 Middle Spraberry wells, eight Jo Mill wells, four Wolfcamp B wells, four Dean wells, two Second Bone Springs wells and one Third Bone Springs wells.
(2)The average lateral length for the wells completed during the first nine months of 2021 was 10,9069,658 feet. Operated completions during the first nine monthsquarter of 20212022 consisted of 6119 Lower Spraberry wells, 15 Wolfcamp A wells, 50 Lower Spraberry11 Jo Mill wells, 2510 Middle Spraberry wells, 21 Jo Mill wells, 17six Wolfcamp B wells, 10six Second Bone SpringsSpring wells, nineone Third Bone Springs wells, seven Dean wells, two Bakken wells, two Three Forks wellsSpring well and one Barnett well.
As of September 30, 2021,March 31, 2022, we operated the following wells:
| | | As of September 30, 2021 | | As of March 31, 2022 |
| | Vertical Wells | | Horizontal Wells | | Total | | Vertical Wells | | Horizontal Wells | | Total |
| Area | Area | Gross | | Net | | Gross | | Net | | Gross | | Net | Area | Gross | | Net | | Gross | | Net | | Gross | | Net |
| Midland Basin | Midland Basin | 2,298 | | | 2,142 | | | 1,689 | | | 1,565 | | | 3,987 | | | 3,707 | | Midland Basin | 2,278 | | | 2,114 | | | 1,803 | | | 1,674 | | | 4,081 | | | 3,788 | |
| Delaware Basin | Delaware Basin | 28 | | | 25 | | | 656 | | | 613 | | | 684 | | | 638 | | Delaware Basin | 48 | | | 44 | | | 703 | | | 655 | | | 751 | | | 699 | |
| Other | Other | — | | | — | | | 412 | | | 356 | | | 412 | | | 356 | | Other | — | | | — | | | — | | | — | | | — | | | — | |
| Total | Total | 2,326 | | | 2,167 | | | 2,757 | | | 2,534 | | | 5,083 | | | 4,701 | | Total | 2,326 | | | 2,158 | | | 2,506 | | | 2,329 | | | 4,832 | | | 4,487 | |
As of September 30, 2021,March 31, 2022, we held interests in 11,21411,289 gross (4,844(4,601 net) wells, including wells that we do not operate. During the first quarter of 2021, we acquired interests in 1,671 gross (1,240 net) wells as part of the QEP Merger.
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 GlasscockFivestones areas within the Permian Basin. Rattler’s water sourcing and distribution assets consist of water wells, hydraulic fracturing pits, pipelines and water treatment and recycling facilities, which collectively gather and distribute water from Permian Basin aquifers to the drilling and completion sites through buried pipelines and temporary surface pipelines. Rattler’s gathering and disposal system spans approximately 521600 miles and consists of gathering pipelines along with produced water disposal wells and facilities which collectively gather and dispose of produced water from operations throughout our Permian Basin acreage.
We have entered into multiple fee-based commercial agreements with Rattler, each with an initial term ending in 2034, utilizing Rattler’s infrastructure assets or its planned infrastructure assets to provide an array of essential services critical to our upstream operations in the Delaware and Midland Basins. Our agreements with Rattler include substantial acreage dedications.
The midstream operations segment’s revenues and operating expenses were not significant to our condensed consolidated statements of operations for the three and nine months ended September 30, 2021March 31, 2022 and 2020.2021. See Note 15—16—Segment Information of the condensed notes to the consolidated financial statements included elsewhere in this report for further details regarding acquisitions.
Results of Operations
The following table sets forth selected operating data for the threefirst quarter of 2022 and nine months ended September 30, 2021 and 2020:2021:
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended March 31, | |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | |
| Revenues (In millions): | Revenues (In millions): | | | | | | | | Revenues (In millions): | | | | |
| Oil sales | Oil sales | $ | 1,506 | | | $ | 606 | | | $ | 3,845 | | | $ | 1,785 | | Oil sales | $ | 1,946 | | | $ | 944 | | |
| Natural gas sales | Natural gas sales | 152 | | | 36 | | | 363 | | | 61 | | Natural gas sales | 154 | | | 104 | | |
| Natural gas liquid sales | Natural gas liquid sales | 239 | | | 65 | | | 528 | | | 156 | | Natural gas liquid sales | 289 | | | 124 | | |
| Total oil, natural gas and natural gas liquid revenues | Total oil, natural gas and natural gas liquid revenues | $ | 1,897 | | | $ | 707 | | | $ | 4,736 | | | $ | 2,002 | | Total oil, natural gas and natural gas liquid revenues | $ | 2,389 | | | $ | 1,172 | | |
| | Production Data: | Production Data: | | Production Data: | | |
| Oil (MBbls) | Oil (MBbls) | 22,058 | | | 15,639 | | | 60,703 | | | 50,009 | | Oil (MBbls) | 20,055 | | | 16,578 | | |
| Natural gas (MMcf) | Natural gas (MMcf) | 45,571 | | | 32,505 | | | 124,186 | | | 96,482 | | Natural gas (MMcf) | 42,645 | | | 34,109 | | |
| Natural gas liquids (MBbls) | Natural gas liquids (MBbls) | 7,540 | | | 5,377 | | | 19,992 | | | 16,326 | | Natural gas liquids (MBbls) | 7,161 | | | 5,405 | | |
Combined volumes (MBOE)(1) | Combined volumes (MBOE)(1) | 37,193 | | | 26,433 | | | 101,393 | | | 82,415 | | Combined volumes (MBOE)(1) | 34,324 | | | 27,668 | | |
| | Daily oil volumes (BO/d) | Daily oil volumes (BO/d) | 239,761 | | | 169,989 | | | 222,355 | | | 182,515 | | Daily oil volumes (BO/d) | 222,833 | | | 184,200 | | |
| Daily combined volumes (BOE/d) | Daily combined volumes (BOE/d) | 404,272 | | | 287,315 | | | 371,403 | | | 300,785 | | Daily combined volumes (BOE/d) | 381,378 | | | 307,422 | | |
| | Average Prices: | Average Prices: | | Average Prices: | | |
| Oil ($ per Bbl) | Oil ($ per Bbl) | $ | 68.27 | | | $ | 38.75 | | | $ | 63.34 | | | $ | 35.69 | | Oil ($ per Bbl) | $ | 97.03 | | | $ | 56.94 | | |
| Natural gas ($ per Mcf) | Natural gas ($ per Mcf) | $ | 3.34 | | | $ | 1.11 | | | $ | 2.92 | | | $ | 0.63 | | Natural gas ($ per Mcf) | $ | 3.61 | | | $ | 3.05 | | |
| Natural gas liquids ($ per Bbl) | Natural gas liquids ($ per Bbl) | $ | 31.70 | | | $ | 12.09 | | | $ | 26.41 | | | $ | 9.56 | | Natural gas liquids ($ per Bbl) | $ | 40.36 | | | $ | 22.94 | | |
| Combined ($ per BOE) | Combined ($ per BOE) | $ | 51.00 | | | $ | 26.75 | | | $ | 46.71 | | | $ | 24.29 | | Combined ($ per BOE) | $ | 69.60 | | | $ | 42.36 | | |
| Oil, hedged ($ per Bbl)(2) | Oil, hedged ($ per Bbl)(2) | $ | 53.81 | | | $ | 38.17 | | | $ | 50.46 | | | $ | 41.31 | | Oil, hedged ($ per Bbl)(2) | $ | 83.47 | | | $ | 46.81 | | |
Natural gas, hedged ($ per MMBtu)(2) | $ | 2.04 | | | $ | 0.95 | | | $ | 2.13 | | | $ | 0.57 | | |
Natural gas, hedged ($ per Mcf)(2) | | Natural gas, hedged ($ per Mcf)(2) | $ | 3.31 | | | $ | 2.64 | | |
Natural gas liquids, hedged ($ per Bbl)(2) | Natural gas liquids, hedged ($ per Bbl)(2) | $ | 31.30 | | | $ | 12.09 | | | $ | 26.16 | | | $ | 9.56 | | Natural gas liquids, hedged ($ per Bbl)(2) | $ | 40.36 | | | $ | 22.76 | | |
Average price, hedged ($ per BOE)(2) | Average price, hedged ($ per BOE)(2) | $ | 40.76 | | | $ | 26.22 | | | $ | 37.97 | | | $ | 27.63 | | Average price, hedged ($ per BOE)(2) | $ | 61.30 | | | $ | 35.75 | | |
(1)Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl.
(2)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices and include gains and losses on cash settlements for matured commodity derivatives, which we do not designate for hedge accounting. Hedged prices exclude gains or losses resulting from the early settlement of commodity derivative contracts.
Production Data
Substantially all of our revenues are generated through the sale of oil, natural gas and natural gas liquids production. The following tables set forth the mix of our production data by product and basin for the threefirst quarter of 2022 and nine months ended September 30, 2021 and 2020:2021:
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended March 31, | |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | |
| Oil (MBbls) | Oil (MBbls) | 59 | % | | 59 | % | | 60 | % | | 61 | % | Oil (MBbls) | 58 | % | | 60 | % | |
| Natural gas (MMcf) | Natural gas (MMcf) | 21 | % | | 21 | % | | 20 | % | | 19 | % | Natural gas (MMcf) | 21 | % | | 21 | % | |
| Natural gas liquids (MBbls) | Natural gas liquids (MBbls) | 20 | % | | 20 | % | | 20 | % | | 20 | % | Natural gas liquids (MBbls) | 21 | % | | 19 | % | |
| | 100 | % | | 100 | % | | 100 | % | | 100 | % | | 100 | % | | 100 | % | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2021 | | Three Months Ended September 30, 2020 |
| Midland Basin | Delaware Basin | Other(1) | Total | | Midland Basin | Delaware Basin | Other(2) | Total |
| Production Data: | | | | | | | | | |
| Oil (MBbls) | 14,265 | | 6,247 | | 1,546 | | 22,058 | | | 8,971 | | 6,627 | | 41 | | 15,639 | |
| Natural gas (MMcf) | 26,246 | | 16,210 | | 3,115 | | 45,571 | | | 17,403 | | 15,003 | | 99 | | 32,505 | |
| Natural gas liquids (MBbls) | 4,547 | | 2,301 | | 692 | | 7,540 | | | 3,087 | | 2,268 | | 22 | | 5,377 | |
| Total (MBoe) | 23,186 | | 11,250 | | 2,757 | | 37,193 | | | 14,958 | | 11,395 | | 80 | | 26,433 | |
| | | Nine Months Ended September 30, 2021 | | Nine Months Ended September 30, 2020 | | Three Months Ended March 31, 2022 | | Three Months Ended March 31, 2021 |
| | Midland Basin | Delaware Basin | Other(1) | Total | | Midland Basin | Delaware Basin | Other(2) | Total | | Midland Basin | Delaware Basin | Other(1) | Total | | Midland Basin | Delaware Basin | Other(2) | Total |
| Production Data: | Production Data: | | | | Production Data: | | | |
| Oil (MBbls) | Oil (MBbls) | 38,065 | | 19,074 | | 3,564 | | 60,703 | | | 28,864 | | 21,013 | | 132 | | 50,009 | | Oil (MBbls) | 13,921 | | 6,101 | | 33 | | 20,055 | | | 9,840 | | 6,436 | | 302 | | 16,578 | |
| Natural gas (MMcf) | Natural gas (MMcf) | 69,822 | | 47,503 | | 6,861 | | 124,186 | | | 50,285 | | 45,871 | | 326 | | 96,482 | | Natural gas (MMcf) | 26,873 | | 15,681 | | 91 | | 42,645 | | | 18,457 | | 15,055 | | 597 | | 34,109 | |
| Natural gas liquids (MBbls) | Natural gas liquids (MBbls) | 12,146 | | 6,438 | | 1,408 | | 19,992 | | | 9,281 | | 6,975 | | 70 | | 16,326 | | Natural gas liquids (MBbls) | 4,750 | | 2,390 | | 21 | | 7,161 | | | 3,236 | | 2,069 | | 100 | | 5,405 | |
| Total (MBoe) | Total (MBoe) | 61,848 | | 33,429 | | 6,116 | | 101,393 | | | 46,525 | | 35,633 | | 257 | | 82,415 | | Total (MBoe) | 23,150 | | 11,105 | | 69 | | 34,324 | | | 16,152 | | 11,014 | | 502 | | 27,668 | |
(1)Includes the Eagle Ford Shale and Rockies.
(2)Includes the Eagle Ford Shale, Rockies and High Plains.
(2)Includes the Central Basin Platform, Eagle Ford Shale and Rockies.
Comparison of the Three Months Ended September 30,March 31, 2022 and 2021 and 2020 and Nine Months Ended September 30, 2021 and 2020
Oil, Natural Gas and Natural Gas Liquids Revenues. Our revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average sales prices received for those volumes.
Our oil, natural gas and natural gas liquids revenues for the three months ended September 30, 2021first quarter of 2022 increased by $1.2 billion, or 168%104%, to $1.9$2.4 billion from $707 million$1.2 billion during the three months ended September 30, 2020.same period in 2021. Higher average oil prices, and to a lesser extent natural gas and natural gas liquids prices, contributed $0.9$1.0 billion of the total increase. The remainder of the overall change is due to a 41%24% increase in combined volumes sold.
Our oil, natural gas and natural gas liquids revenues for the nine months ended September 30, 2021 increased by $2.7 billion, or 137%, to $4.7 billion from $2.0 billion during the nine months ended September 30, 2020. Higher average oil prices, and to a lesser extent natural gas and natural gas liquids prices, contributed to $2.3 billion of the total increase. The remainder of the overall change is due to a 23% increase in combined volumes sold.
In both cases, higher commodity prices in the 2021 periodsfirst quarter of 2022 compared to the 2020 periodssame period in 2021 primarily reflect athe increase in demand for oil due to economic recovery from historically low prices experienced in 2020 due to the COVID-19 pandemic and other macroeconomic factors such as the Russian-Ukrainian military conflict as discussed in “—Recent Developments” above. The increase in production for the 2021 periodsfirst quarter of 2022 compared to the 2020 periodssame period in 2021 resulted primarily from recognizing a full quarter’s production in the first quarter of 2022 related to the Guidon Acquisition and QEP Merger, duringwhich occurred late in the first quarter of 20212021.
Other Revenues. The following table shows the other insignificant revenues for the three months ended March 31, 2022 and an overall recovery in our drilling and production activities2021:
| | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| 2022 | | 2021 | | | | |
| (In millions) |
| Midstream services | $ | 17 | | | $ | 11 | | | | | |
| Other operating income | $ | 2 | | | $ | 1 | | | | | |
after curtailments in the second quarter of 2020 in response to the COVID-19 pandemic. We expect to hold our oil production levels flat for the foreseeable future.
Lease Operating Expenses. The following table shows lease operating expenses for the three and nine months ended September 30, 2021March 31, 2022 and 2020:2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| Amount | | Per BOE | | Amount | | Per BOE | | Amount | | Per BOE | | Amount | | Per BOE |
| (In millions, except per BOE amounts) |
| Lease operating expenses | $ | 156 | | | $ | 4.19 | | | $ | 102 | | | $ | 3.86 | | | $ | 415 | | | $ | 4.09 | | | $ | 332 | | | $ | 4.03 | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| 2022 | | 2021 | | | | |
| Amount | | Per BOE | | Amount | | Per BOE | | | | | | | | |
| (In millions, except per BOE amounts) |
| Lease operating expenses | $ | 149 | | | $ | 4.34 | | | $ | 102 | | | $ | 3.69 | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Lease operating expenses increased by $54$47 million, or $0.33$0.65 per BOE for the thirdfirst quarter of 20212022 compared to the thirdfirst quarter of 2020 and increased by $83 million, or $0.06 per BOE for the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020. In both cases, this2021. This increase is primarily due to an increase inrecording a full quarter of production between periods driven byand operating expenses from the Guidon Acquisition and the QEP Merger in the first quarter of 2021.2022. The increase on a per BOE basis is primarily relateddue to the Williston Basin assetsimpact of production acquired infrom the Guidon Acquisition and the QEP Merger, which on average have higher lease operating costsexpenses per BOE on average than our historical properties.properties and, to a lesser extent, an increase in well workover activity.
Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the three and nine months ended September 30, 2021March 31, 2022 and 2020:2021:
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended March 31, | |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | |
| | Amount | | Per BOE | | Amount | | Per BOE | | Amount | | Per BOE | | Amount | | Per BOE | | Amount | | Per BOE | | Amount | | Per BOE | |
| | (In millions, except per BOE amounts) | | (In millions, except per BOE amounts) |
| Production taxes | Production taxes | $ | 98 | | | $ | 2.63 | | | $ | 36 | | | $ | 1.36 | | | $ | 245 | | | $ | 2.42 | | | $ | 97 | | | $ | 1.18 | | Production taxes | $ | 120 | | | $ | 3.50 | | | $ | 60 | | | $ | 2.17 | | |
| Ad valorem taxes | Ad valorem taxes | 26 | | | 0.70 | | | 19 | | | 0.72 | | | 59 | | | 0.58 | | | 51 | | | 0.62 | | Ad valorem taxes | 41 | | | 1.19 | | | 15 | | | 0.54 | | |
| Total production and ad valorem expense | Total production and ad valorem expense | $ | 124 | | | $ | 3.33 | | | $ | 55 | | | $ | 2.08 | | | $ | 304 | | | $ | 3.00 | | | $ | 148 | | | $ | 1.80 | | Total production and ad valorem expense | $ | 161 | | | $ | 4.69 | | | $ | 75 | | | $ | 2.71 | | |
| | Production taxes as a % of oil, natural gas, and natural gas liquids revenue | Production taxes as a % of oil, natural gas, and natural gas liquids revenue | 5.2 | % | | 5.1 | % | | 5.2 | % | | 4.8 | % | | Production taxes as a % of oil, natural gas, and natural gas liquids revenue | 5.0 | % | | 5.1 | % | | |
In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes as a percentage of production revenues increased slightlyremained consistent for the three and nine months ended September 30, 2021first quarter of 2022 compared to the same periodsperiod in 2020 due to the addition of production revenues from the acquired Williston Basin properties which have a higher production tax rate than our other properties. We completed the divestiture of the Williston Basin properties in October 2021.
Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. Ad valorem taxes for the three and nine months ended September 30, 2021first quarter of 2022 as compared to the same periodsperiod in 20202021 increased by $7$26 million and $8 million, respectively, primarily due to additional properties acquiredhigher overall valuations resulting from an increase in the Guidon acquisition and the QEP Merger.commodity prices between valuation periods.
Gathering and Transportation Expense. The following table shows gathering and transportation expense for the three and nine months ended September 30, 2021March 31, 2022 and 2020:2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| Amount | | Per BOE | | Amount | | Per BOE | | Amount | | Per BOE | | Amount | | Per BOE |
| (In millions, except per BOE amounts) |
| Gathering and transportation expense | $ | 67 | | | $ | 1.80 | | | $ | 33 | | | $ | 1.25 | | | $ | 154 | | | $ | 1.52 | | | $ | 105 | | | $ | 1.27 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| 2022 | | 2021 | | | | |
| Amount | | Per BOE | | Amount | | Per BOE | | | | | | | | |
| (In millions, except per BOE amounts) |
| Gathering and transportation expense | $ | 59 | | | $ | 1.72 | | | $ | 31 | | | $ | 1.12 | | | | | | | | | |
The increases forincrease in gathering and transportation expenses for the three and nine months ended September 30, 2021,first quarter of 2022, compared to the same periodsperiod in 2020 are2021 is primarily attributable to the increase in production between periods. Additionally,The increase on a per BOE basis is primarily attributable to several individually insignificant factors including an increase in third-party gas gathering expenses related to the sale of certain gas gathering assets during the fourth quarter of 2021, production added from the QEP Merger which has higher average gathering and transportation costs per BOE than our historical properties.properties and annual contractual rate escalations.
Depreciation, Depletion, Amortization and Accretion. The following table provides the components of our depreciation, depletion, amortization and accretion expense for the three and nine months ended September 30, 2021March 31, 2022 and 2020:2021:
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended March 31, | |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | |
| | (In millions, except BOE amounts) | | (In millions, except BOE amounts) |
| Depletion of proved oil and natural gas properties | Depletion of proved oil and natural gas properties | $ | 324 | | | $ | 273 | | | $ | 899 | | | $ | 995 | | Depletion of proved oil and natural gas properties | $ | 286 | | | $ | 257 | | |
| Depreciation of midstream assets | Depreciation of midstream assets | 11 | | | 9 | | | 37 | | | 29 | | Depreciation of midstream assets | 20 | | | 11 | | |
| Depreciation of other property and equipment | Depreciation of other property and equipment | 4 | | | 4 | | | 12 | | | 12 | | Depreciation of other property and equipment | 4 | | | 3 | | |
| Asset retirement obligation accretion | Asset retirement obligation accretion | 2 | | | 2 | | | 7 | | | 5 | | Asset retirement obligation accretion | 3 | | | 2 | | |
| Depreciation, depletion and amortization expense | $ | 341 | | | $ | 288 | | | $ | 955 | | | $ | 1,041 | | |
| Depreciation, depletion, amortization and accretion expense | | Depreciation, depletion, amortization and accretion expense | $ | 313 | | | $ | 273 | | |
| Oil and natural gas properties depletion rate per BOE | Oil and natural gas properties depletion rate per BOE | $ | 8.71 | | | $ | 10.33 | | | $ | 8.87 | | | $ | 12.07 | | Oil and natural gas properties depletion rate per BOE | $ | 8.33 | | | $ | 9.29 | | |
The increase in depletion of proved oil and natural gas properties of $51$29 million for the three months ended September 30, 2021first quarter of 2022 as compared to the three months ended September 30, 2020same period in 2021 resulted largely from increasedhigher production volumes partially offset by a lower average depletion rate. The decline in rate resulted primarily from higher SEC prices utilized in the reserve calculations in the 2021 period, lengthening the economic life of the reserve base and resulting in higher projected remaining reserve volumes on our wells.
The decrease in depletion of proved oil and natural gas properties of $96 million for the nine months ended September 30, 2021 as compared to the nine months ended September 30, 2020 resulted largely from a reduction in the average depletion rate partially offset by increased production in 2021. The decline in rate resulted primarily from higher SEC oil prices utilized in the reserve calculations in the 20212022 period, lengthening the economic life of the reserve base and resulting in higher projected remaining reserve volumes on our wells.
Impairment of Oil and Natural Gas Properties. No impairment expense was recorded for the three and nine months ended September 30, 2021.first quarter of 2022. In connection with the QEP Merger and the Guidon Acquisition in the first quarter of 2021, we recorded the oil and natural gas properties acquired at fair value. Pursuant to SEC guidance, we determined the fair value of the properties acquired in the QEP Merger and the Guidon Acquisition clearly exceeded the related full cost ceiling limitation beyond a reasonable doubt. As such, we requested and received a waiver from the SEC to exclude the acquired properties from the first quarter 2021 ceiling test calculation. As a result, no impairment expense related to the QEP Merger and the Guidon Acquisition was recorded for the three months ended March 31, 2021. Had we not received the waiver from the SEC, an impairment charge of approximately $1.1 billion would have been recorded in the first quarter of 2021. The properties acquired in the QEP Merger and the Guidon Acquisition had total unamortized costs at March 31, 2021 of $3.0 billion and $1.1 billion, respectively.
As a result of the sharp decline in commodity prices during 2020, we recorded non-cash ceiling test impairments for the three and nine months ended September 30, 2020 of $1.5 billion and $5.0 billion, respectively, which are included in accumulated depletion, depreciation, amortization and impairment on our condensed consolidated balance sheet.
Impairment charges affect our results of operations but do not reduce our cash flow. In addition to commodity prices, our production rates, levels of proved reserves, future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analysis in future periods. If the trailing 12-month commodity prices fall significantly as compared to the commodity prices used in prior quarters, we may have material write-downs in subsequent quarters. See Note 5—Property and Equipment of the condensed notes to the consolidated financial statements included elsewhere in this report for further details regarding factors that impact the impairment of oil and natural gas properties.
General and Administrative Expenses. The following table shows general and administrative expenses for the three and nine months ended September 30, 2021March 31, 2022 and 2020:2021:
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended March 31, | |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | |
| | Amount | | Per BOE | | Amount | | Per BOE | | Amount | | Per BOE | | Amount | | Per BOE | | Amount | | Per BOE | | Amount | | Per BOE | |
| | (In millions, except per BOE amounts) | | (In millions, except per BOE amounts) |
| General and administrative expenses | General and administrative expenses | $ | 24 | | | $ | 0.65 | | | $ | 11 | | | $ | 0.42 | | | $ | 62 | | | $ | 0.61 | | | $ | 37 | | | $ | 0.45 | | General and administrative expenses | $ | 21 | | | $ | 0.61 | | | $ | 15 | | | $ | 0.54 | | |
| Non-cash stock-based compensation | Non-cash stock-based compensation | 14 | | | 0.37 | | | 9 | | | 0.34 | | | 37 | | | 0.37 | | | 27 | | | 0.33 | | Non-cash stock-based compensation | 15 | | | 0.44 | | | 10 | | | 0.36 | | |
| Total general and administrative expenses | Total general and administrative expenses | $ | 38 | | | $ | 1.02 | | | $ | 20 | | | $ | 0.76 | | | $ | 99 | | | $ | 0.98 | | | $ | 64 | | | $ | 0.78 | | Total general and administrative expenses | $ | 36 | | | $ | 1.05 | | | $ | 25 | | | $ | 0.90 | | |
The increasesincrease in general and administrative expenses for the three and nine months ended September 30, 2021first quarter of 2022 compared to the threesame period in 2021 was due primarily to higher compensation costs resulting from growth in our headcount and nine months ended September 30, 2020 were due largely to additional payrollan increase in salary and other employee drivenbonus costs of $11 million and $21 million, respectively, related toin the QEP Merger and the Guidon Acquisition.current year. Additionally, equity compensation increased by $5 million and $10 million for the three and nine months ended September 30, 2021, respectively,first quarter of 2022 compared to the same periodsperiod in 2020.2021, primarily due to a higher grant-date fair value for performance stock units issued in the first quarter of 2022 and the accelerated vesting of restricted stock held by transitional employees related to the QEP Merger.
Merger and Integration Expense. The following tables shows merger and integration expense for the three and nine months ended September 30, 2021March 31, 2022 and 2020:2021:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| (In millions) |
| Merger and integration expense | $ | — | | | $ | — | | | $ | 77 | | | $ | — | |
| | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| 2022 | | 2021 | | | | |
| (In millions) |
| Merger and integration expense | $ | — | | | $ | 75 | | | | | |
Total merger and integration expense for the nine months ended September 30,first quarter of 2021 includes $68$67 million in costs incurred for the QEP Merger and $9$8 million in costs incurred for the Guidon Acquisition. The QEP Merger related expenses primarily consistconsisted of $38 million in severance costs and $30$23 million in banking, legal and advisory fees, and the Guidon Acquisition related expenses consistconsisted primarily of advisory and legal fees. See Note 4—Acquisitions and Divestitures of the condensed notes to the consolidated financial statements included elsewhere in this report for further details regarding the QEP Merger and the Guidon Acquisition.
40Other Operating Costs and Expenses. The following table shows the other insignificant operating costs and expenses for the three months ended March 31, 2022 and 2021:
| | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| 2022 | | 2021 | | | | |
| (In millions) |
| Midstream services expense | $ | 22 | | | $ | 28 | | | | | |
| Other operating expense | 8 | | | 4 | | | | | |
Net Interest Expense. The following table shows the components of net interest expense for the three and nine months ended September 30, 2021March 31, 2022 and 2020:2021:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| (In millions) |
| Revolving credit agreements | $ | 2 | | | $ | 4 | | | $ | 7 | | | $ | 17 | |
| Senior notes | 66 | | | 57 | | | 197 | | | 155 | |
| Amortization of debt issuance costs and discounts | 5 | | | 4 | | | 13 | | | 9 | |
| Other | 1 | | | 2 | | | 5 | | | 7 | |
| Capitalized interest | (16) | | | (14) | | | (51) | | | (41) | |
| Total | 58 | | | 53 | | | 171 | | | 147 | |
| Less: interest income | 1 | | | — | | | 1 | | | — | |
| Interest expense, net | $ | 57 | | | $ | 53 | | | $ | 170 | | | $ | 147 | |
| | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| 2022 | | 2021 | | | | |
| (In millions) |
| Revolving credit agreements | $ | 4 | | | $ | 3 | | | | | |
| Senior notes | 61 | | | 61 | | | | | |
| Amortization of debt issuance costs and discounts | 5 | | | 4 | | | | | |
| Other | 1 | | | 4 | | | | | |
| Capitalized interest | (31) | | | (14) | | | | | |
| Total | 40 | | | 58 | | | | | |
| Less: interest income | — | | | 2 | | | | | |
| Interest expense, net | $ | 40 | | | $ | 56 | | | | | |
Net interest expense increaseddecreased by $4 million and $23$16 million for the three and nine months ended September 30, 2021first quarter of 2022 compared to the same periodsperiod in 2020. In both cases, the increase was2021, primarily due to an increase in capitalized interest expense related to our May 2020 Notes, Rattler’s 5.625% Senior Notes due 2025, the newly issued March 2021 Notes, and to a lesser extent, interest expense incurred on the QEP Notes that remained outstanding following the QEP Merger completed in March 2021. These increases were partially offset by interest cost savings on the repurchases of our 2025 Senior Notes in March 2021 and August 2021, and the reduction in borrowings under our revolving credit agreements during 2021.costs. See Note 7—Debt of the condensed notes to the consolidated financial statements included elsewhere in this report for further details regarding outstanding borrowings and interest expense.borrowings.
Derivative Instruments. The following table shows the net gain (loss) on derivative instruments and the net cash receipts (payments) on settlements of derivative instruments for the three and nine months ended September 30, 2021March 31, 2022 and 2020:2021:
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended March 31, | |
| | 2021 | | 2020 | | 2021 | | 2020 | | 2022 | | 2021 | |
| | (In millions) | | (In millions) |
| Gain (loss) on derivative instruments, net | Gain (loss) on derivative instruments, net | $ | (234) | | | $ | (99) | | | $ | (895) | | | $ | 82 | | Gain (loss) on derivative instruments, net | $ | (552) | | | $ | (164) | | |
Net cash received (paid) on settlements(3)(2) | Net cash received (paid) on settlements(3)(2) | $ | (397) | | | $ | (9) | | | $ | (822) | | | $ | 288 | | Net cash received (paid) on settlements(3)(2) | $ | (420) | | | $ | (102) | | |
(1)The three and nine months ended September 30, 2021 includeMarch 31, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $16$135 million.
(2)The three and nine months ended September 30, 2020 include cash received on commodity contracts terminated prior to their contractual maturity of $6 million and $17 million, respectively.
(3)The nine months ended September 30,March 31, 2021 includeincludes cash received on interest rate swap contracts terminated prior to their contractual maturity of $80 million.
We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our commodity 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.”
We have designated certain of our interest rate swaps as fair value hedges for accounting purposes. As parta result, gains and losses due to changes in the fair value of the QEP Merger,interest rate swaps completely offset changes in the fair value of the hedged portion of the underlying debt and no gain or loss is recognized due to hedge effectiveness. Changes in fair value are recorded as an adjustment to the carrying value of the 2029 Notes in the condensed consolidated balance sheet. Beginning on December 1, 2021, semi-annual cash settlements of these interest rate swaps will be recorded in interest expense in the condensed consolidated statements of operations.
Other Income (Expense). The following table shows other insignificant income and expenses for the three months ended March 31, 2022 and 2021:
| | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| 2022 | | 2021 | | | | |
| (In millions) |
| Other income (expense), net | $ | 1 | | | $ | 1 | | | | | |
| Gain (loss) on extinguishment of debt | $ | (54) | | | $ | (61) | | | | | |
| Income (loss) from equity investments | $ | 9 | | | $ | (3) | | | | | |
See Note 7—Debt of the condensed notes to the consolidated financial statements included elsewhere in this report for further details regarding gain (loss) on extinguishment of debt in the first quarter of 2022.
Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the three months ended March 31, 2022 and 2021:
| | | | | | | | | | | | | | | |
| Three Months Ended March 31, | | |
| 2022 | | 2021 | | | | |
| (In millions) |
| Provision for (benefit from) income taxes | $ | 221 | | | $ | 65 | | | | | |
The change in our income tax provision for the first quarter of 2022 compared to the same period in 2021 was primarily due to the increase in pre-tax income which resulted primarily from the changes in revenues from oil, natural gas and natural gas liquids, gain (loss) on derivatives and other expenses discussed above. See Note 10—Income Taxes of the condensed notes to the consolidated financial statements included elsewhere in this report for further discussion of our income tax expense.
Comparison of the Three Months Ended March 31, 2022 and December 31, 2021
As noted in “—Recent Developments,” the markets for oil and natural gas are highly volatile and are influenced by a number of factors which can lead to significant changes in our results of operations and management’s operational strategy on a quarterly basis. As a result, beginning with the first quarter of 2022, we have elected to change our results of operations discussion to focus on a comparison of the current quarter’s results of operations with those of the immediately preceding quarter. We believe the change in our discussion will provide investors with a more meaningful analysis of material operational and financial changes which occurred during the quarter based on current market and operational trends.
Results of Operations
The following table sets forth selected operating data for the three months ended March 31, 2022 and December 31, 2021:
| | | | | | | | | | | | | | | |
| Three Months Ended | | |
| March 31, 2022 | | December 31, 2021 | | | | |
| Revenues (In millions): | | | | | | | |
| Oil sales | $ | 1,946 | | | $ | 1,551 | | | | | |
| Natural gas sales | 154 | | | 206 | | | | | |
| Natural gas liquid sales | 289 | | | 254 | | | | | |
| Total oil, natural gas and natural gas liquid revenues | $ | 2,389 | | | $ | 2,011 | | | | | |
| | | | | | | |
| Production Data: | | | | | | | |
| Oil (MBbls) | 20,055 | | | 20,819 | | | | | |
| Natural gas (MMcf) | 42,645 | | | 45,220 | | | | | |
| Natural gas liquids (MBbls) | 7,161 | | | 7,254 | | | | | |
Combined volumes (MBOE)(1) | 34,324 | | | 35,610 | | | | | |
| | | | | | | |
| Daily oil volumes (BO/d) | 222,833 | | | 226,293 | | | | | |
| Daily combined volumes (BOE/d) | 381,378 | | | 387,065 | | | | | |
| | | | | | | |
| Average Prices: | | | | | | | |
| Oil ($ per Bbl) | $ | 97.03 | | | $ | 74.50 | | | | | |
| Natural gas ($ per Mcf) | $ | 3.61 | | | $ | 4.56 | | | | | |
| Natural gas liquids ($ per Bbl) | $ | 40.36 | | | $ | 35.02 | | | | | |
| Combined ($ per BOE) | $ | 69.60 | | | $ | 56.47 | | | | | |
| | | | | | | |
Oil, hedged ($ per Bbl)(2) | $ | 83.47 | | | $ | 58.70 | | | | | |
Natural gas, hedged ($ per Mcf)(2) | $ | 3.31 | | | $ | 3.12 | | | | | |
Natural gas liquids, hedged ($ per Bbl)(2) | $ | 40.36 | | | $ | 34.46 | | | | | |
Average price, hedged ($ per BOE)(2) | $ | 61.30 | | | $ | 45.30 | | | | | |
(1)Bbl equivalents are calculated using a conversion rate of six Mcf per Bbl.
(2)Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices and include gains and losses on cash settlements for matured commodity derivatives, which we do not designate for hedge accounting. Hedged prices exclude gains or losses resulting from the early settlement of commodity derivative contracts.
Production Data
Substantially all of our revenues are generated through the sale of oil, natural gas and natural gas liquids production. The following tables provides information on the mix of our production for the three months ended March 31, 2022 and December 31, 2021:
| | | | | | | | | | | | | | | |
| Three Months Ended | | |
| March 31, 2022 | | December 21, 2021 | | | | |
| Oil (MBbls) | 58 | % | | 59 | % | | | | |
| Natural gas (MMcf) | 21 | % | | 21 | % | | | | |
| Natural gas liquids (MBbls) | 21 | % | | 20 | % | | | | |
| 100 | % | | 100 | % | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended March 31, 2022 | | Three Months Ended December 31, 2021 |
| Midland Basin | Delaware Basin | Other(1) | Total | | Midland Basin | Delaware Basin | Other(2) | Total |
| Production Data: | | | | | | | | | |
| Oil (MBbls) | 13,921 | | 6,101 | | 33 | | 20,055 | | | 14,047 | | 6,598 | | 174 | | 20,819 | |
| Natural gas (MMcf) | 26,873 | | 15,681 | | 91 | | 42,645 | | | 26,261 | | 18,531 | | 428 | | 45,220 | |
| Natural gas liquids (MBbls) | 4,750 | | 2,390 | | 21 | | 7,161 | | | 4,864 | | 2,311 | | 79 | | 7,254 | |
| Total (MBoe) | 23,150 | | 11,105 | | 69 | | 34,324 | | | 23,288 | | 11,998 | | 324 | | 35,610 | |
(1)Includes the Eagle Ford Shale and Rockies.
(2)Includes the Eagle Ford Shale, Rockies and High Plains.
Oil, Natural Gas and Natural Gas Liquids Revenues. Our revenues are a function of oil, natural gas and natural gas liquids production volumes sold and average sales prices received for those volumes.
Our oil, natural gas and natural gas liquids revenues for the first quarter of 2022 increased by novation$378 million, or 19%, to $2.4 billion from QEP$2.0 billion during the fourth quarter of 2021. Higher average oil prices, and to a lesser extent natural gas liquids prices, contributed $450 million of the total increase. The remainder of the overall change is due to a 4% decrease in combined volumes sold.
Higher commodity prices in the 2022 period compared to the 2021 period primarily reflect the increase in demand for oil due to economic recovery from the COVID-19 pandemic and other macroeconomic factors such as the Russian-Ukrainian military conflict as discussed in “—Recent Developments” above. The decrease in production resulted primarily from having two fewer days of production in the first quarter of 2022 compared to the fourth quarter of 2021.
Other Revenues. The following table shows other insignificant revenues for the three months ended March 31, 2022 and December 31, 2021:
| | | | | | | | | | | | | | | |
| Three Months Ended | | |
| March 31, 2022 | | December 31, 2021 | | | | |
| (In millions) |
| Midstream services | $ | 17 | | | $ | 10 | | | | | |
| Other operating income | $ | 2 | | | $ | 1 | | | | | |
Lease Operating Expenses. The following table shows lease operating expenses for the three months ended March 31, 2022 and December 31, 2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended | | |
| March 31, 2022 | | December 31, 2021 | | | | |
| Amount | | Per BOE | | Amount | | Per BOE | | | | | | | | |
| (In millions, except per BOE amounts) |
| Lease operating expenses | $ | 149 | | | $ | 4.34 | | | $ | 150 | | | $ | 4.21 | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Lease operating expenses remained consistent in total and increased by $0.13 on a per BOE basis for the first quarter of 2022 compared to the fourth quarter of 2021. The increase on a per BOE basis is primarily related to service cost inflation, as well as the impact of having two fewer operating days over which to allocate fixed lease operating expenses.
Production and Ad Valorem Tax Expense. The following table shows production and ad valorem tax expense for the three months ended March 31, 2022 and December 31, 2021:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended |
| March 31, 2022 | | December 31, 2021 |
| Amount | | Per BOE | | Amount | | Per BOE |
| (In millions, except per BOE amounts) |
| Production taxes | $ | 120 | | | $ | 3.50 | | | $ | 104 | | | $ | 2.92 | |
| Ad valorem taxes | 41 | | | 1.19 | | | 17 | | | 0.48 | |
| Total production and ad valorem expense | $ | 161 | | | $ | 4.69 | | | $ | 121 | | | $ | 3.40 | |
| | | | | | | |
| Production taxes as a % of oil, natural gas, and natural gas liquids revenue | 5.0 | % | | | | 5.2 | % | | |
In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes as a percentage of production revenues for the first quarter of 2022 remained consistent with the fourth quarter of 2021.
Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices, which were adjusted upward during the first quarter of 2022 based on the recovery in commodity prices during 2021 as compared to 2020. Additionally, the fourth quarter of 2021 also included a downward revision to our full 2021 ad valorem accrual based on actual tax assessments received, which caused ad valorem taxes on a per BOE rate to be lower in that period. These adjustment resulted in an overall increase in ad valorem tax expense of $24 million for the first quarter of 2022 compared to the fourth quarter of 2021.
Gathering and Transportation Expense. The following table shows gathering and transportation expense for the three months ended March 31, 2022 and December 31, 2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended | | |
| March 31, 2022 | | December 31, 2021 | | | | |
| Amount | | Per BOE | | Amount | | Per BOE | | | | | | | | |
| (In millions, except per BOE amounts) |
| Gathering and transportation expense | $ | 59 | | | $ | 1.72 | | | $ | 58 | | | $ | 1.63 | | | | | | | | | |
Gathering and transportation expenses remained relatively consistent in total and increased by $0.09 on a per BOE basis for the first quarter of 2022 compared to the fourth quarter of 2021. The increase is primarily related to additional third-party gas gathering charges incurred following the divestiture of certain gas gathering assets during the fourth quarter of 2021.
Depreciation, Depletion, Amortization and Accretion. The following table provides the components of our depreciation, depletion, amortization and accretion expense for the three months ended March 31, 2022 and December 31, 2021:
| | | | | | | | | | | | | | | |
| Three Months Ended | | |
| March 31, 2022 | | December 31, 2021 | | | | |
| (In millions, except BOE amounts) |
| Depletion of proved oil and natural gas properties | $ | 286 | | | $ | 303 | | | | | |
| Depreciation of midstream assets | 20 | | | 11 | | | | | |
| Depreciation of other property and equipment | 4 | | | 4 | | | | | |
| Asset retirement obligation accretion | 3 | | | 2 | | | | | |
| Depreciation, depletion, amortization and accretion expense | $ | 313 | | | $ | 320 | | | | | |
| Oil and natural gas properties depletion rate per BOE | $ | 8.33 | | | $ | 8.51 | | | | | |
The decrease in depletion of proved oil and natural gas properties of $17 million for the first quarter of 2022 as compared to the fourth quarter of 2021 resulted largely from lower production in the first quarter of 2022 coupled with a decline in the average depletion rate. The decline in rate resulted primarily from higher SEC prices utilized in the reserve calculations in the 2021 period, which lengthened the economic life of the reserve base and resulted in higher projected remaining reserve volumes on our wells.
General and Administrative Expenses. The following table shows general and administrative expenses for the three months ended March 31, 2022 and December 31, 2021:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended |
| March 31, 2022 | | December 31, 2021 |
| Amount | | Per BOE | | Amount | | Per BOE |
| (In millions, except per BOE amounts) |
| General and administrative expenses | $ | 21 | | | $ | 0.61 | | | $ | 33 | | | $ | 0.93 | |
| Non-cash stock-based compensation | 15 | | | 0.44 | | | 14 | | | 0.39 | |
| Total general and administrative expenses | $ | 36 | | | $ | 1.05 | | | $ | 47 | | | $ | 1.32 | |
The decrease in general and administrative expenses for the first quarter of 2022 compared to the fourth quarter of 2021 was due largely to compensation related accrual adjustments made during the fourth quarter of 2021 for annual bonuses. Equity compensation for the first quarter of 2022 remained consistent with the fourth quarter of 2021.
Other Operating Costs and Expenses. The following table shows other insignificant operating costs and expenses for the three months ended March 31, 2022 and December 31, 2021:
| | | | | | | | | | | | | | | |
| Three Months Ended | | |
| March 31, 2022 | | December 31, 2021 | | | | |
| (In millions) |
| Midstream services expense | $ | 22 | | | $ | 19 | | | | | |
| Merger and integration expense | $ | — | | | $ | 1 | | | | | |
| Other operating expense | $ | 8 | | | $ | (5) | | | | | |
Net Interest Expense. The following table shows the components of net interest expense for the three months ended March 31, 2022 and December 31, 2021:
| | | | | | | | | | | |
| Three Months Ended |
| March 31, 2022 | | December 31, 2021 |
| (In millions) |
| Revolving credit agreements | $ | 4 | | | $ | 4 | |
| Senior notes | 61 | | | 55 | |
| Amortization of debt issuance costs and discounts | 5 | | | 5 | |
| Other | 1 | | | 2 | |
| Capitalized interest | (31) | | | (37) | |
| Total | 40 | | | 29 | |
| Less: interest income | — | | | — | |
| Interest expense, net | $ | 40 | | | $ | 29 | |
Net interest expense increased by $11 million for the first quarter of 2022 compared to the fourth quarter of 2021. The increase was primarily due to (i) interest expense in the fourth quarter of 2021 reflecting the receipt of a $7 million cash settlement on our fair value interest rate swaps which offset a portion of the interest expense on our 2029 Notes, and (ii) a decrease in capitalized interest costs. Our fair value interest rate swaps settle semi-annually in December and June. See Note 7—Debt of the condensed notes to the consolidated financial statements included elsewhere in this report for further details regarding outstanding borrowings and interest expense.
Derivative Instruments. The following table shows the net gain (loss) on derivative instruments which were includedand the net cash receipts (payments) on oursettlements of derivative instruments for the three months ended March 31, 2022 and December 31, 2021:
| | | | | | | | | | | |
| Three Months Ended |
| March 31, 2022 | | December 31, 2021 |
| (In millions) |
| Gain (loss) on derivative instruments, net | $ | (552) | | | $ | 47 | |
Net cash received (paid) on settlements(1) | $ | (420) | | | $ | (403) | |
(1)The first quarter of 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $135 million.
We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our commodity 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 September 30, 2021.operations under the line item captioned “Gain (loss) on derivative instruments, net.”
We have designated certain of our interest rate swaps as fair value hedges for accounting purposes. As a result, gains and losses due to changes in the fair value of the interest rate swaps completely offset changes in the fair value of the hedged portion of the underlying debt and no gain or loss is recognized due to hedge ineffectiveness. Changes in fair value are recorded as an adjustment to the carrying value of the 2029 Notes in the condensed consolidated balance sheet. Beginning on December 1, 2021, semi-annual cash settlements of these interest rate swaps will be recorded in interest expense in the condensed consolidated statements of operations.
Other Income (Expense). The following table shows other income and expenses for the three months ended March 31, 2022 and December 31, 2021:
| | | | | | | | | | | | | | | |
| Three Months Ended | | |
| March 31, 2022 | | December 31, 2021 | | | | |
| (In millions) |
| Other income (expense), net | $ | 1 | | | $ | (6) | | | | | |
| Gain (loss) on extinguishment of debt | $ | (54) | | | $ | (2) | | | | | |
| Income (loss) from equity investments | $ | 9 | | | $ | 9 | | | | | |
See Note 7—Debt of the condensed notes to the consolidated financial statements included elsewhere in this report for further details regarding gain (loss) on extinguishment of debt.
Provision for (Benefit from) Income Taxes. The following table shows the provision for (benefit from) income taxes for the threefirst quarter of 2022 and nine months ended September 30, 2021 and 2020:fourth quarter of 2021:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| (In millions) |
| Provision for (benefit from) income taxes | $ | 193 | | | $ | (304) | | | $ | 352 | | | $ | (902) | |
| | | | | | | | | | | |
| Three Months Ended |
| March 31, 2022 | | December 31, 2021 |
| (In millions) |
| Provision for (benefit from) income taxes | $ | 221 | | | $ | 279 | |
The changeschange in our income tax provision for the three and nine months ended September 30, 2021first quarter of 2022 compared to the same periods in 2020 werefourth quarter of 2021 was primarily due to the increasedecrease in pre-tax income between the periods which resulted primarily from the changes in gain (loss) on derivatives and revenues from oil, natural gas and natural gas liquids discussed above. See Note 10—Income Taxesfor the three and nine months ended September 30, 2021, partially offset byfurther discussion of our income tax expense resulting from recording a valuation allowance on Viper’s deferred tax assets for the nine months ended September 30, 2021.expense.
Liquidity and Capital Resources
AsOverview of September 30, 2021, we had $1.6 billionSources and Uses of availability for future borrowings under the credit agreement and approximately $457 million of cash on hand. Cash
Historically, our primary sources of liquidity have beeninclude cash flows from operations, proceeds from our public equity offerings, borrowings under theour revolving credit agreement andfacility, proceeds from the issuance of our senior notes.notes and sales of non-core assets. Our primary uses of capital have been for the acquisition, development and exploration of oil and natural gas propertiesproperties. At March 31, 2022, we had approximately $1.7 billion of liquidity consisting of $0.1 billion in cash and returncash equivalents and $1.6 billion available under our credit facility. As discussed below, our capital budget for 2022 is $1.75 billion to $1.90 billion. Further, we have $45 million of capital to our stockholders.senior notes maturities in the next 12 months.
Our working capital requirements are supported by our cash and cash equivalents and our credit facility. We may draw on our revolving credit facility to meet short-term cash requirements, or issue debt or equity securities as part of our longer-term liquidity and capital management program. Because of the alternatives available to us as discussed above, we believe that our short-term and long-term liquidity are adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our capital spending programs, dividend payments, debt service obligations and repayment of debt maturities, repurchases of equity or debt securities and other amounts that may ultimately be paid in connection with contingencies.
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. In order to mitigate this volatility, we entered into derivative contracts with a number of financial institutions, all of which are participants in our credit facility, hedging a portion of our estimated future crude oil and natural gas production through the end of 2023 as discussed further in Note 11—Derivatives and Item 3. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk. The level of our hedging activity and duration of the financial instruments employed depend on our desired cash flow protection, available hedge prices, the magnitude of our capital program and our operating strategy.
As we pursue our business and financial strategy, we regularly consider which capital resources, including cash flow and equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us. Continued prolonged volatility in the capital, financial and/or credit markets due to the Russian-Ukrainian military conflict, the COVID-19 pandemic, the commodity pricing environment and uncertainand/or other 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. Although the Company expects that its sources of funding will be adequate to fund its short-term and long-term liquidity requirements, we cannot assure you that the needed capital will be available on acceptable terms or at all.
Liquidity and Cash Flow
Our cash flows for the ninethree months ended September 30,March 31, 2022 and 2021 and 2020 are presented below:
| | | Nine Months Ended September 30, | | Three Months Ended March 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| | (In millions) | | (In millions) |
| Net cash provided by (used in) operating activities | Net cash provided by (used in) operating activities | $ | 2,777 | | | $ | 1,715 | | Net cash provided by (used in) operating activities | $ | 1,252 | | | $ | 624 | |
| Net cash provided by (used in) investing activities | Net cash provided by (used in) investing activities | (1,323) | | | (1,855) | | Net cash provided by (used in) investing activities | (716) | | | (587) | |
| Net cash provided by (used in) financing activities | Net cash provided by (used in) financing activities | (1,021) | | | 111 | | Net cash provided by (used in) financing activities | (1,041) | | | 29 | |
| Net increase (decrease) in cash | Net increase (decrease) in cash | $ | 433 | | | $ | (29) | | Net increase (decrease) in cash | $ | (505) | | | $ | 66 | |
Operating Activities
Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas we produce. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict.
The increase in operating cash flows for the ninethree months ended September 30, 2021March 31, 2022 compared to the same period in 20202021 primarily resulted from (i) an increase of $2.7$1.2 billion in our total revenues, which was partially offset by cash outflows of (i) $242 million due to making net cash payments of $420 million on our derivative contracts in the first quarter of 2022 compared to net cash payments of $178 million on our derivative contracts in the first quarter of 2021, (ii) an increase in our cash operating expenses of approximately $90 million primarily due to the QEP Merger and (ii) receiptthe Guidon Acquisition, (iii) an increase of $152$31 million in refunds ofour cash paid for interest primarily due to interest payments on senior notes which were issued in 2021 and (iv) other working capital changes including an increase in accounts receivable for oil and natural gas sales and revenues and a partially offsetting increase in revenues and royalties payable, which stem from higher commodity prices in 2022, as well as recording a payable for income taxes expected to be paid in 2022 compared to an income tax receivable related to the carryback of federal net operating losses and the accelerated refund of minimum tax credits allowed under the 2020 CARES Act in 2020. These net cash inflows were partially offset by (i) a reduction of $1.1 billion due to making net cash payments of $847 million on our derivative contracts in the nine months ended September 30, 2021 compared to receiving net cash of $288 million on our derivative contracts in the nine months ended September 30, 2020, (ii) an increase in our cash operating expenses of approximately $396 million primarily due to the QEP Merger and the Guidon Acquisition, (iii) an increase of $77 million in our cash paid for interest primarily due to interest payments on senior notes which were issued in 2020 and 2021 and (iv) other working capital changes, primarily due to recording activity for working capital assets and liabilities acquired in the QEP Merger during March 2021.prior year. See “—Results of Operations” for discussion of significant changes in our revenues and expenses.
Investing Activities
Net cash used in investing activities was $1.3 billion$716 million compared to $1.9 billion$587 million during the ninethree months ended September 30,March 31, 2022 and 2021, and 2020, respectively. The majority of our net cash used for investing activities during the ninethree months ended September 30,March 31, 2022 was for drilling and completion costs in conjunction with our development program and as well as the purchase of oil and gas properties, which is discussed further in Note 4—Acquisitions and Divestitures.
The majority of our net cash used in investing activities during the three months ended March 31, 2021 was for the purchase and development of oil and natural gas properties and related assets including the acquisition of certain leasehold interests as part of the Guidon Acquisition.
These expenditures were partially offset by proceeds from the sale of leasehold acreage discussed in Note 4—Acquisitions and Divestitures.
The majority of our net cash used in investing activities during the nine months ended September 30, 2020 was incurred for drilling and completion costs in conjunction with our development program. Our capital expenditures for each period are discussed further below.
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, | | Three Months Ended March 31, |
| | 2021 | | 2020 | | 2022 | | 2021 |
| | (In millions) | | (In millions) |
Drilling, completions and non-operated additions to oil and natural gas properties(1)(2) | Drilling, completions and non-operated additions to oil and natural gas properties(1)(2) | $ | 987 | | | $ | 1,404 | | Drilling, completions and non-operated additions to oil and natural gas properties(1)(2) | $ | 374 | | | $ | 281 | |
| Infrastructure additions to oil and natural gas properties | Infrastructure additions to oil and natural gas properties | 43 | | | 96 | | Infrastructure additions to oil and natural gas properties | 44 | | | 8 | |
| Additions to midstream assets | Additions to midstream assets | 23 | | | 133 | | Additions to midstream assets | 19 | | | 7 | |
| Total | Total | $ | 1,053 | | | $ | 1,633 | | Total | $ | 437 | | | $ | 296 | |
(1)During the ninethree months ended September 30, 2021,March 31, 2022, in conjunction with our development program, we drilled 16361 gross (153(59 net) operated horizontal wells, of which 13547 gross (127(46 net) wells were in the Midland Basin and 2814 gross (26(13 net) wells were in the Delaware Basin, and turned 20569 gross (189(63 net) operated horizontal wells to production, of which 15254 gross (140(50 net) wells were in the Midland Basin and 4915 gross (46(13 net) wells were in the Delaware Basin.
(2)During the ninethree months ended September 30, 2020,March 31, 2021, in conjunction with our development program, we drilled 18349 gross (173(47 net) operated horizontal wells, of which 11441 gross (108(40 net) wells were in the Midland Basin and 69eight gross (65(seven net) wells were in the Delaware Basin, and turned 13667 gross (124(60 net) operated horizontal wells to production, of which 6942 gross (61(37 net) wells were in the Midland Basin and 6725 gross (63(23 net) wells were in the Delaware Basin .
Financing Activities
Net cash used in financing activities for the ninethree months ended September 30, 2021March 31, 2022 was $1.0 billion compared to net cash provided by financing activities for the ninethree months ended September 30, 2020March 31, 2021 of $111$29 million. During the ninethree months ended September 30, 2021,March 31, 2022, the amount used in financing activities was primarily attributable to (i) $2.5$1.5 billion paid for the repurchase of principal outstanding on certain senior notes as discussed in “— Repurchases of Notes”2022 Debt Transactions” below, as well as $178$47 million of additional premiums paid in connection with the repurchases, (ii) $221$107 million of dividends paid to stockholders, (iii) $94 million of repayments under our credit facilities, net of borrowings, (iv) $72$47 million in distributions to non-controlling interest,interests, and (v) $85(iv) $49 million of repurchases as part of the share and unit repurchase programs.programs, and (v) $21 million of repayments under credit facilities, net of borrowings. These cash outflows were partially offset by $2.2 billion$750 million in proceeds from the March 2021 Notes and $25 million in net cash receipts from the early settlement of interest rate swaps and commodity derivative contracts that contained an other-than-insignificant financing element.2022 Notes.
Net cash provided by financing activities for the ninethree months ended September 30, 2020March 31, 2021 was primarily attributable to $758$2.2 billion in proceeds from the March 2021 Notes and $76 million in proceeds that relate primarily to the early settlement of interest rate swaps that contained an other-than-insignificant financing element. These net of repayments,increases in cash flows from senior notes and $47 million in proceeds from joint ventures. These cash inflowsfinancing activities were partially offset by (i) $321$1.9 billion paid for the repurchase of a portion of the QEP Notes and 2025 Senior Notes, as well as $166 million of repayments, netadditional premiums paid in connection with the repurchases, $68 million of borrowings,dividends paid to stockholders, $24 million of unit repurchases as part of the Viper and Rattler unit repurchase programs and $23 million of repayments under our credit facilities, (i) $177 millionnet of dividends to stockholders, (ii) $98 million of share repurchases as part of our previous stock repurchase program, and (iii) $77 million of distributions to non-controlling interest.borrowings.
IndebtednessCapital Resources
AtRevolving Credit Facilities and Other Debt Instruments
September 30, 2021,
As of March 31, 2022, our debt, including the debt of Viper and Rattler, consists of approximately $6.9$5.4 billion in aggregate outstanding principal amount of senior notes, $92$478 million in aggregate outstanding borrowings under revolving credit facilities and $65$64 million in outstanding amounts due under our DrillCo Agreement. Our revolving credit facilities and
significant changes in our outstanding indebtedness during the nine months ended September 30, 2021 are discussed further below. See Note 7—Debt for additional discussion of our outstanding debt at September 30, 2021.
Second Amended and Restated Credit Facility
As discussed in “— Recent Developments” on June 2, 2021, we entered into an amendment to the credit agreement. As of September 30, 2021,March 31, 2022, the maximum credit amount available under theour credit agreement was $1.6 billion, with no outstanding borrowings and $1.6 billion available for future borrowings. As of September 30, 2021,March 31, 2022, there was an aggregate of $3 million in outstanding letters of credit, which reduce available borrowings under theour credit agreement on a dollar for dollar basis. During the nine months ended September 30, 2021, the weighted average interest rate on theThere were no borrowings under our credit facility was 1.67%.
As of September 30, 2021, we were in compliance with all financial maintenance covenants under the credit agreement.
March 2021 Notes Offering
On March 24, 2021, we issued $650 million of our 2023 Notes, $900 million of our 2031 Notes and $650 million of our 2051 Notes and received proceeds of $2.18 billion, net of $24 million in debt issuance costs and discounts. The net proceeds were primarily used to fund the repurchase of other senior notes outstanding as discussed further below. Interest on the March 2021 Notes is payable semi-annually in March and September, beginning in September 2021.
Repurchases of Notes
Subsequent to the QEP Merger, in March 2021, we repurchased pursuant to tender offers commenced by us approximately $1.65 billion in fair value carrying amount of the QEP Notes for total cash consideration of $1.7 billion, including redemption and early premium fees, which resulted in a loss on extinguishment of debtagreement during the three months ended March 31, 2021 of approximately $47 million. The aggregate fair value of the QEP Notes repurchased consisted of (i) $453 million, or 94.65%, of the outstanding fair value carrying amount of the QEP 2022 Notes, (ii) $663 million, or 98.43%, of the outstanding fair value carrying amount of the QEP 2023 Notes, and (iii) $538 million, or 96.35%, of the outstanding fair value carrying amount of the QEP 2026 Notes.2022.
In March 2021, we also repurchased an aggregate of $368 million principal amount of our 5.375% 2025 Senior Notes, representing approximately 45.97% of the outstanding 2025 Senior Notes, for total cash consideration of $381 million, including redemption and early premium fees. This resulted in a loss on extinguishment of debt during the nine months ended September 30, 2021 of $14 million.
We funded the repurchases of the QEP Notes and 2025 Senior Notes with the proceeds from the March 2021 Notes offering discussed above.
In connection with the tender offers to repurchase the QEP Notes discussed above, we also solicited consents from holders of the QEP Notes to amend the indenture for the QEP Notes to, among other things, eliminate substantially all of the restrictive covenants and related provisions and certain events of default contained in the indenture under which the QEP Notes were issued. We received the requisite number of consents and, on March 23, 2021, entered into a supplemental indenture relating to the QEP Notes adopting these amendments.
In June 2021, we redeemed the remaining $191 million principal amount of the outstanding Energen 4.625% senior notes due on September 1, 2021. We recorded an immaterial pre-tax loss on extinguishment of debt related to the redemption, which included the write-off of unamortized debt discounts associated with the redeemed notes. We funded the redemption with internally generated cash flow from operations as well as proceeds from the divestitures of certain non-core assets as discussed in Note 4—Acquisitions and Divestitures.
In August 2021, we redeemed the remaining $432 million principal amount of our outstanding 5.375% Senior Notes due 2025 for total cash consideration of $449 million, including redemption and early premium fees of $12 million, which resulted in a loss on extinguishment of debt during the three and nine months ended September 30, 2021 of $12 million. We funded the redemption with cash on hand and borrowings under its revolving credit facility.
On November 1, 2021, we redeemed the aggregate $650 million principal amount of our outstanding 2023 Senior Notes at a redemption price equal to 100% of the principal amount, plus accrued and unpaid interest up to, but not including, the redemption date. We funded the redemption with proceeds received from the divestiture of our Williston Basin assets and cash on hand.
Viper’s Credit Agreement
The Viper credit agreement, as amended to date, provides for a revolving credit facility in the maximum credit amount of $2.0 billion, with a borrowing base of $580 million as of September 30, 2021,March 31, 2022, although Viper LLC had elected a commitment amount of $500 million, based on Viper LLC’s oil and natural gas reserves and other factors. The borrowing base is scheduled to be redetermined semi-annually in May and November, and is expected to be reaffirmed at $580 million by the lenders during the redetermination in November 2021.May 2022. As of September 30, 2021,March 31, 2022, there were $92$248 million of outstanding borrowings and $408$252 million available for future borrowings under the Viper credit agreement. In the fourth quarter of 2021, approximately $190.0 million of the cash portion of the Swallowtail Acquisition was funded through borrowings under Viper’s credit agreement, reducing the amount that remained available for future borrowings under this facility to $218.0 million as of October 1, 2021. During the three and nine months ended September 30, 2021,March 31, 2022, the weighted average interest rate on borrowings under the Viper credit agreement was 1.98% and 2.14%, respectively.2.58%. The Viper credit agreement will mature on June 2, 2025.
As of September 30, 2021, Viper LLC was in compliance with all financial maintenance covenants under the Viper credit agreement.
Rattler’s Credit Agreement
The Rattler credit agreement, as amended to date, provides for a revolving credit facility in the maximum credit amount of $600 million, which is expandable to $1.0 billion upon Rattler’s election, subject to obtaining additional lender commitments and satisfaction of customary conditions. As of September 30, 2021,March 31, 2022, there were no$230 million of outstanding borrowings and $600$370 million available for future borrowings under the Rattler credit agreement. During the three and nine months ended September 30, 2021,March 31, 2022, the weighted average interest rate on borrowings under the Rattler credit agreement was 1.34% and 1.38%, respectively.1.40%. The Rattler credit agreement matures on May 28, 2024.
As
2022 Debt Transactions
On March 17, 2022, Diamondback Energy, Inc. issued the $750 million March 2022 Notes for net proceeds of $739 million, which were used to fund, together with cash on hand, the redemption of all of our outstanding 4.750% Senior Notes due 2025 and 2.875% Senior Notes due 2024 in the aggregate principal amount of $1.5 billion. Interest on the March 2022 Notes is payable semi-annually on March 15 and September 30, 2021, Rattler LLC was15 of each year, beginning on September 15, 2022.
For additional discussion of our outstanding debt as of March 31, 2022, see Note 7—Debt of the condensed notes to the consolidated financial statements included elsewhere in this report.
Subject to market conditions and other factors, we expect to continue to issue debt securities from time to time in the future to refinance our maturing debt. The availability, interest rate and other terms of any new borrowings will depend on the ratings assigned by credit rating agencies, among other factors.
We are currently in compliance, and expect to continue to be, with all financial maintenance covenants in our debt instruments.
Debt Ratings
We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales and production growth opportunities. Our credit rating from Standard and Poor’s Global Ratings Services is BBB-. Our credit rating from Fitch Investor Services is BBB. Our credit rating from Moody’s Investor Services is Baa3. Any rating downgrades may result in additional letters of credit or cash collateral being posted under the Rattler credit agreement.certain contractual arrangements.
Capital Requirements and Sources of Liquidity
OurIn addition to future operating expenses and working capital commitments discussed in —Results of Operations, our primary short and long-term liquidity requirements consist primarily of (i) capital expenditures, (ii) payments of other contractual obligations including debt maturities,and (iii) cash used to pay for dividends and share repurchases and (iv) working capital obligations.of securities as discussed below.
DuringBased upon current oil and natural gas prices and production expectations for 2022, we believe that our cash flow from operations, cash on hand and borrowings under our revolving credit facility will be sufficient to fund our operations through the 12-month period following the filing of this report and thereafter. 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. We cannot assure you that the needed capital will be available on acceptable terms or at all. Further, our 2022 capital expenditure budget does not allocate any funds for leasehold interest and property acquisitions.
2022 Capital Spending Plan
Our board of directors approved a 2022 capital budget for drilling, midstream and infrastructure of approximately $1.75 billion to $1.90 billion, maintaining our annualized fourth quarter 2021 cash capital expenditure guidance presented in November of 2021, we updated our 2021 capital budget to approximately $1.49 billion to $1.53 billion, which represented a decrease at the midpoint of 4% over our previously announced capital budget. This decrease is due to cost control and volume outperformance of our 2021 development plan. We intend to maintain current production levels with less capital and fewer completed wells than were originally expected in our 2021 development plan.2021. We estimate that, of these expenditures, approximately:
•$1.391.56 billion to $1.42$1.67 billion will be spent primarily on drilling 270 to 290 gross (248 to 267 net) horizontal wells and completing and 265260 to 275280 gross (246(240 to 256258 net) horizontal wells across our operated and non-operated leasehold acreage in the Northern Midland and Southern Delaware Basins, with an average lateral length of approximately 10,50010,200 feet;
•$4080 million to $100 million will be spent on midstream infrastructure, excluding joint venture investments; and
•$60110 million to $70$130 million will be spent on infrastructure and environmental expenditures, excluding the cost of any leasehold and mineral interest acquisitions.
We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately forecasted.
During the ninethree months ended September 30, 2021,March 31, 2022, we spent $948$374 million on drilling and completion, $23$19 million on midstream $39 million on non-operated properties and $43$44 million on infrastructure, for total capital expenditures, excluding acquisitions, of $1,053$437 million.
The amount and timing of our capital expenditures are largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including but not limited to the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs and the level of participation by other interest owners. We are currently operating nine10 drilling rigs
and threefour completion crews. We currently continue to execute on our strategy to hold oil production flat while using cash flow from operations to reduce debt, strengthen our balance sheet and return capital to our stockholders. We will continue monitoring commodity prices and overall market conditions and can adjust our rig cadence and our capital expenditure budget in response to changes in commodity prices and overall market conditions.
Dividends and Repurchases of Securities
We paid common stock dividends of $107 million and $68 million during three months ended March 31, 2022 and 2021, respectively. In addition to our base dividend program, we have initiated a variable dividend strategy whereby we may pay a quarterly variable dividend of up to 50 percent of the prior quarter’s free cash flow remaining after the payment of the base dividend. On April 27, 2022, our board of directors declared a cash dividend for the first quarter of 2022 of $3.05 per share of common stock, payable on May 23, 2022 to our stockholders of record at the close of business on May 12, 2022. The decision to pay any future dividends is solely within the discretion of, and subject to approval by, our board of directors. The dividend consists of a base quarterly dividend of $0.70 per share of common stock and a variable quarterly dividend of $2.35 per share of common stock.
Free cash flow is a non-GAAP financial measure. As used by the Company, free cash flow is defined as cash flow from operating activities before changes in working capital in excess of cash capital expenditures. The Company believes that free cash flow is useful to investors as it provides a measure to compare both cash flow from operating activities and additions to oil and natural gas properties across periods on a consistent basis.
Future base and variable dividends are at the discretion of our board of directors, and, if declared, the board of directors may change the dividend amount based on the Company's outlook for commodity prices, liquidity, debt levels, capital resources, free cash flow and other factors. The Company can provide no assurance that dividends will be authorized or declared in the future or as to the amount of any future dividends. Any future variable dividends, if declared and paid, will by their nature fluctuate based on the Company's free cash flow, which will depend on a number of factors beyond the Company's control, including commodity prices.
In September 2021, our board of directors approved a stock repurchase program to acquire up to $2 billion of our outstanding common stock. We repurchased approximately $22$7 million of our common stock under this program during the ninethree months ended September 30, 2021, with approximately $1.98March 31, 2022, and have $1.6 billion remaining available for future repurchases under this program.the repurchase program at March 31, 2022. We intend to continue to purchase shares under this repurchase program opportunistically with available funds primarily from cash flow from operations and liquidity events such as the sale of assets while maintaining sufficient liquidity to fund our capital expenditure programs. See Note 8—Stockholders' Equity and Earnings Per Share of the condensed notes to the consolidated financial statements included elsewhere in this report for further discussion of the repurchase program.
Based upon current oil and natural gas prices and production expectations for 2021, we believe thatWe may also from time to time opportunistically repurchase some of our outstanding Senior Notes of one or more tranches or series, in open market purchases or in privately negotiated transactions.
Income Taxes
We expect our cash flow from operations, cash on hand and borrowings under our revolving credit facility willtax rate to be sufficient10% to fund our operations through15% of pre-tax income for the 12-month period followingyear ended December 31, 2022. See Note 10—Income Taxes of the filing ofcondensed notes to the consolidated financial statements included elsewhere in this report and thereafter. However, future cash flows are subject to a numberfor further discussion 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. We cannot assure you that the needed capital will be available on acceptable terms or at all. Further, our 2021 capital expenditure budget does not allocate any funds for leasehold interest and property acquisitions.income taxes.
Guarantor Financial Information
In connection with the mergerAs of certain of the Company’s wholly owned subsidiaries in an internal subsidiary restructuring on June 30, 2021,March 31, 2022, Diamondback E&P became the successor borrower to O&G under the credit agreement, the successor issuer of the Energen Medium-Term Notes andis the sole guarantor under the indentures governing the outstanding December 2019 Notes, the May 2020 Notes, the 2025 SeniorMarch 2021 Notes and the March 20212022 Notes.
Guarantees are “full and unconditional,” as that term is used in Regulation S-X, Rule 3-10(b)(3), except that such guarantees will be released or terminated in certain circumstances set forth in the 2019 Indenture and the 2025IG Indenture, such as, with certain exceptions, (1) in the event Diamondback E&P (or all or substantially all of its assets) is sold or disposed of, (2) in the event Diamondback E&P ceases to be a guarantor of or otherwise be an obligor under certain other indebtedness, and (3) in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the relevant indenture. The 2025 Indenture was terminated in connection with the early redemption of the remaining $432 million principal amount of our 2025 Senior Notes in the third quarter of 2021.
Diamondback E&P’s guarantees of the outstanding December 2019 Notes, the May 2020March 2021 Notes and the March 20212022 Notes are senior unsecured obligations and rank senior in right of payment to any of its future subordinated indebtedness, equal in right of payment with all of its existing and future senior indebtedness, including its obligations under its revolving credit facility, and effectively subordinated to any of its existing and future secured indebtedness, to the extent of the value of the collateral securing such indebtedness.
The rights of holders of the Senior Notes against Diamondback E&P 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 E&P’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 E&P. Moreover, this provision may not be effective to protect the guarantee from being voided under fraudulent conveyance laws. There is a possibility that the entire guarantee may be set aside, in which case the entire liability may be extinguished.
The following tables present summarized financial information for Diamondback Energy, Inc., as the parent, and Diamondback E&P, as the guarantor subsidiary, on a combined basis after elimination of (i) intercompany transactions and balances between the parent and the guarantor subsidiary and (ii) equity in earnings from and investments in any subsidiary that is a non-guarantor. The information is presented in accordance with the requirements of Rule 13-01 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiary operated as an independent entity.
| | | September 30, 2021 | | December 31, 2020 | | March 31, 2022 | | December 31, 2021 |
| Summarized Balance Sheets: | Summarized Balance Sheets: | (In millions) | Summarized Balance Sheets: | (In millions) |
| Assets: | Assets: | | Assets: | |
| Current assets | Current assets | $ | 979 | | | $ | 308 | | Current assets | $ | 967 | | | $ | 1,148 | |
| | Property and equipment, net | Property and equipment, net | $ | 14,558 | | | $ | 6,934 | | Property and equipment, net | $ | 15,339 | | | $ | 14,778 | |
| Other noncurrent assets | Other noncurrent assets | $ | 44 | | | $ | 6 | | Other noncurrent assets | $ | 67 | | | $ | 55 | |
| Liabilities: | Liabilities: | | Liabilities: | |
| Current liabilities | Current liabilities | $ | 1,675 | | | $ | 355 | | Current liabilities | $ | 1,629 | | | $ | 1,221 | |
| Intercompany accounts payable, non-guarantor subsidiary | Intercompany accounts payable, non-guarantor subsidiary | $ | 468 | | | $ | 335 | | Intercompany accounts payable, non-guarantor subsidiary | $ | 1,637 | | | $ | 1,440 | |
| Long-term debt | Long-term debt | $ | 5,748 | | | $ | 4,293 | | Long-term debt | $ | 4,270 | | | $ | 5,093 | |
| Other noncurrent liabilities | Other noncurrent liabilities | $ | 1,270 | | | $ | 886 | | Other noncurrent liabilities | $ | 1,758 | | | $ | 1,549 | |
| | | | | |
| NineThree Months Ended September 30, 2021March 31, 2022 |
| Summarized Statement of Operations: | (In millions) |
| Revenues | $ | 3,5161,855 | |
| Income (loss) from operations | $ | 1,9641,253 | |
| Net income (loss) | $ | 658436 | |
Contractual ObligationsCritical Accounting Estimates
In addition to the changes in debt discussed in “—Indebtedness” above and in Note 7—Debt included in the notes to the condensed consolidated financial statements included elsewhere in this report, we acquired certain contractual obligations during the nine months ended September 30, 2021 in conjunction with the QEP Merger including an aggregate of approximately $68 million in various transportation, gathering and purchase commitments. There werehave been no other significant changes in our contractual obligationscritical accounting estimates from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2020.2021.
CriticalRecent Accounting Policies and EstimatesPronouncements
There have been no changes in our critical accounting policies from those disclosed in our See Note 2—Annual Report on Form 10-K for the year ended December 31, 2020.
Off-Balance Sheet Arrangements
We had no material off-balance sheet arrangements asSummary of September 30, 2021. Please read Note 13—Commitments and ContingenciesSignificant Accounting Policies included in the condensed notes to the condensed consolidated financial statements included elsewhere in this report,Quarterly Report for a discussion of our commitmentsrecent accounting pronouncements and contingencies, which areaccounting policies not recognized in the balance sheets under GAAP.yet adopted, if any.
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. Although demand and market prices for oil and natural gas have recently increased, due to the rising energy use, easing of the COVID-19 pandemic and the improvements in the U.S. economic activity, we cannot predict events, including the outcome of the Russian-Ukrainian military conflict or the COVID-19 pandemic, that may lead to future price volatility and the near term energy outlook remains subject to heightened levels of uncertainty. Further, the prices we receive for production depend on many other factors outside of our control.
We use derivatives, including swaps, basis swaps, puts, swaptions, roll swaps, and costless collars, puts and basis puts, to reduce price volatility associated with certain of our oil and natural gas sales.
At September 30, 2021,March 31, 2022, we had a net liability derivative position related to our commodity price derivatives of $618$300 million, related to our commodity price risk derivatives. Utilizing actual derivative contractual volumes under our commodity price derivatives as of September 30, 2021,March 31, 2022, a 10% increase in forward curves associated with the underlying commodity would have increased the net liability position by $256$128 million to $874$428 million, while a 10% decrease in forward curves associated with the underlying commodity would have decreased the net liability position by $218$105 million to $400$195 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. For additional information on our open commodity derivative instruments at March 31, 2022, see Note 11—Derivatives included in the condensed notes to the consolidated financial statements included elsewhere in this Quarterly Report.
In our midstream operations business, we have indirect exposure to commodity price risk in that persistent low commodity prices may cause us or Rattler’s other customers to delay drilling or shut in production, which would reduce the volumes available for gathering and processing by our infrastructure assets. If we or Rattler’s other customers delay drilling or temporarily shut in production due to persistently low commodity prices or for any other reason, our revenue in the midstream operations segment could decrease, as Rattler’s commercial agreements do not contain minimum volume commitments.
For additional information on our open commodity derivative instruments at September 30, 2021, see Note 11—Derivatives.
Counterparty and Customer Credit Risk
Our principal exposures to credit risk are due to the concentration of receivables from the sale of our oil and natural gas production (approximately $712$966 million at September 30, 2021)March 31, 2022), and to a lesser extent, receivables resulting from joint interest receivables (approximately $99$113 million at September 30, 2021)March 31, 2022).
We do not require our customers to post collateral, and the failure or inability of our significant customers to meet their obligations to us due to their liquidity issues, bankruptcy, insolvency or liquidation may adversely affect our financial results.
Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells.
Interest Rate Risk
We are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolving credit facilities and changes in the fair value of our fixed-ratefixed rate debt. The terms of the credit agreement 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 1.125% per annum in the case of the alternative base rate and from 1.25% to 2.125% per annum in the case of LIBOR, in each case based on the pricing level. The pricing level depends on certain rating agencies’ ratings of our long-term senior unsecure debt. We believe significant interest rate changes would not have a material near-term impact on our future earnings or cash flows. For additional information on our variable interest rate debt at September 30, 2021,March 31, 2022, see Note 7—Debt. included in the condensed notes to the consolidated financial statements included elsewhere in this Quarterly Report.
Historically, we have at times used interest rates swaps to manage our exposure to (i) interest rate changes on our floating-rate date and (ii) fair value changes on our fixed-ratefixed rate debt. At September 30, 2021,March 31, 2022, we have interest rate swap agreements for a notional amount of $1.2 billion to manage the impact of market interest rates on interest expense. These interest rate swaps have been designated as fair value hedges of the Company’s $1.2 billion 3.50% fixed rate senior notes due
2029 whereby we will receive the fixed rate of interest and will pay an average variable rate of interest based on three month LIBOR plus 2.1865%. For additional information on our interest rate swaps, see Note 11—Derivatives. included in the condensed notes to the consolidated financial statements included elsewhere in this Quarterly Report.
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, 2021,March 31, 2022, 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, 2021,March 31, 2022, our disclosure controls and procedures are effective.
Changes in Internal Control over Financial Reporting. In July 2021, we implemented an enterprise resource planning system covering various financial and accounting processes. As a result of this implementation, certain internal controls over financial reporting have been automated, modified or implemented to address the new environment associated with the implementation of this system. We believe we have maintained appropriate internal control over financial reporting during the implementation and believe this new system will strengthen our internal control system. However, there are inherent risks in implementing any new system, and we will continue to evaluate these control changes as part of our assessment of internal control over financial reporting throughout 2021. There have not been any changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2021,March 31, 2022, that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.
PART II
ITEM 1. LEGAL PROCEEDINGS
We are a party to various routine legal proceedings, disputes and claims arising in the ordinary course of our business, including those that arise from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry, personal injury claims, title disputes, royalty disputes, contract claims, contamination claims relating to oil and natural gas exploration and development and environmental claims, including claims involving assets previously sold to third parties and no longer part of our current operations. While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on us, cannot be predicted with certainty, we believe that none of these matters, if ultimately decided adversely, will have a material adverse effect on our financial condition, results of operations or cash flows. See Note 13—14—Commitments and Contingencies. included in the condensed notes to the consolidated financial statements included elsewhere in this Quarterly Report.
ITEM 1A. RISK FACTORS
Our business faces many risks. Any of the risks discussed in this report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also materially impair our business operations, financial condition or future results.
As of the date of this filing, we continue to be subject to the risk factors previously disclosed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2020,2021, filed with the SEC on February 25, 2021,24, 2022, and in subsequent filings we make with the SEC. ThereExcept as provided below, there have been no material changes in our risk factors from those described in our Annual Report on Form 10-K for the year ended December 31, 2020.2021.
We cannot predict the impact of the ongoing military conflict between Russia and Ukraine and the related humanitarian crisis on the global economy, energy markets, geopolitical stability and our business.
Our leasehold acreage is located primarily in the Permian Basin in West Texas. However, the broader consequences of the Russian-Ukrainian conflict, which may include further sanctions, embargoes, supply chain disruptions, regional instability and geopolitical shifts, may have adverse effects on global macroeconomic conditions, increase volatility in the price and demand for oil and natural gas, increase exposure to cyberattacks, cause disruptions in global supply chains, increase foreign currency fluctuations, cause constraints or disruption in the capital markets and limit sources of liquidity. We cannot predict the extent of the conflict’s effect on our business and results of operations as well as on the global economy and energy markets.
Our targets related to sustainability and emissions reduction initiatives, including our public statements and disclosures regarding them, may expose us to numerous risks.
We have developed, and will continue to develop, targets related to our ESG initiatives, including our emissions reduction targets and strategy. Statements in this and other reports we file with the SEC and other public statements related to these initiatives reflect our current plans and expectations and are not a guarantee the targets will be achieved or achieved on the currently anticipated timeline. Our ability to achieve our ESG targets, including emissions reductions, is subject to numerous factors and conditions, some of which are outside of our control, and failure to achieve our announced targets or comply with ethical, environmental or other standards, including reporting standards, may expose us to government enforcement actions or private litigation and adversely impact our business. Further, our continuing efforts to research, establish, accomplish and accurately report on these targets may create additional operational risks and expenses and expose us to reputational, legal and other risks.
Investor and regulatory focus on ESG matters continues to increase. If our ESG initiatives do not meet our investors’ or other stakeholders’ evolving expectations and standards, investment in our stock may be viewed as less attractive and our reputation, contractual, employment and other business relationships may be adversely impacted.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Unregistered Sales of Equity Securities
None.
Issuer Repurchases of Equity Securities
Our common stock repurchase activity for the ninethree months ended September 30, 2021March 31, 2022 was as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Total Number of Shares Purchased(1) | | Average Price Paid Per Share(2) | | Total Number of Shares Purchased as Part of Publicly Announced Plan | | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan(3) |
| | ($ In millions, except per share amounts, shares in thousands) |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| July 1, 2021 - July 31, 2021 | | — | | $ | — | | | — | | $ | — | |
| August 1, 2021 - August 31, 2021 | | — | | $ | — | | | — | | $ | — | |
| September 1, 2021 - September 30, 2021 | | 268 | | $ | 82.02 | | | 268 | | $ | 1,978 | |
| Total | | 268 | | $ | 82.02 | | | 268 | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Total Number of Shares Purchased(1) | | Average Price Paid Per Share(2) | | Total Number of Shares Purchased as Part of Publicly Announced Plan | | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plan(3) |
| | ($ In millions, except per share amounts, shares in thousands) |
| January 1, 2022 - January 31, 2022 | | 15 | | $ | 109.89 | | | 15 | | $ | 1,567 | |
| February 1, 2022 - February 28, 2022 | | — | | $ | — | | | — | | $ | 1,567 | |
| March 1, 2022 - March 31, 2022 | | 151 | | $ | 132.99 | | | 43 | | $ | 1,562 | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| Total | | 166 | | $ | 130.92 | | | 58 | | |
(1)Includes 108,508 shares of common stock repurchased from employees in order to satisfy tax withholding requirements. Such shares are cancelled and retired immediately upon repurchase.
(2)The average price paid per share includes any commissions paid to repurchase stock.
(3)In September 2021, the Company’s board of directors authorized a $2 billion common stock repurchase program. The stock repurchase program has no time limit and may be suspended, modified, or discontinued by the board of directors at any time.
ITEM 6. EXHIBITS
EXHIBIT INDEX | | | | | | | | |
| Exhibit Number | | Description |
| 3.1 | | |
| 3.2 | | |
| 3.3 | | |
| 3.4 | | |
| 4.1 | | |
| 4.2 | | |
| 4.3 | | |
| 4.4 | | Fifth Supplemental Indenture, dated as of March 17, 2022, among Diamondback Energy, Inc., Diamondback E&P LLC and Computershare Trust Company, National Association, as trustee (including the form of the March 2022 Notes) (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 001-35700, filed by the Company with the SEC on March 17, 2022). |
| 10.1 | | |
| 22.1 | | |
| 31.1* | | |
| 31.2* | | |
| 32.1** | | |
| 32.2** | | |
| 101 | | The following financial information from the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2021,March 31, 2022, formatted in Inline XBRL: (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statement of Changes in Stockholders’ Equity, (iv) Condensed Consolidated Statements of Cash Flows and (v) Condensed Notes to Consolidated Financial Statements. |
| 104 | | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). |
______________
| | | | | |
| * | Filed herewith. |
| ** | The certifications attached as Exhibit 32.1 and Exhibit 32.2 accompany this Quarterly Report on Form 10-Q pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended. |
| |
| |
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 4, 2021May 5, 2022 | /s/ Travis D. Stice |
| | Travis D. Stice |
| | Chief Executive Officer |
| | (Principal Executive Officer) |
| |
| Date: | November 4, 2021May 5, 2022 | /s/ Kaes Van’t Hof |
| | Kaes Van’t Hof |
| | Chief Financial Officer |
| | (Principal Financial Officer) |