UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2024
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File No. 001-13726
EXPAND ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
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| Oklahoma | 73-1395733 |
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
| 6100 North Western Avenue, | Oklahoma City, | Oklahoma | 73118 |
| (Address of principal executive offices) | (Zip Code) |
| | (405) | 848-8000 | |
| (Registrant’s telephone number, including area code) |
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| Securities registered pursuant to Section 12(b) of the Act: |
| Title of each class | | Trading Symbol(s) | | Name of each exchange on which registered |
| Common Stock, $0.01 par value per share | | EXE | | The Nasdaq Stock Market LLC |
| Class A Warrants to purchase Common Stock | | EXEEW | | The Nasdaq Stock Market LLC |
| Class B Warrants to purchase Common Stock | | EXEEZ | | The Nasdaq Stock Market LLC |
| Class C Warrants to purchase Common Stock | | EXEEL | | The Nasdaq Stock Market LLC |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
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 (§ 232.405 of this chapter) 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.
Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐
Smaller reporting company ☐ Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to § 240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☒ No ☐
The aggregate market value of our common stock held by non-affiliates on June 28, 2024 was approximately $6.5 billion. As of February 19, 2025, there were 232,699,939 shares of our common stock outstanding.
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DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement for the 2025 Annual Meeting of Stockholders are incorporated by reference in Part III.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
FORM 10-K
TABLE OF CONTENTS
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| PART I | Page |
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| PART II | |
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| PART III | |
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| PART IV | |
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| Explanatory Note and Definitions |
On October 1, 2024, Chesapeake Energy Corporation completed its previously announced merger with Southwestern Energy Company. In connection with the Southwestern Merger, Chesapeake Energy Corporation changed its name to Expand Energy Corporation.
Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Expand Energy,” the “Company” and “Registrant” refer to Expand Energy Corporation and its consolidated subsidiaries. All monetary values, other than per unit and per share amounts, are stated in millions of U.S. dollars unless otherwise specified. The following are other abbreviations and definitions of certain terms used within this Annual Report on Form 10-K (this “Form 10-K” or this “report”):
“Adjusted Free Cash Flow” (a non-GAAP measure) means net cash provided by operating activities (GAAP) less cash capital expenditures and contributions to investments, adjusted to exclude certain items management believes affect the comparability of operating results.
“ASC” means Accounting Standards Codification.
“ASU” means Accounting Standards Update.
“Bankruptcy Code” means Title 11 of the United States Code, 11 U.S.C. §§ 101–1532, as amended.
“Bankruptcy Court” means the United States Bankruptcy Court for the Southern District of Texas.
“Bbl” or “Bbls” means one stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
“Bcf” means billion cubic feet.
“Bcfe” means billion cubic feet of natural gas equivalent.
“BLM” means the Bureau of Land Management.
“Chapter 11 Cases” means, when used with reference to a particular Debtor, the case pending for that Debtor under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court, and when used with reference to all the Debtors, the procedurally consolidated Chapter 11 cases pending for the Debtors in the Bankruptcy Court.
“Chesapeake” means Chesapeake Energy Corporation, prior to the Southwestern Merger.
“Chief” means Chief E&D Holdings, LP.
“Class A Warrants” means warrants to purchase 10 percent of the common stock (after giving effect to the Rights Offering, but subject to dilution by the Management Incentive Plan, the Class B Warrants, and the Class C Warrants), at an initial exercise price per share of $27.63. The Class A Warrants are exercisable from the Effective Date until February 9, 2026.
“Class B Warrants” means warrants to purchase 10 percent of the common stock (after giving effect to the Rights Offering, but subject to dilution by the Management Incentive Plan and the Class C Warrants), at an initial exercise price per share of $32.13. The Class B Warrants are exercisable from the Effective Date until February 9, 2026.
“Class C Warrants” means warrants to purchase 10 percent of the common stock (after giving effect to the Rights Offering, but subject to dilution by the Management Incentive Plan), at an initial exercise price per share of $36.18. The Class C Warrants are exercisable from the Effective Date until February 9, 2026.
“Completion” means the process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas, oil or natural gas liquids, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.
“Confirmation Order” means the order confirming the Fifth Amended Joint Chapter 11 Plan of Reorganization of Chesapeake Energy Corporation and its Debtor Affiliates, Docket No. 2915, entered by the Bankruptcy Court on January 16, 2021.
“Credit Facility” means the reserve-based credit facility entered into on December 9, 2022.
“DD&A” means depreciation, depletion and amortization.
“Debtors” means Chesapeake Energy Corporation prior to the Southwestern Merger, together with all of its direct and indirect subsidiaries that have filed the Chapter 11 Cases.
“DEI” means diversity, equity and inclusion.
“Developed Acreage” means acres which are allocated or assignable to producing wells or wells capable of production.
“Dry Well” means a well found to be incapable of producing either natural gas or oil in sufficient quantities to justify completion as a natural gas or oil well.
“Effective Date” means February 9, 2021.
“ESG” means environmental, social and governance.
“Exit Credit Facility” means the reserve-based credit facility available upon emergence from bankruptcy. In December 2022, we terminated the Exit Credit Facility.
“Exploratory Well” means a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well.
“FASB” means the Financial Accounting Standards Board.
“Formation” means a succession of sedimentary beds that were deposited under the same general geologic conditions.
“Free Cash Flow” (a non-GAAP measure) means net cash provided by operating activities (GAAP) less cash capital expenditures.
“G&A” means general and administrative expenses.
“GAAP” means U.S. generally accepted accounting principles.
“General Unsecured Claim” means any Claim against any Debtor that is not otherwise paid in full during the Chapter 11 Cases pursuant to an order of the Bankruptcy Court and is not an Administrative Claim, a Priority Tax Claim, an Other Priority Claim, an Other Secured Claim, a Revolving Credit Facility Claim, a FLLO Term Loan Facility Claim, a Second Lien Notes Claim, an Unsecured Notes Claim, an Intercompany Claim, or a Section 510(b) Claim.
“Gross Acres or Gross Wells” means the total acres or wells, as the case may be, in which a working interest is owned.
“LNG” means liquefied natural gas.
“LTIP” means the Expand Energy Corporation 2021 Long Term Incentive Plan.
“Marcellus Acquisition” means our acquisition of Chief and associated non-operated interests held by affiliates of Radler and Tug Hill, which closed on March 9, 2022, with an effective date of January 1, 2022.
“MBbls” means one thousand barrels of oil or other liquid hydrocarbons.
“MMBbls” means one million barrels of oil or other liquid hydrocarbons.
“Mcf” means thousand cubic feet.
“Mcfe” means one thousand cubic feet of natural gas equivalent, with one barrel of oil or NGL converted to an equivalent volume of natural gas using the ratio of one barrel of oil or NGL to six Mcf of natural gas.
“MMcf” means million cubic feet.
“MMcfe” means million cubic feet of natural gas equivalent.
“Net Acres or Net Wells” means the sum of the fractional working interests owned in gross acres or gross wells.
“NGL” means natural gas liquids.
“NYMEX” means New York Mercantile Exchange.
“OPEC+” means the Organization of the Petroleum Exporting Countries Plus.
“Petition Date” means June 28, 2020, the date on which the Debtors commenced the Chapter 11 Cases.
“Plan” means the Fifth Amended Joint Chapter 11 Plan of Reorganization of Chesapeake Energy Corporation and its Debtor Affiliates, attached as Exhibit A to the Confirmation Order.
“Play” means a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential natural gas, oil and NGL reserves.
“Present Value of Estimated Future Net Revenues” or “PV-10” (non-GAAP)” means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices calculated as the average natural gas and oil price during the preceding 12-month period prior to the end of the current reporting period, (determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period) and costs in effect at the determination date (unless such costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.
“Price Differential” means the difference in the price of natural gas, oil or NGL received at the sales point and the NYMEX price.
“Productive Well” means a well that is not a dry well. Productive wells include producing wells and wells that are mechanically capable of production.
“Proved Developed Reserves” means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.
“Proved Properties” means properties with proved reserves.
“Proved Reserves” has the meaning given to such term in Rule 4-10(a)(22) of Regulation S-X, which states in part proved natural gas and oil reserves are those quantities of natural gas and oil, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
“Proved Undeveloped Reserves (PUDs)” means proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
“Radler” means Radler 2000 Limited Partnership.
“Reservoir” means a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
“Rights Offering” means the common stock rights offering for the Rights Offering Amount consummated by the Debtors on the Effective Date.
“SEC” means United States Securities and Exchange Commission.
“SOFR” means a rate equal to the secured overnight financing rate as administered by the SOFR Administrator, the Federal Reserve Bank of New York (or a successor administrator of the secured overnight financing rate).
“Southwestern” means Southwestern Energy Company.
“Southwestern Merger” means Chesapeake’s merger with Southwestern, which closed on October 1, 2024.
“Standardized Measure” means the discounted future net cash flows relating to proved reserves based on the means of the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices calculated as the average natural gas and oil price during the preceding 12-month period prior to the end of the current reporting period (determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period). The standardized measure differs from the PV-10 measure only because the former includes the effects of estimated future income tax expenses.
“Tcf” means trillion cubic feet.
“Tcfe” means trillion cubic feet of natural gas equivalent.
“Tug Hill” means Tug Hill, Inc.
“Undeveloped Acreage” means acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of natural gas and oil regardless of whether the acreage contains proved reserves.
“Unproved Properties” means properties with no proved reserves.
“Vine” means Vine Energy Inc.
“Vine Acquisition” means our acquisition of Vine, which closed on November 1, 2021.
“Warrants” means, collectively, the Class A Warrants, Class B Warrants and Class C Warrants.
“Working Interest” means the operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
“WTI” means West Texas Intermediate.
“/Bbl” means per barrel.
“/Mcf” means per Mcf.
“/Mcfe” means per Mcfe.
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| Forward-Looking Statements |
This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). Forward-looking statements include our current expectations or forecasts of future events, including matters relating to armed conflict and instability in Europe and the Middle East, along with the effects of the current global economic environment, and the impact of each on our business, financial condition, results of operations and cash flows, actions by, or disputes among or between, members of OPEC+ and other foreign oil-exporting countries, market factors, market prices, our ability to meet debt service requirements, our ability to continue to pay cash dividends, the amount and timing of any cash dividends and our ESG initiatives. Forward-looking and other statements in this Form 10-K regarding our environmental, social and other sustainability plans and goals are not an indication that these statements are necessarily material to investors or required to be disclosed in our filings with the SEC. In addition, historical, current, and forward-looking environmental, social and sustainability-related statements may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve, and assumptions that are subject to change in the future. Forward-looking statements often address our expected future business, financial performance and financial condition, and often contain words such as “aim,” “predict,” “should,” "expect," “could,” “may,” "anticipate," "intend," "plan," “ability,” "believe," "seek," "see," "will," "would," “estimate,” “forecast,” "target," “guidance,” “outlook,” “opportunity” or “strategy.”
Although we believe the expectations and forecasts reflected in our forward-looking statements are reasonable, they are inherently subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. No assurance can be given that such forward-looking statements will be correct or achieved or that the assumptions are accurate or will not change over time. Particular uncertainties that could cause our actual results to be materially different than those expressed in our forward-looking statements include:
•Reduced demand for natural gas, oil and natural gas liquids;
•negative public perceptions of our industry;
•competition in the natural gas and oil exploration and production industry;
•the volatility of natural gas, oil and NGL prices, which are affected by general economic and business conditions, as well as increased demand for (and availability of) alternative fuels and electric vehicles;
•risks from regional epidemics or pandemics and related economic turmoil, including supply chain constraints;
•write-downs of our natural gas and oil asset carrying values due to low commodity prices;
•significant capital expenditures are required to replace our reserves and conduct our business;
•our ability to replace reserves and sustain production;
•uncertainties inherent in estimating quantities of natural gas, oil and NGL reserves and projecting future rates of production and the amount and timing of development expenditures;
•drilling and operating risks and resulting liabilities;
•our ability to generate profits or achieve targeted results in drilling and well operations;
•leasehold terms expiring before production can be established;
•risks from our commodity price risk management activities;
•uncertainties, risks and costs associated with natural gas and oil operations;
•our need to secure adequate supplies of water for our drilling operations and to dispose of or recycle the water used;
•pipeline and gathering system capacity constraints and transportation interruptions;
•risks related to our plans to participate in the global LNG value chain;
•terrorist activities and/or cyber-attacks adversely impacting our operations;
•risks from failure to protect personal information and data and compliance with data privacy and security laws and regulations;
•disruption of our business by natural or human causes beyond our control;
•a deterioration in general economic, business or industry conditions;
•the impact of inflation and commodity price volatility, including as a result of decisions made by OPEC+ and armed conflict and instability in Europe and the Middle East, along with the effects of the current global economic environment, on our business, financial condition, employees, contractors, vendors and the global demand for natural gas and oil and on U.S. and global financial markets;
•our inability to access the capital markets on favorable terms;
•the limitations on our financial flexibility due to our level of indebtedness and restrictive covenants from our indebtedness;
•challenges with employee retention and increasingly competitive labor market;
•risks related to acquisitions or dispositions, or potential acquisitions or dispositions; risks related to loss of management personnel, other key employees, customers, suppliers, vendors, landlords, joint venture partners and other business partners as a result of the Southwestern Merger; the risk that problems may arise in successfully integrating the businesses of the companies, which may result in the combined company not operating as effectively and efficiently as expected; and the risk that the combined company may be unable to achieve synergies or other anticipated benefits of the Southwestern Merger or it may take longer than expected to achieve those synergies or benefits;
•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;
•our ability to achieve and maintain ESG certifications, goals and commitments;
•environmental and ESG legislation and regulatory initiatives, including those addressing the impact of climate change or further regulating hydraulic fracturing, methane emissions, flaring or water disposal;
•federal and state tax proposals affecting our industry;
•risks related to an annual limitation on the utilization of our tax attributes, which was triggered upon the completion of the Southwestern Merger, as well as trading in our common stock, additional issuance of common stock, and certain other stock transactions, which could lead to an additional, potentially more restrictive, annual limitation; and
•other factors that are described under Risk Factors in Item 1A of Part I of this Form 10-K.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. The reserve data represents only estimates which may differ from the actual quantities of natural gas, oil and NGL that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the associated present value are based upon certain assumptions, including prices, future production levels and costs that may not prove correct. Future prices and costs may be materially higher or lower than the prices and costs as of the date of any estimate. See Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities included in Item 8 of Part II of this report for further discussion of our reserve quantities. We caution you not to place undue reliance on the forward-looking statements contained in this report, which speak only as of the filing date, and we undertake no obligation and have no intention to update this information, except as required by law. We urge you to carefully review and consider the disclosures in this report and our other filings with the SEC that attempt to advise interested parties of the risks and factors that may affect our business.
All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.
PART I
Unless the context otherwise requires, references to “Expand Energy,” the “Company,” “us,” “we,” “our” and “ours” in this report are to Expand Energy Corporation together with its subsidiaries. Our principal executive offices are located at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118, and our main telephone number at that location is (405) 848-8000.
Expand Energy is the largest independent natural gas producer in the U.S., based on net daily production, and is focused on responsibly developing an abundant supply of natural gas, oil and NGL to expand energy access for all. Our operations are located in Louisiana in the Haynesville and Bossier Shales (“Haynesville”), in Pennsylvania in the Marcellus Shale (“Northeast Appalachia”) and in West Virginia and Ohio in the Marcellus and Utica Shales (“Southwest Appalachia”) and include interests in approximately 8,000 gross natural gas and oil wells.
On October 1, 2024, we completed the Southwestern Merger, creating a premier energy company that we believe is underpinned by a leading natural gas portfolio adjacent to the highest demand markets, premium inventory, a resilient financial foundation and an investment grade balance sheet. We believe that we are uniquely positioned to deliver affordable, lower-carbon energy to meet growing domestic and international demand while creating sustainable value for stakeholders.
During 2023, we completed our exit from Eagle Ford through three separate divestiture transactions, with aggregate proceeds from these transactions exceeding $3.5 billion, subject to customary post-closing adjustments.
On March 25, 2022, we sold our Powder River Basin assets in Wyoming to Continental Resources, Inc. for approximately $450 million.
On March 9, 2022, we completed our acquisition of Chief, Radler and associated non-operated interests held by affiliates of Tug Hill. Chief, Radler and Tug Hill held producing assets and an inventory of premium drilling locations in the Marcellus Shale in Northeast Pennsylvania.
We make available, free of charge on our website at expandenergy.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. From time to time, we also post announcements, updates, events, investor information and presentations on our website in addition to copies of all recent news releases. Documents and information on our website are not incorporated by reference herein.
The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers, including Expand Energy, that file electronically with the SEC.
Our strategy is to create shareholder value through the responsible development of our significant resource plays while continuing to be a leading provider of natural gas to markets in need. We continue to focus on improving margins through operating efficiencies and financial discipline and improving our ESG performance. To accomplish these goals, we intend to allocate our human resources and capital expenditures to projects we believe offer the highest cash return on capital invested, to deploy leading drilling and completion technology throughout our portfolio, and to take advantage of acquisition and divestiture opportunities to strengthen our portfolio. We also intend to continue to dedicate capital to projects designed to reduce the environmental impact of our production activities.
We focus our acquisition, exploration, development and production efforts in the geographic operating areas described below.
Haynesville - Haynesville and Bossier Shales in Louisiana.
Northeast Appalachia - Marcellus Shale in Pennsylvania.
Southwest Appalachia - Marcellus and Utica Shales in Ohio and West Virginia.
As of December 31, 2024, we held an interest in approximately 8,000 gross productive wells, including 6,200 (4,300 net) wells in which we held a working interest and 1,800 wells in which we held an overriding or royalty interest. Of the 6,200 (4,300 net) wells in which we held a working interest, substantially all were classified as productive natural gas wells. During 2024, we operated 5,500 gross wells and held a non-operating working interest in 700 gross wells. We also completed 81 gross (62 net) wells as operator and participated in another 6 gross and less than one net well completed by other operators. We operate approximately 99% of our current daily production volumes.
The following table sets forth the wells we completed or participated in during the periods indicated. In the table, "gross" refers to the total wells in which we had a working interest and "net" refers to gross wells multiplied by our working interest:
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| | 2024 | | 2023 | | 2022 |
| | Gross | | % | | Net | | % | | Gross | | % | | Net | | % | | Gross | | % | | Net | | % |
| Development: | | | | | | | | | | | | | | | | | | | | | | | |
| Productive | 87 | | | 100 | | | 62 | | | 100 | | | 194 | | | 100 | | | 109 | | | 100 | | | 237 | | | 100 | | | 151 | | | 100 | |
| Dry | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Total | 87 | | | 100 | | | 62 | | | 100 | | | 194 | | | 100 | | | 109 | | | 100 | | | 237 | | | 100 | | | 151 | | | 100 | |
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| Exploratory: | | | | | | | | | | | | | | | | | | | | | | | |
| Productive | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
| Dry | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | 1 | | | 100 | | | 1 | | | 100 | |
| Total | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | | | 1 | | | 100 | | | 1 | | | 100 | |
The following table shows the wells we completed or participated in by operating area:
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| | 2024 | | 2023 | | 2022 |
| | Gross Wells | | Net Wells | | Gross Wells | | Net Wells | | Gross Wells | | Net Wells |
| Haynesville | | 48 | | | 41 | | | 84 | | | 51 | | | 83 | | | 61 | |
| Northeast Appalachia | | 38 | | | 20 | | | 78 | | | 37 | | | 103 | | | 59 | |
| Southwest Appalachia | | 1 | | | 1 | | | — | | | — | | | — | | | — | |
| Eagle Ford | | — | | | — | | | 32 | | | 21 | | | 52 | | | 32 | |
| Total | | 87 | | | 62 | | | 194 | | | 109 | | | 238 | | | 152 | |
As of December 31, 2024, we had 162 gross (128 net) wells in the process of being drilled or completed.
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| Production Volumes, Sales Prices, Production Expenses and Gathering, Processing and Transportation Expenses |
The following tables present information regarding our net production volumes, average sales price received for our production, and production and gathering, processing and transportation expenses per Mcfe for the periods indicated for our significant fields:
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| | Production |
| | Natural Gas (Bcf) | | Oil (MMBbl) | | NGL (MMBbl) | | Total (Bcfe) |
| 2024 | | | | | | |
| Haynesville | | 561 | | — | | | — | | | 561 |
| Northeast Appalachia | | 662 | | — | | | — | | | 662 |
| Southwest Appalachia | | 98 | | 1.2 | | | 7.8 | | | 152 |
| | | | | | | | |
| Total Production | | 1,321 | | 1.2 | | 7.8 | | 1,375 |
| 2023 | | | | | | |
| Haynesville | | 566 | | — | | | — | | | 566 |
| Northeast Appalachia | | 669 | | — | | | — | | | 669 |
| | | | | | | | |
| Eagle Ford | | 31 | | 7.7 | | 3.8 | | 100 |
| Total Production | | 1,266 | | 7.7 | | 3.8 | | 1,335 |
| 2022 | | | | | | |
| Haynesville | | 588 | | — | | | — | | | 588 |
| Northeast Appalachia | | 670 | | — | | | — | | | 670 |
| | | | | | | | |
| Eagle Ford | | 46 | | 18.7 | | 5.8 | | 193 |
| Total Production | | 1,308 | | | 19.4 | | 6.0 | | 1,461 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Average Sales Price of Production(a) | | Expenses ($/Mcfe) |
| | Natural Gas ($/Mcf) | | Oil ($/Bbl) | | NGL ($/Bbl) | | Total ($/Mcfe) | | Production | | GP&T |
| 2024 | | | | | | | | | | |
| Haynesville | | $ | 2.14 | | | $ | — | | | $ | — | | | $ | 2.14 | | | $ | 0.30 | | | $ | 0.58 | |
| Northeast Appalachia | | $ | 1.88 | | | $ | — | | | $ | — | | | $ | 1.88 | | | $ | 0.15 | | | $ | 0.77 | |
| Southwest Appalachia | | $ | 2.42 | | | $ | 60.41 | | | $ | 27.44 | | | $ | 3.42 | | | $ | 0.32 | | | $ | 1.33 | |
| | | | | | | | | | | | |
| Total | | $ | 2.03 | | | $ | 60.41 | | | $ | 27.44 | | | $ | 2.16 | | | $ | 0.23 | | | $ | 0.75 | |
| 2023 | | | | | | | | | | |
| Haynesville | | $ | 2.30 | | | $ | — | | | $ | — | | | $ | 2.30 | | | $ | 0.33 | | | $ | 0.46 | |
| Northeast Appalachia | | $ | 2.22 | | | $ | — | | | $ | — | | | $ | 2.22 | | | $ | 0.12 | | | $ | 0.65 | |
| | | | | | | | | | | | |
| Eagle Ford | | $ | 2.25 | | | $ | 77.80 | | | $ | 25.62 | | | $ | 7.64 | | | $ | 0.91 | | | $ | 1.57 | |
| Total | | $ | 2.25 | | | $ | 77.80 | | | $ | 25.62 | | | $ | 2.66 | | | $ | 0.27 | | | $ | 0.64 | |
| 2022 | | | | | | | | | | |
| Haynesville | | $ | 5.92 | | | $ | — | | | $ | — | | | $ | 5.92 | | | $ | 0.26 | | | $ | 0.53 | |
| Northeast Appalachia | | $ | 6.03 | | | $ | — | | | $ | — | | | $ | 6.03 | | | $ | 0.11 | | | $ | 0.57 | |
| | | | | | | | | | | | |
| Eagle Ford | | $ | 5.64 | | | $ | 96.10 | | | $ | 36.76 | | | $ | 11.76 | | | $ | 1.22 | | | $ | 1.78 | |
| Total | | $ | 5.96 | | | $ | 96.07 | | | $ | 37.48 | | | $ | 6.77 | | | $ | 0.33 | | | $ | 0.73 | |
___________________________________________(a) Excludes the effect of hedging.
| | |
| Natural Gas, Oil and NGL Reserves |
The tables below set forth information as of December 31, 2024, with respect to our estimated proved reserves, the associated estimated future net revenue, the present value of estimated future net revenue and the standardized measure of discounted future net cash flows. None of the estimated future net revenue, PV-10 nor the standardized measure are intended to represent the current market value of the estimated natural gas, oil and NGL reserves we own. All of our estimated reserves are located within the United States.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2024 |
| | Natural Gas | | Oil | | NGL | | Total |
| | (Bcf) | | (MMBbl) | | (MMBbl) | | (Bcfe) |
| Proved developed | | 14,418 | | | 40.3 | | | 383.0 | | | 16,958 | |
| Proved undeveloped | | 2,506 | | | 27.6 | | | 195.1 | | | 3,842 | |
Total proved(a) | | 16,924 | | | 67.9 | | | 578.1 | | | 20,800 | |
| | | | | | | | | | | | | | | | | | | | |
| | Proved Developed | | Proved Undeveloped | | Total Proved |
Standardized measure(b) | | | | | | $ | 7,531 | |
Estimated future net revenue(b) | | $ | 10,620 | | | $ | 3,049 | | | $ | 13,669 | |
Present value of estimated future net revenue (PV-10)(b) | | $ | 6,519 | | | $ | 1,048 | | | $ | 7,567 | |
___________________________________________
(a) Haynesville, Northeast Appalachia and Southwest Appalachia accounted for approximately 19%, 39% and 42%, respectively, of our estimated proved reserves by volume as of December 31, 2024.
(b) Estimated future net revenue represents the estimated future revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using pricing differentials and costs under existing economic conditions as of December 31, 2024, and assuming commodity prices as set forth below. For the purpose of determining prices used in our reserve reports, we used the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2024. The price used in our PV-10 measure was $2.13 per Mcf of natural gas and $75.48 per Bbl of oil and NGL, before basis differential adjustments. These prices should not be interpreted as a prediction of future prices, nor do they reflect the value of our commodity derivative instruments in place as of December 31, 2024. The amounts shown do not give effect to non-property-related expenses, such as corporate general and administrative expenses and debt service, or to depreciation, depletion and amortization. The present value of estimated future net revenue typically differs from the standardized measure because the former does not include the effects of estimated future income tax expense of $36 million as of December 31, 2024.
Management uses PV-10, which is calculated without deducting estimated future income tax expenses, as a measure of the value of the Company's current proved reserves and to compare relative values among peer companies. We also understand that securities analysts and rating agencies use this measure in similar ways. While estimated future net revenue and the present value thereof are based on prices, costs and discount factors which may be consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. PV-10, a non-GAAP measure, should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company's financial or operating performance presented in accordance with GAAP.
A comparison of the standardized measure of discounted future net cash flows to PV-10 is presented above. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our proved natural gas and oil reserves.
As of December 31, 2024, our proved reserve estimates included 3,842 Bcfe of reserves classified as proved undeveloped, compared to 3,325 Bcfe as of December 31, 2023. Presented below is a summary of changes in our proved undeveloped reserves for 2024:
| | | | | | | | |
| | Total |
| | (Bcfe) |
| Proved undeveloped reserves, beginning of period | | 3,325 | |
| Extensions and discoveries | | 55 | |
| Revisions of previous estimates | | (1,625) | |
| Conversion to proved developed reserves | | (1,050) | |
| Purchase of reserves-in-place | | 3,137 | |
| Sales of reserves-in-place | | — | |
| Proved undeveloped reserves, end of period | | 3,842 | |
As of December 31, 2024, all PUDs were planned to be developed within five years of original recording. In 2024, we invested approximately $395 million to convert 1,050 Bcfe of PUDs to proved developed reserves. We added 55 Bcfe of PUD reserves through extensions and discoveries due to new PUDs added in Northeast Appalachia. We had a net downward revision in previous estimates of 1,625 Bcfe. The net downward revision primarily consisted of 2,022 Bcfe of downward revisions due to lower natural gas, oil and NGL prices in 2024, and a downward revision of 183 Bcfe due to development plan changes in Northeast Appalachia and Haynesville, partially offset by 462 Bcfe of positive revisions on existing PUD locations primarily related to increased production forecasts, increased ownership interest in the locations, and improved differentials in the Haynesville, as well as 118 Bcfe of PUDs added in areas previously categorized as proved in Northeast Appalachia and Haynesville. We added 3,137 Bcfe of PUDs through purchase of reserves-in-place, primarily as a result of the Southwestern Merger.
The future net revenue attributable to our estimated PUDs was $3.0 billion, and the present value was $1.0 billion as of December 31, 2024. These values were calculated assuming that we will expend approximately $1.8 billion to develop these reserves ($739 million in 2025, $546 million in 2026, $530 million in 2027, $8 million in 2028 and $7 million in 2029). The amount and timing of these expenditures will depend on a number of factors, including actual drilling results, service costs, commodity prices and the availability of capital. Our developmental drilling schedules are subject to revision and reprioritization throughout the year resulting from unknowable factors such as commodity prices, unexpected developmental drilling results, title issues and infrastructure availability or constraints.
As of December 31, 2024, approximately 1,606 Bcfe, or 8%, of our total proved reserves were developed and non-producing, primarily due to our deferred turn in line program.
Our ownership interest used for calculating proved reserves and the associated estimated future net revenue assumes maximum participation by other parties to our farm-out and participation agreements.
Our estimated proved reserves and the standardized measure of discounted future net cash flows of the proved reserves as of December 31, 2024, 2023 and 2022, along with the changes in quantities and standardized measure of the reserves for each of the three years then ended, are shown in Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities included in Item 8 of Part II of this report. No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the SEC. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. The reserve data represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured exactly, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary. Accordingly, reserve estimates often differ from the actual quantities of natural gas, oil and NGL that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the associated present value are based upon certain assumptions, including prices, future production levels and costs that may not prove correct. Future prices and costs may be materially higher or
lower than the prices and costs as of the date of any estimate. See Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities included in Item 8 of Part II of this report for further discussion of our reserve quantities. Reserves Estimation
We engaged Netherland, Sewell & Associates, Inc., a third-party engineering firm, to audit our total proved reserves as of December 31, 2024. A copy of the audit letter issued by the engineering firm is filed with this report as Exhibit 99.1. The qualifications of the technical persons at the firm primarily responsible for overseeing the audit of our reserve estimates are set forth below.
•Over 43 combined years of practical experience in the estimation and evaluation of reserves;
•Licensed Professional Engineer in the State of Texas and Bachelor of Science degree in Chemical Engineering;
•Licensed Professional Geoscientist in the State of Texas and Bachelor of Science and Master of Science degrees in Geology.
Our Corporate Reserves Department prepared our estimated proved reserves as of December 31, 2024 disclosed in this report. Those estimates were established utilizing standard geological and engineering technologies, which are generally accepted by the petroleum industry and were based upon the best available production, engineering and geologic data. These technologies, including computational methods, provide reasonable certainty in our reserves estimation and include technologies and inputs such as drilling results and well performance, decline curve analysis of wells in analogous reservoirs, material balance, volumetric calculation, statistical analysis, well logs, geologic maps and seismic data.
Our Manager – Corporate Reserves, who is in charge of our Corporate Reserves Department, is the technical person primarily responsible for overseeing the preparation of our reserve estimates and for coordinating any reserves work conducted by a third-party engineering firm. His qualifications include the following:
•Over 17 years of practical experience in the oil and gas industry, with over 15 years in reservoir engineering;
•Licensed Professional Engineer (Petroleum) in the State of Oklahoma;
•Member in good standing of the Society of Petroleum Evaluation Engineers;
•Bachelor of Science in Mechanical Engineering; and
•Masters of Business Administration.
We ensure that the key members of our Corporate Reserves Department have appropriate technical qualifications to oversee the preparation of reserve estimates. Our engineering technicians have a minimum of a four-year degree in mathematics, economics, finance or other technical/business/science field. We maintain a continuous education program for our engineers and technicians on new technologies and industry advancements as well as refresher training on basic skills and analytical techniques.
We maintain internal controls such as the following to ensure the reliability of reserves estimations:
•We follow comprehensive SEC-compliant internal policies to estimate and report proved reserves. Reserve estimates are made by experienced reservoir engineers or under their direct supervision. All material changes are reviewed and approved by the Manager – Corporate Reserves.
•The Corporate Reserves Department reviews our proved reserves at the close of each quarter.
•Each quarter, Reservoir Managers, the Manager – Corporate Reserves, the Vice Presidents of each operating area and the Vice President of Corporate and Strategic Planning review all significant reserves changes and all new proved undeveloped reserves additions.
•The Corporate Reserves Department reports independently of our operations.
•The five-year PUD development plan is reviewed and approved annually by the Manager – Corporate Reserves and the Vice President of Corporate and Strategic Planning.
The following table sets forth our gross and net developed and undeveloped natural gas and oil leasehold and fee mineral acreage as of December 31, 2024. Gross acres are the total number of acres in which we own a working interest. Net acres refer to gross acres multiplied by our fractional working interest.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Developed Leasehold | | Undeveloped Leasehold | | Total |
| | Gross Acres | | Net Acres | | Gross Acres | | Net Acres | | Gross Acres | | Net Acres |
| | (in thousands) |
| Haynesville | | 698 | | | 586 | | | 91 | | | 78 | | | 789 | | | 664 | |
| Northeast Appalachia | | 754 | | | 501 | | | 242 | | | 199 | | | 996 | | | 700 | |
| Southwest Appalachia | | 267 | | | 204 | | | 493 | | | 362 | | | 760 | | | 566 | |
Other(a) | | 310 | | | 290 | | | 1,346 | | | 1,265 | | | 1,656 | | | 1,555 | |
| Total | | 2,029 | | | 1,581 | | | 2,172 | | | 1,904 | | | 4,201 | | | 3,485 | |
___________________________________________
(a) Includes 1.2 million net acres retained in the 2016 divestiture of our Devonian Shale assets, in which we retained all rights below the base of the Kope formation.
Most of our leases have a three- to five-year primary term, and we manage lease expirations to ensure that we do not experience unintended material expirations. Our leasehold management efforts include scheduling our drilling to establish production in paying quantities in order to hold leases by production, timely exercising our contractual rights to pay delay rentals to extend the terms of leases we value, planning non-core divestitures to high-grade our lease inventory and letting some leases expire that are no longer part of our development plans. We do not anticipate any material lease expirations within the next three years.
The principal function of our marketing operations is to provide natural gas, oil and NGL marketing services, including commodity price structuring, securing and negotiating of gathering, hauling, processing and transportation services, contract administration and nomination services for us and other interest owners in Expand Energy-operated wells. The marketing operations also provide other services for our exploration and production activities, including services to enhance the value of natural gas and oil production by aggregating volumes sold to various intermediary markets, end markets and pipelines. This aggregation allows us to attract larger, more creditworthy customers that in turn assist in maximizing the prices received.
Generally, our natural gas and NGL production are sold to purchasers under index contracts or daily spot price contracts. Under our index contracts, the price we receive is tied to published indices. Under our daily spot price contracts, we receive the daily spot price at the location where the gas or NGL are sold. Oil production is sold under short-to-long-term market-sensitive and spot price contracts using a differential to NYMEX WTI.
We have entered into long-term gathering, processing, and transportation contracts with various parties that require us to deliver fixed, determinable quantities of production over specified periods of time. Certain of our contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under these commitments. See Note 5 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion of commitments. As of December 31, 2024, we had delivery commitments for gas and NGLs of approximately 6,900 Bcf and 45 MMBbls over the next 16 and 18 years, respectively. These delivery commitments vary each year. Additionally, we have delivery commitments of approximately 1 MMBbls of oil during 2025. We expect to fulfill these commitments primarily with production from our proved developed reserves.
| | |
| Oilfield Services Vertical Integration |
The Company also operates drilling rigs and provides certain oilfield products and services, principally serving the Company’s E&P operations through vertical integration.
For the year ended December 31, 2024, we had no purchaser that accounted for 10% or greater of our total revenues (before the effects of hedging). For the year ended December 31, 2023, we had sales to two purchasers that accounted for approximately 17% and 10% of total revenues (before the effects of hedging). For the year ended December 31, 2022, we had sales to two purchasers that accounted for approximately 13% and 10% of total revenues (before the effects of hedging). No other purchasers accounted for more than 10% of our total revenues during the years ended December 31, 2023 or 2022.
We compete with both major integrated and other independent natural gas and oil companies in all aspects of our business to explore, develop and operate our properties and market our production. Some of our competitors may have larger financial and other resources than us. Competitive conditions may be affected by future legislation and regulations as the United States develops new energy and climate-related policies. In addition, some of our competitors may have a competitive advantage when responding to factors that affect demand for natural gas and oil production, such as changing prices, domestic and foreign political conditions, weather conditions, the price and availability of alternative fuels, the proximity and capacity of natural gas pipelines and other transportation facilities and overall economic conditions. We also face indirect competition from alternative energy sources, including wind, solar and electric power. We believe that our technological expertise, combined with our exploration, land, drilling and production capabilities and the experience of our management team, enables us to compete effectively.
| | |
| Public Policy and Government Regulation |
All of our operations are conducted onshore in the United States. Our industry is subject to a wide range of regulations, laws, rules, taxes, fees and other policy implementation actions that are under constant review for amendment or expansion. Numerous government agencies have issued extensive regulations that are binding on our industry, some of which carry substantial penalties for failure to comply. These laws and regulations increase the cost of doing business. We anticipate that compliance with existing laws and regulations governing our current operations will not have a material adverse effect on our capital expenditures, earnings or competitive position. However, additional proposals that affect the oil and gas industry are regularly considered by Congress, the states, regulatory agencies and the courts, and we cannot predict when or whether any such proposals may become effective or the effect that such proposals may have on us. We actively monitor regulatory developments applicable to our industry in order to anticipate, design and implement required compliance activities and systems. The following is a summary of the existing laws, rules and regulations to which our operations are subject.
Exploration and Production, Environmental, Health and Safety and Occupational Laws and Regulations
Our operations are subject to federal, tribal, state, and local laws and regulations. These laws and regulations relate to matters that include, but are not limited to, the following:
•reporting of workplace injuries and illnesses;
•industrial hygiene monitoring;
•worker protection and workplace safety;
•approval or permits to drill and to conduct operations;
•provision of financial assurances (such as bonds) covering drilling and well operations;
•calculation and disbursement of royalty payments and production taxes;
•seismic operations/data;
•location, drilling, cementing and casing of wells;
•well design and construction of pad and equipment;
•construction and operations activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species, their habitats, or sites of cultural significance;
•method of well completion and hydraulic fracturing;
•water withdrawal;
•well production and operations, including processing and gathering systems;
•emergency response, contingency plans and spill prevention plans;
•emissions and discharges permitting;
•climate change;
•use, transportation, storage and disposal of fluids and materials incidental to natural gas and oil operations;
•surface usage, maintenance, monitoring and the restoration of properties associated with well pads, pipelines, impoundments and access roads;
•plugging and abandoning of wells; and
•transportation of production.
In November 2021, the Environmental Protection Agency (the “EPA”) proposed new regulations to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from new, modified, reconstructed and existing facilities in the oil and gas sector. The EPA issued a supplemental proposed rule in November 2022 to update, strengthen and expand its November 2021 proposed rule. The proposed rules sought to make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the Clean Air Act (“CAA”) (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). The November 2022 supplemental proposed rule removed an emissions monitoring exemption for small wellhead-only sites and created a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters”. In addition, the proposed rules sought to establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. In December 2023, the EPA issued the final rule, which imposes more stringent requirements on the natural gas and oil industry, requiring all well sites and compressor stations to be routinely monitored for leaks and eliminating or minimizing emissions from common pieces of equipment used in oil and gas operations, such as process controllers, pumps, and storage tanks. Notably, the EPA updated the applicability date for Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance dates under state plans. The final rule gives states, along with federal tribes that wish to regulate existing sources, until March 2026 to develop and submit their plans for reducing methane from existing sources. The final emissions guidelines under Subpart OOOOc provide until 2029 for existing sources to comply. Fines and penalties for violation of these rules can be substantial. However, the final rule is subject to ongoing litigation but remains in effect. Additionally, in January 2025, the Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (the “PHMSA”) finalized a rule that requires pipelines, underground natural gas storage facilities, and liquefied natural gas facilities to update leak detection and repair programs to require companies to use commercially available technologies to find and fix methane leaks from pipelines and other facilities. These rules and policy priorities could have a material adverse effect on our financial position, results of operations and cash flows. However, in January 2025, the current Presidential Administration issued an executive order directing the heads of all federal agencies to identify and begin the process to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. Consequently, the future implementation and enforcement of these rules remain uncertain at this time.
The Inflation Reduction Act (“IRA”), signed into law in August 2022, provides significant funding and incentives for research, development and implementation of low-carbon energy production methods, carbon capture, and other programs directed at addressing climate change. The IRA also includes a Methane Emissions Reduction Program that amends the CAA to require the EPA to impose a “Waste Emissions Charge” on methane emissions from certain natural gas and oil sources that are already required to report under EPA’s Greenhouse Gas Reporting Program. In May 2024, the EPA finalized revisions to the Greenhouse Gas Reporting Program for petroleum and natural gas facilities. Among other things, the final rule expands the emissions events that are subject to reporting requirements to include "other large release events" and applies reporting requirements to certain new sources and sectors. The emissions reported under the Greenhouse Gas Reporting Program will be the basis for any payments under the Methane Emissions Reduction Program in the IRA. However, petitions for reconsideration to the EPA are pending and litigation in the D.C. Circuit Court of Appeals has commenced. In addition, in November 2024, the EPA finalized a rule to implement the IRA’s Waste Emissions Charge that became effective in January 2025. The Waste Emissions Charge imposed under the Methane Emissions Reduction Program for 2024 reported amounts is $900 per metric ton emitted over permitted methane emissions thresholds, and increases to $1,200 for 2025 reported amounts, and $1,500 for 2026 reported amounts. In January 2025, industry associations challenged the Waste Emissions Charge rule in the D.C. Circuit Court of Appeals. Additionally, based on the timing of the rule’s finalization, the Waste Emissions Charge rule is potentially vulnerable to repeal by Congress under the Congressional Review Act. To the extent the rule is implemented, the emissions fee and funding provisions of the law could increase operating costs within the oil and gas industry and accelerate the transition away from fossil fuels, which could in turn adversely affect our business and results of operations. However, in January 2025, the current Presidential Administration issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. The Inflation Reduction Act may also be subject to amendment or repeal through Congressional budget reconciliation. Consequently, future implementation and enforcement of these rules remains uncertain at this time.
In January 2024, the previous Presidential Administration announced a temporary pause on pending decisions on exports of LNG to non-free trade agreement countries until the Department of Energy (“DOE”) can update the underlying analyses for authorizations, including an assessment of the impact of greenhouse gas (“GHG”) emissions. In December 2024, the DOE released its report on LNG exports, which report is subject to a 60-day public comment period ending in February 2025. However, in January 2025, the current Presidential Administration issued an executive order directing the DOE to restart reviews of applications for approvals of LNG export projects as expeditiously as possible.
In addition, several states and geographic regions in the United States have adopted legislation and regulations regarding climate change-related matters, and additional legislation or regulation by these states and regions, U.S. federal agencies, including the EPA, and/or international agreements to which the United States may become a party could result in increased compliance costs for us and our customers. Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities, administrative, civil or criminal fines or penalties or injunctions limiting our operations in affected areas. In 2021, the previous Presidential Administration recommitted the United States to the Paris Agreement and announced a goal of reducing the United States’ GHG emissions by 50-52% below 2005 levels by 2030. In November 2021, at the 26th Conference of the Parties on the UN Framework Convention on Climate Change (“COP26”), the United States and the European Union jointly announced the Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector. COP26 concluded with the finalization of the Glasgow Climate Pact, which stated long-term global goals (including those in the Paris Agreement) to limit the increase in the global average temperature and emphasized reductions in GHG emissions. At the 27th Conference of the Parties (“COP27”), the previous Presidential Administration announced the EPA’s then-proposed standards to reduce methane emissions from new, modified and existing oil and gas sources, and the United States agreed, in conjunction with the European Union and several other partner countries, to develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. At the 28th Conference of the Parties (“COP28”), member countries entered into an agreement that calls for actions toward achieving, at a global scale, a tripling of renewable energy capacity and doubling energy efficiency improvements by 2030. In April 2024, the European Union adopted a regulation to track and reduce methane emissions in the energy sector, including requiring new monitoring, reporting and verification measures to be applied by importers of oil, natural gas and coal into the European Union by January 1, 2027, and
the “maximum methane intensity values” must be met by 2030 and every year thereafter. Each member state will have the power to impose administrative penalties for failure to comply and the standard will be mandatory for supply contracts signed after the law takes effect. On January 20, 2025, the current Presidential Administration issued an executive order directing the immediate notice to the United Nations of the United States’ withdrawal from the Paris Agreement and all other agreements made under the United Nations Framework Convention on Climate Change. However, various state and local governments in the U.S. have publicly committed to furthering the goals of the Paris Agreement and many of these efforts at the local, state and international levels are expected to continue.
Moreover, multiple environmental laws provide for citizen suits, which allow environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law. We consider the responsibility and costs of environmental protection and safety and health compliance fundamental parts of our business. To date, we have been able to plan for and comply with environmental, safety and health laws and regulations without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increasingly stringent laws, as well as the increasing number of climate-related commitments by capital providers, our capital expenditures and operating expenses related to compliance with environmental and safety and health regulations have increased over time and may continue to increase. In addition, in March 2024, the SEC released its final rule requiring public companies to disclose information regarding material climate-related risks. However, the SEC voluntarily stayed the final rule in April 2024 pending judicial review of multiple petitions challenging the rules and it is unclear when the rule will become effective, if ever. Although future implementation of the final rule and impact on our business is uncertain, compliance with the rule, as finalized, may result in additional legal, accounting and financial compliance costs, make some activities more difficult, time-consuming and costly, and place strain on our personnel, systems and resources. For more information, see Item 1A. Risk Factors - “We are subject to extensive governmental regulation, which can change and could adversely impact our business.”
Our operations also are subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in a unit, the rate of production allowable from gas and oil wells, and the unitization or pooling of gas and oil properties. In the United States, some states allow the statutory pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop gas and oil properties. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ratable purchase of production. These regulations limit the amounts of gas and oil we can produce from our wells and the number of wells or the locations at which we can drill. For further discussion, see Item 1A. Risk Factors - “We are subject to extensive governmental regulation, which can change and could adversely impact our business.”
Regulatory proposals in some states and local communities have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Federal and state agencies have continued to assess the potential impacts of hydraulic fracturing, which could result in additional federal, state and/or local legislation and regulation. Further restrictions of hydraulic fracturing could make it difficult or impossible to conduct our drilling and completion operations, and thereby reduce the amount of natural gas, oil and NGLs that we are ultimately able to produce from our properties.
Certain of our U.S. natural gas and oil leases are granted or approved by the federal government and administered by the U.S. Department of the Interior (“DOI”). Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government, tribes or tribal members. The federal government has increased its review in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding, venting and flaring, gas and oil measurement and royalty payment obligations for production from federal lands. In January 2021, the previous Presidential Administration temporarily paused new oil and gas leases on federal lands and waters pending completion of a comprehensive review of the federal government’s existing oil and gas leasing and permitting program. In June 2021, a federal district court enjoined the DOI from implementing the pause and leasing resumed subject to certain limitations. In August 2022, a federal appeals court vacated and remanded the federal district court’s decision to block the pause on new oil and gas leasing, and the federal district court shortly thereafter enjoined the DOI from implementing the pause in the thirteen plaintiff states, including Louisiana and West Virginia. Litigation over leasing remains ongoing.
However, in January 2025, current Presidential Administration issued executive orders (i) reversing the previous Presidential Administration’s leasing pause and executive orders withdrawing certain lands and waters from federal oil and gas leasing and (ii) directing the heads of all federal agencies to facilitate the leasing, siting, and generation of domestic energy resources, including on federal lands and waters.
In April 2024, the BLM finalized regulations to reduce the waste of natural gas from gas and oil operations on federal and Tribal land. The rule became effective in June 2024. However, in May 2024, North Dakota, Texas, Montana, Wyoming and Utah challenged the rule in federal district court. In September 2024, the court granted a preliminary injunction enjoining BLM from enforcing the rule against the plaintiff states pending the outcome of the litigation, and the litigation remains ongoing. In January 2025, the current Presidential Administration issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. Accordingly, future implementation and enforcement of this rule is uncertain at this time. Any future restrictions surrounding onshore drilling and restrictions on the ability to obtain required permits could have a material adverse impact on our operations.
Obtaining environmental permits has the potential to delay the development and operation of natural gas and oil projects. Delays in obtaining permits or an inability to obtain new permits or permit modifications or renewals could inhibit our ability to execute our drilling and production plans. Failure to comply with applicable regulations or permit requirements could result in revocation of our permits, inability to obtain new permits and the imposition of fines and penalties.
For further discussion, see Item 1A. Risk Factors - “Natural gas and oil operations are uncertain and involve substantial costs and risks.”
Our title to properties is subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the natural gas and oil industry, to liens for current taxes not yet due and to other encumbrances. As is customary in the industry in the case of undeveloped properties, only cursory investigation of record title is made at the time of acquisition. Drilling title opinions are usually prepared before commencement of drilling operations. We believe we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the natural gas and oil industry. Nevertheless, we are involved in title disputes from time to time that may result in litigation.
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| Operating Hazards and Insurance |
The natural gas and oil business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of materials or pollutants. Any of these events could adversely affect our ability to conduct operations or result in substantial loss to us as a result of defending against claims by government agencies or third parties, injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. Our horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations.
We maintain a control of well insurance policy with a $50 million single well limit and a $100 million multiple wells limit that insures against certain sudden and accidental risks associated with drilling, completing and operating our wells. This insurance may not be adequate to cover all losses or exposure to liability. We also carry a $305 million comprehensive general liability umbrella insurance policy. In addition, we maintain a $50 million pollution liability insurance policy providing coverage for gradual pollution related risks and in excess of the general liability policy for sudden and accidental pollution risks. We provide workers' compensation insurance coverage to employees in all states in which we operate. While we believe these policies are customary in the industry, they do not provide complete coverage against all operating risks, and policy limits scale to our working interest percentage in certain situations. In addition, our insurance does not cover penalties or fines that may be assessed by a governmental authority. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. Our insurance coverage may not be sufficient to cover every claim made against us or may not be commercially available for purchase in the future.
We own an office complex in Oklahoma City, Oklahoma and lease an office building in Spring, Texas. Additionally, we own or lease various field offices in cities or towns in the areas where we conduct our operations.
Domenic J. Dell'Osso, Jr., President, Chief Executive Officer and Director
Domenic J. (“Nick”) Dell'Osso, Jr., 48, has served as President and Chief Executive Officer since October 2021. Prior to being named as CEO, Mr. Dell’Osso served as our Executive Vice President and Chief Financial Officer since November 2010. Mr. Dell'Osso served as our Vice President – Finance and Chief Financial Officer of our wholly owned midstream subsidiary, Chesapeake Midstream Development, L.P., from August 2008 to November 2010. Before joining Expand Energy, Mr. Dell’Osso was an energy investment banker with Jefferies & Co. from 2006 to 2008 and Banc of America Securities from 2004 to 2006. Mr. Dell’Osso graduated from Boston College and earned his M.B.A. from the University of Texas at Austin.
Mohit Singh, Executive Vice President and Chief Financial Officer
Mohit Singh, 48, has served as Executive Vice President and Chief Financial Officer since December 2021. Prior to joining Expand Energy, Mr. Singh served for six years on the executive leadership team at BPX Energy, the United States onshore subsidiary of BP plc (NYSE: BP). He most recently led the M&A, corporate land and reserves functions, having previously served as Head of Business Development and Exploration and as Senior Vice President – North Business Unit. Prior to joining BPX, Mr. Singh worked as an investment banker focused on oil and gas transactions for RBC Capital Markets and Goldman Sachs. A chemical engineer by training, he began his career at Shell Exploration & Production Company where he held business planning, reservoir engineering and research engineering roles of increasing importance. Mr. Singh earned a PhD in Chemical Engineering from the University of Houston, an MBA from the University of Texas at Austin and a BTech in Chemical Engineering from the Indian Institute of Technology.
Joshua J. Viets, Executive Vice President and Chief Operating Officer
Joshua J. (“Josh”) Viets, 46, has served as Executive Vice President and Chief Operating Officer since February 2022. Prior to joining Expand Energy, Mr. Viets worked for 20 years in operational positions of increasing importance at ConocoPhillips (NYSE: COP). He most recently served as Vice President, Delaware Basin and previously held leadership positions in operations, engineering, subsurface, and capital project across the ConocoPhillips portfolio. Mr. Viets earned a Bachelor of Science in Petroleum Engineering from Colorado School of Mines.
Christopher W. Lacy, Executive Vice President - General Counsel and Corporate Secretary
Christopher W. (“Chris”) Lacy, 47, has served as Executive Vice President – General Counsel and Corporate Secretary since October 2024. Prior to that time, he served as Senior Vice President, General Counsel and Secretary at Southwestern Energy Company. Mr. Lacy joined Southwestern in 2014 as Chief Litigation Counsel and held various roles of progressively increasing responsibility. Before joining Southwestern, Chris was with Dewey & LeBouef, LLP and Ahmad, Zavitsanos, Anaipakos, Alavi & Mensing P.C. with a practice focused on high value and high stakes litigation. He has nearly 20 years of experience representing clients in the energy industry. Mr. Lacy earned his B.A. in Communication from the University of Texas and his juris doctorate from the University of Houston Law Center.
Daniel F. Turco, Executive Vice President - Marketing and Commercial
Daniel F. (“Dan”) Turco, 45, has served as Executive Vice President – Marketing and Commercial since February 2025. Prior to joining Expand Energy, Mr. Turco served as Head of Global LNG Trading / Head of Asia Gas & Power Marketing in Singapore for ExxonMobil. Mr. Turco joined ExxonMobil in 2006 and has since held positions of increasing responsibility in upstream natural gas marketing and trading, spanning LNG, U.S., Europe and Asia gas markets. Mr. Turco began his career in oil and gas as an engineer. Mr. Turco earned an M.B.A. from Wilfrid Laurier University (Canada) and an Honors Bachelor of Applied Science, Civil Engineering & Management Science from the University of Waterloo (Canada).
Employees
We had approximately 1,700 employees as of December 31, 2024, inclusive of approximately 200 employees temporarily assisting in our efforts to integrate Southwestern. None of our employees were covered by collective bargaining agreements, and our management works to maintain good relations with our employees.
Values-Driven Culture
At Expand Energy, our core values are the foundation of our company. Serving as the lens through which we evaluate business decisions, our commitment to these values, in both words and actions builds a stronger, healthier Expand Energy, benefiting all our stakeholders. Our core values are:
•Stewardship - Safety and environmental stewardship requires excellence in the ordinary
•Character - Integrity in every action
•Collaborate - Commit to continuous improvement through humility, curiosity and constant learning
•Learn - Embrace diverse perspectives, confront the brutal facts, and speak with radical candor
•Disrupt - Challenge the status quo to achieve better outcomes for energy consumers
Diversity, Equity and Inclusion (DEI)
We are committed to supporting inclusion and diversity within our organization. We believe building a diverse workforce and an equitable, inclusive work culture are key drivers of our long-term success. We embrace the variety of backgrounds, perspectives and talents within our organization, leveraging strengths to pursue results and meaningful change for our company, employees, and stakeholders. To support this commitment, we offer education and training for our employees on topics related to inclusion and diversity to help ensure our team is equipped to contribute to an environment of respect, inclusion and collaboration.
Own Safety, Lead Safety
Safety is more than a company metric. It is core to our commitment to leading a responsible energy future. We set and deliver robust safety standards, prioritizing the well-being of our employees and contractors. Our safety culture is championed by our Board of Directors and executive leadership team, owned by every employee and contractor and managed by our Health, Safety, Environmental and Regulatory (HSER) team. Maintaining a safe work environment and promoting safe behaviors is a commitment that each of our employees and contractors own together. We hold each other accountable to keeping our sites, our co-workers and our contractors safe.
One program that reinforces this philosophy of personal responsibility is Stop Work Authority. Through Stop Work Authority, every employee and contractor has the right, responsibility and authority to stop work if conditions are unsafe or could cause harm to the environment. Creating an incident-free work environment starts with setting clear expectations among employees and contractors regarding our Safe and Compliant Operations Policy, safety standards, and working to empower and equip individuals with the skills necessary to promote safety in their areas of work. The foundation of our safety culture is our Own Safety, Lead Safety motto, which encourages all workers on our locations to take personal responsibility for their safety and the safety of those around them. We have transitioned companywide to our Serious Incident and Fatality prevention model for more proactive hazard identification of exposures that could lead to a life-altering injury with verification processes that check for controls in place for these exposures.
Every year our HSER team provides targeted trainings based on safety performance analysis, job functions and location specific factors. Our training program includes a mix of in-person and virtual training, with greater emphasis on in-person instruction and includes all employees. Job-specific learning paths aim to exceed regulatory requirements and ensure employees are holistically prepared to execute their job functions safely and responsibly.
Expand Energy’s training philosophy values contractor training in the same manner as employees. We design contractor training to align as much as possible with employee training, encouraging synchronized knowledge sharing and understanding, critical to decreasing our cumulative incidents.
Ethical Business Conduct
Expand Energy works hard to maintain the confidence of our stakeholders. We earn this trust by striving to act in an ethical manner to protect our people, the environment and the communities where we operate. This starts by driving accountability through all levels of the company and having systems in place to uphold our high standards for conduct. Strong governance practices begin at the top, providing our organization with clear guidelines to define standards for ethical behavior at every level. Each Expand Energy director or employee, regardless of position, must abide by Expand Energy’s Code of Business Conduct (the "Code"), which is structured around our core values. Each year all employees must sign a Code certification acknowledging that they have reviewed the Code and related policies, the high standards expected of them and that they will report actual or potential ethics concerns or Code violations.
Employee Wellness and Benefits
Supporting the individual well-being of our employees is foundational to our safety culture and success as a company. We champion healthy lifestyles and offer health resources. Across the company, employees are offered preventive programs and are encouraged to complete an annual screening for common health-related issues. We support our employees’ and their families’ health by offering full medical, dental, vision, prescription drug insurance for employees and their families, life insurance, short- and long-term disability coverage, and health savings and dependent care flexible spending accounts. We offer parental leave for the birth or adoption of a child, an adoption assistance program, alternate work schedules, a 401(k) savings plan with company match and discretionary contributions, flexible work hours, generous paid time off, including a well-being day, where each employee is encouraged to relax and recharge for a day once per calendar year and 12 company-paid holidays, tuition reimbursement and access to a child development center and fitness center at market rates. Additionally, Expand Energy provides employees and their families access to a confidential Employee Assistance Program, which connects employees with trained counselors and other support professionals.
There are numerous factors that affect our business and results of operations, many of which are beyond our control. The following is a description of factors that we consider to be material and that might cause our future results to differ materially from those currently expected. The risks described below are not the only risks facing our company. Additional risks and uncertainties not presently known to us or that we currently deem immaterial may also affect our business operations. If any of these risks actually occur, our business, financial position, results of operations, cash flows, reserves and/or our ability to pay our debts and other liabilities could suffer, the trading price and liquidity of our securities could decline and you may lose all or part of your investment in our securities.
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| Risks Related to Operating our Business |
•Natural gas, oil and NGL prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse effect on our business.
•Conservation measures and technological advances could reduce demand for natural gas and oil.
•Negative public perception regarding us or our industry could have an adverse effect on our operations.
•The gas and oil exploration and production industry is very competitive; some of our competitors have greater financial and other resources than we do, and there is competition to attract and retain talent and competition over access to certain industry equipment.
•Risks related to potential acquisitions or dispositions may adversely affect our business.
•If commodity prices fall or drilling efforts are unsuccessful, we may be required to record write-downs of the carrying value of our natural gas and oil properties.
•Significant capital expenditures are required to replace our reserves and conduct our business.
•If we are not able to replace reserves, we may not be able to sustain production.
•The actual quantities of and future net revenues from our proved reserves may be less than our estimates.
•Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
•Certain of our undeveloped properties are subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are renewed.
•Our commodity price risk management activities may limit the benefit we would receive from increases in commodity prices, may require us to provide collateral for derivative liabilities and involve risk that our counterparties may be unable to satisfy their obligations to us.
•Natural gas and oil operations are uncertain and involve substantial costs and risks.
•Our ability to produce natural gas, oil and NGLs economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our operations or are unable to dispose of or recycle the water we use economically and in compliance with environmental laws.
•Our operations may be adversely affected by pipeline, trucking and gathering system capacity constraints and may be subject to interruptions that could adversely affect our cash flow.
•Our business strategy is increasingly focused on participating in the global LNG value chain, which is dependent, in part, on the growing U.S. LNG export market, a highly regulated and capital-intensive industry with a number of inherent commercial risks. U.S. LNG exports have helped drive domestic demand for natural gas, and, as a natural gas producer, we could be materially and adversely impacted by a deterioration in the U.S. LNG export industry, which could in turn reduce demand for natural gas. In addition, we may seek to more directly participate in the LNG value chain through direct marketing arrangements with LNG export facilities and/or end users, which could expose us to additional commercial risks associated with the global LNG markets.
•Regional epidemics or pandemics and related economic turmoil, including supply chain constraints, have affected, and could in the future adversely affect our business, financial condition, results of operations and cash flows.
•Cyber-attacks targeting systems and infrastructure used by the gas and oil industry and related regulations may adversely impact our operations and, if we or our third-party providers are unable to obtain and maintain adequate protection for our key systems and data, our business may be harmed.
•We collect, process, store and use personal information and other data, and our actual or perceived failure to protect such information and data or comply with data privacy and security laws and regulations could damage our reputation and brand and harm our business and operating results.
•A deterioration in general economic, political, business or industry conditions would have a material adverse effect on our results of operations, liquidity and financial condition.
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| Financial Risks Related to our Business |
•We have significant capital needs, and our ability to access the capital and credit markets to raise capital on favorable terms is limited by industry conditions.
•Restrictive covenants in certain of our existing and future debt instruments may limit our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.
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| Risks Related to the Company Following the Southwestern Merger |
•Failure to successfully integrate the business of the Company and Southwestern or realize the anticipated benefits of the Southwestern Merger may adversely affect our future results and financial condition.
•The market price of our common stock as a result of the Southwestern Merger may be affected by factors different from those that historically have affected our common stock.
•The Company’s operating results following the Southwestern Merger will suffer if we do not effectively manage our expanded operations.
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| Legal and Regulatory Risks |
•We are subject to extensive governmental regulation, which can change and could adversely impact our business.
•Costs to comply with environmental, health and safety regulations and initiatives can be significant.
•Increasing attention to ESG matters and our ability to achieve and maintain ESG certifications, goals and commitments may impact our business, financial results or stock price.
•The taxation of independent producers is subject to change, and changes in tax law could increase our cost of doing business.
•The completion of the Southwestern Merger triggered an annual limitation on the utilization of our tax attributes, reducing our ability to offset future taxable income, which may result in an increase to income tax liabilities. In addition, trading in our common stock, additional issuance of common stock, and certain other stock transactions could lead to an additional, potentially more restrictive, annual limitation.
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| Risks Related to Operating our Business |
Natural gas, oil and NGL prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse effect on our business.
Our revenues, results of operations, profitability, liquidity, leverage ratio and ability to grow and invest in capital expenditures depend primarily upon the prices we receive for the natural gas, oil and NGL we sell. We incur substantial expenditures to replace reserves, sustain production and fund our business plans. Low natural gas, oil and NGL prices can negatively affect the amount of cash available for capital expenditures, debt service and debt repayment and our ability to borrow money or raise additional capital and, as a result, could have a material adverse effect on our financial condition, results of operations, cash flows and reserves. In addition, periods of low natural gas and oil prices may result in a reduction of the carrying value of our natural gas and oil properties due to recognizing impairments in proved and unproved properties.
Volatility in natural gas, oil and NGL prices may result from factors that are beyond our control, including:
•domestic and worldwide supplies of natural gas, oil and NGL, including U.S. inventories of natural gas and oil reserves;
•weather conditions;
•changes in the level of consumer and industrial demand, including impacts from global or national health events and concerns, such as the COVID-19 pandemic;
•the price and availability of alternative fuels;
•technological advances affecting energy consumption;
•the nature and extent of domestic and international conservation and sustainability initiatives;
•the availability, proximity and capacity of pipelines, other transportation facilities and processing facilities;
•the level and effect of trading in commodity futures markets, including by commodity price speculators and others;
•U.S. exports of natural gas, oil, liquefied natural gas and NGL;
•the price and level of foreign imports;
•the nature and extent of domestic and foreign governmental regulations and taxes;
•the ability of the members of OPEC+ and others to agree to and maintain oil price and production controls;
•increased use of competing energy products, including alternative energy sources;
•political instability or armed conflict in natural gas and oil producing regions, including in connection with the continued armed conflict and instability in Europe and the Middle East;
•acts of terrorism; and
•domestic and global economic and political conditions.
These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas, oil and NGL price movements. In addition, any prolonged period of lower prices could reduce the quantities of reserves that we may economically produce.
Conservation measures and technological advances could reduce demand for natural gas and oil.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to natural gas and oil, technological advances in fuel economy and energy generation devices could reduce demand for natural gas and oil. The impact of the changing demand for natural gas and oil could adversely impact our earnings, cash flows and financial position.
Negative public perception regarding us or our industry could have an adverse effect on our operations.
Negative public perception regarding us or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, waste disposal, oil spills, seismic activity, climate change, explosions of natural gas transmission lines and the development and operation of pipelines and other midstream facilities may lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement priorities. Additionally, environmental groups, landowners, local groups and other advocates may oppose our operations or those of our midstream transportation providers, encourage capital providers to divest of their interests in us or our industry, intervene in regulatory or administrative proceedings involving our assets or those of our midstream transportation providers, or file lawsuits or other actions designed to prevent, disrupt or delay the development or operation of our assets and business or those of our midstream transportation providers. These actions may cause operational delays or restrictions, increased operating and compliance costs, additional regulatory scrutiny and increased risk of litigation, as well as potentially reducing our ability to execute routine or strategic business partnerships. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public can engage in the permitting process, including through intervention in the courts. Changes in public perception could cause the permits we require to conduct our operations to be withheld, delayed or conditioned by requirements that restrict our ability to conduct our business, which could materially adversely affect our industry and our financial condition and results of operations.
Certain financial institutions, funds and other sources of capital have also elected to restrict or eliminate their investment in certain fossil fuel-related activities, which may restrict our access to capital. Even if capital providers have not generally restricted their investment in fossil fuel-related activities, they may still assess various ESG considerations in making voting and capital allocation decisions. Responding to these and other stakeholder concerns on ESG matters may require us to incur additional costs or otherwise impact our business. In addition, the enactment of climate change-related policies and initiatives across the market at the corporate level and/or investor community level may in the future result in reduced demand for our products or stimulate demand for alternative forms of energy that do not rely on combustion of fossil fuels. For more information, see our risk factor “Increasing attention to ESG matters and our ability to achieve and maintain ESG certifications, goals and commitments may impact our business, financial results or stock price.”
The gas and oil exploration and production industry is very competitive; some of our competitors have greater financial and other resources than we do, and there is competition to attract and retain talent and competition over access to certain industry equipment.
We face competition in every aspect of our business, including, but not limited to, buying and selling reserves and leases, obtaining goods and services needed to operate our business and marketing natural gas, oil or NGL. Competitors include multinational oil companies, independent production companies and individual producers and operators. Some of our competitors have greater financial and other resources than we do. As a result, these competitors may be able to address industry challenges more effectively or weather industry downturns more easily than we can. We also face indirect competition from alternative energy sources, including wind, solar and electric power.
Our performance depends largely on the talents and efforts of highly skilled individuals and on our ability to attract new employees and to retain and motivate our existing employees. Competition in our industry for qualified employees is intense. If we are unsuccessful in attracting and retaining skilled employees and managerial talent, our ability to compete effectively may be diminished. In addition, the sudden loss of any of our key executives, their services or our failure to appropriately plan for any expected key executive succession could materially and adversely affect our business and prospects, as we may not be able to find suitable individuals to replace them on a timely basis, if at all. We also compete for the equipment required to explore, develop and operate properties. Typically, during times of rising commodity prices, drilling and operating costs will also increase. During these periods, there is often a shortage of drilling rigs and other oilfield equipment and services, which could adversely affect our ability to execute our development plans on a timely basis and within budget.
Risks related to potential acquisitions or dispositions may adversely affect our business.
From time to time, we evaluate acquisitions and dispositions of assets, businesses and other investments. These transactions may not result in the anticipated benefits or efficiencies. In addition, acquisitions may be financed by borrowings, requiring us to incur more debt, or by the issuance of our common stock. Any such acquisition or disposition involves risks and we cannot assure you that:
•any acquisition will be successfully integrated into our operations and internal controls;
•the due diligence conducted prior to an acquisition will uncover situations that could result in financial or legal exposure, such as title defects and potential environmental and other liabilities;
•post-closing purchase price adjustments will be realized in our favor;
•our assumptions about, among other things, reserves, estimated production, revenues, capital expenditures, operating expenses and costs will be accurate;
•there will not be delays in closing, lower than expected sales proceeds for the disposed assets or business, residual liabilities or post-closing claims for indemnification;
•any investment, acquisition or disposition will not divert management resources from the operation of our business; and
•any investment, acquisition or disposition will not have a material adverse effect on our financial condition, results of operations, cash flows or reserves.
If any of these risks materialize, the benefits of such acquisition or disposition may not be fully realized, if at all, and our financial condition, results of operations, cash flows and reserves could be negatively impacted.
If commodity prices fall or drilling efforts are unsuccessful, we may be required to record write-downs of the carrying value of our natural gas and oil properties.
We have been required to write down the carrying value of certain of our natural gas and oil properties in the past, and there is a risk that we will be required to take additional write-downs in the future. Write-downs may occur in the future when natural gas and oil prices are low for sustained periods, or if we have downward adjustments to our estimated proved reserves, increases in our estimates of operating or development costs or due to the anticipated sale of properties.
The successful efforts method of accounting requires that we periodically review the carrying value of our natural gas and oil properties for possible impairment. Impairment is recognized for the excess of book value over fair value when the book value of a proven property is greater than the expected undiscounted future net cash flows from that property and on acreage when conditions indicate the carrying value is not recoverable. We may be required to write-down the carrying value of a property based on natural gas and oil prices at the time of the impairment review, or as a result of continuing evaluation of drilling results, production data, economics, divestiture activity and other factors. A write-down constitutes a non-cash charge to earnings and does not impact cash or cash flows from operating activities; however, it reflects our long-term ability to recover an investment, reduces our reported earnings and increases certain leverage ratios. See Impairments within Critical Accounting Estimates included in Item 7 of this report for further information.
Significant capital expenditures are required to replace our reserves and conduct our business.
Our exploration, development and acquisition activities require substantial capital expenditures. We intend to fund our capital expenditures through cash flows from operations, and to the extent that is not sufficient, borrowings under our revolving credit facility. Our ability to generate operating cash flow is subject to a number of risks and variables, such as the level of production from existing wells, prices of natural gas, oil and NGLs, our success in developing and producing new reserves and the other risk factors discussed herein. Our forecasted 2025 capital expenditures, inclusive of capitalized interest, are $2.9 - $3.1 billion compared to our 2024 capital spending level of $1.53 billion. Management continues to review operational plans for 2025 and beyond, which could result in changes to projected capital expenditures and projected revenues from sales of natural gas, oil and NGLs. If we are unable to fund our capital expenditures as planned, we could experience a curtailment of our exploration and development activity, a loss of properties and a decline in our natural gas, oil and NGL reserves.
If we are not able to replace reserves, we may not be able to sustain production.
Our future success depends largely upon our ability to find, develop or acquire additional natural gas and oil reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves and production will decline over time. Thus, our future natural gas and oil reserves and production, and therefore our cash flows and income, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves.
The actual quantities of and future net revenues from our proved reserves may be less than our estimates.
The estimates of our proved reserves and the estimated future net revenues from our proved reserves included in this report are based upon various assumptions, including assumptions required by the SEC relating to natural gas, oil and NGL prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating natural gas, oil and NGL reserves is complex and involves significant decisions and assumptions associated with geological, geophysical, engineering and economic data for each well. Therefore, these estimates are subject to future revisions.
Actual future production, natural gas, oil and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas, oil and NGL reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing natural gas and oil prices and other factors, many of which are beyond our control.
As of December 31, 2024, approximately 18% of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflect our plans for capital expenditures to convert PUDs into proved developed reserves, including approximately $1.8 billion during the next five years. You should be aware that the estimated development costs may not equal our actual costs, development may not occur as scheduled and results may not be as estimated. If we choose not to develop our PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove them from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, because PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any PUDs that are not developed within this five-year time frame.
You should not assume that the present values included in this report represent the current market value of our estimated reserves. In accordance with SEC requirements, the estimates of our present values are based on prices and costs as of the date of the estimates. The price on the date of estimate is calculated as the average natural gas and oil price during the 12 months ending in the current reporting period, determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period. The December 31, 2024 present value is based on the price of $2.13 per Mcf of natural gas, $75.48 per bbl of oil and $75.48 per bbl of NGL, before basis differential adjustments. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of an estimate.
The timing of both the production and the expenses from the development and production of natural gas and oil properties will affect both the timing of future net cash flows from our proved reserves and their present value. Any changes in demand for natural gas and oil, governmental regulations or taxation will also affect the future net cash flows from our production. In addition, the 10% discount factor that is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes is not necessarily the most appropriate discount factor. Interest rates in effect from time to time and the risks associated with our business or the gas and oil industry in general will affect the appropriateness of the 10% discount factor.
Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
We have a substantial inventory of undeveloped properties. Development and exploratory drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. We have acquired undeveloped properties that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that undeveloped properties acquired by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive, or that we will recover all or any portion of our investment in such undeveloped properties or wells.
Drilling for natural gas and oil may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling and completion operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, title problems, equipment failures or accidents, shortages of midstream transportation, equipment or personnel, environmental issues, state or local bans or moratoriums on hydraulic fracturing and produced water disposal, federal restrictions on gas and oil leasing and permitting and a decline in commodity prices, among others. The profitability of wells, particularly in certain of the areas in which we operate, will be reduced or eliminated if commodity prices decline. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and future market prices for natural gas, oil and NGLs, costs associated with producing natural gas, oil and NGLs and our ability to add reserves at an acceptable cost.
We rely to a significant extent on seismic data and other technologies in evaluating undeveloped properties and in conducting our exploration activities. The seismic data and other technologies we use do not allow us to know conclusively, prior to acquisition of undeveloped properties or drilling a well, whether natural gas or oil is present or may be produced economically. If we incur significant expense in acquiring or developing properties that do not produce as expected or at profitable levels, it could have a material adverse effect on our results of operations and financial condition.
Certain of our undeveloped properties are subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are renewed.
Leases on natural gas and oil properties typically have a term of three to five years, after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. If our leases on our undeveloped properties expire and we are unable to renew the leases, we will lose our right to develop the related properties. Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, natural gas and oil prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. Low commodity prices may cause us to delay our drilling plans and, as a result, lose our right to develop the related properties.
Our commodity price risk management activities may limit the benefit we would receive from increases in commodity prices, may require us to provide collateral for derivative liabilities and involve risk that our counterparties may be unable to satisfy their obligations to us.
To manage our exposure to price volatility, we enter into natural gas, oil and NGL price derivative contracts. Our natural gas, oil and NGL derivative arrangements may limit the benefit we would receive from increases in commodity prices. The fair value of our natural gas, oil and NGL derivative instruments can fluctuate significantly between periods. Our decision to mitigate cash flow volatility through derivative arrangements, if any, is based in part on our view of current and future market conditions and our desire to stabilize cash flows necessary for the development of our proved reserves. We may choose not to enter into derivatives if we believe the pricing environment for certain time periods is unfavorable. Additionally, we may choose to liquidate existing derivative positions prior to the expiration of their contractual maturities to monetize gain positions for the purpose of funding our capital program.
Most of our natural gas, oil and NGL derivative contracts are with counterparties under bilateral hedging arrangements. Our counterparties’ obligations under the arrangements must be secured by cash or letters of credit to the extent that any mark-to-market amounts owed to us exceed defined thresholds. Collateral requirements are dependent to a large extent on natural gas and oil prices.
Natural gas, oil and NGL derivative transactions expose us to the risk that our counterparties, which are generally financial institutions, may be unable to satisfy their obligations to us. During periods of declining commodity prices, the value of our commodity derivative asset positions increase, which increases our counterparty exposure. Although the counterparties to our hedging arrangements are required to secure their obligations to us under certain scenarios, if any of our counterparties were to default on their obligations to us under the derivative contracts or seek bankruptcy protection, it could have an adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future cash flows being exposed to commodity price changes.
Natural gas and oil operations are uncertain and involve substantial costs and risks.
Our operating activities are subject to numerous costs and risks, including the risk that we will not encounter commercially productive gas or oil reservoirs. Drilling for natural gas, oil and NGL can be unprofitable, not only from dry holes, but from productive wells that do not return a profit because of insufficient revenue from production or high costs. Substantial costs are required to locate, acquire and develop gas and oil properties, and we are often uncertain as to the amount and timing of those costs. Our cost of drilling, completing, equipping and operating wells is often uncertain before drilling commences. Declines in commodity prices and overruns in budgeted expenditures are common risks that can make a particular project uneconomic or less economic than forecasted. Although both exploratory and developmental drilling activities involve these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. In addition, our gas and oil properties can become damaged, our operations may be curtailed, delayed or canceled and the costs of such operations may increase as a result of a variety of factors, including, but not limited to:
•unexpected drilling conditions, pressure conditions or irregularities in reservoir formations;
•equipment failures or accidents;
•fires, explosions, blowouts, cratering or loss of well control;
•the mishandling or underground migration of fluids and chemicals;
•adverse weather conditions and natural disasters, such as tornadoes, earthquakes, hurricanes and extreme temperatures;
•issues with title or in receiving governmental permits or approvals;
•restricted takeaway capacity for our production, including due to inadequate midstream infrastructure or constrained downstream markets;
•environmental hazards or liabilities;
•restrictions in access to, or disposal of, water used or produced in drilling and completion operations;
•shortages or delays in the availability of services or delivery of equipment; and
•unexpected or unforeseen changes in regulatory policy, and political or public opinion.
The occurrence of one or more of these factors could result in a partial or total loss of our investment in a particular property, as well as significant liabilities. Although we may maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover casualty losses or liabilities, and our insurance does not cover penalties or fines that may be assessed by a governmental authority. For certain risks, such as political risk, business interruption, war, terrorism and piracy, we have limited or no insurance coverage. Also, in the future we may not be able to obtain insurance at premium levels that justify its purchase. The occurrence of a significant event against which we are not fully insured may expose us to liabilities.
Moreover, certain of these events could result in environmental contamination and impact to third parties, including persons living in proximity to our operations, our employees and employees of our contractors, leading to possible injuries, death, significant damage to property and natural resources or significant financial liabilities or penalties.
Our ability to produce natural gas, oil and NGL economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our operations or are unable to dispose of or recycle the water we use economically and in compliance with environmental laws.
Water is an essential component of natural gas, oil and NGL production during both the drilling and hydraulic fracturing processes. Development activities, particularly hydraulic fracturing, require the use and disposal of significant quantities of water. Over the past several years, portions of the country have experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. In these areas, water must be obtained from other sources and transported to the drilling site. Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations in certain areas. The imposition of new or revised environmental regulations could further restrict our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other materials associated with the exploration, development or production of natural gas and oil.
We have made significant investments in oilfield service businesses, including our drilling rigs, water infrastructure and pressure pumping equipment, to lower costs and secure inputs for our operations and transportation for our production. If our development and production activities are curtailed or disrupted, we may not recover our investment in these activities, which could adversely impact our results of operations. In addition, our continued expansion of these operations may adversely impact our relationships with third-party providers.
We also have made investments to meet certain of our field services’ needs. If our level of operations is reduced for a long period, we may not be able to recover these investments. Further, our presence in these service and supply sectors, including competing with them for qualified personnel and supplies, may have an adverse effect on our relationships with our existing third-party service and resource providers or our ability to secure these services and resources from other providers.
Our operations may be adversely affected by pipeline, trucking and gathering system capacity constraints and may be subject to interruptions that could adversely affect our cash flow.
In certain resource plays, the capacity of gathering and transportation systems is insufficient to accommodate potential production from existing and new wells. We rely heavily on third parties to meet our natural gas, oil and NGL gathering needs. Capital constraints or changes in laws or regulations could limit the construction of new pipelines and gathering systems and the provision or expansion of trucking services by third parties. Until this new capacity is available, we may experience delays in producing and selling our natural gas, oil and NGL. In such event, we might have to shut in our wells while awaiting a pipeline connection or additional capacity, which would adversely affect our results of operations. Capital constraints or changes in laws or regulations also could increase the cost to access to such capacity, which would increase the cost of our operations.
A portion of our natural gas, oil and NGL production in any region may be interrupted, or shut in, from time to time for numerous reasons, including weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could materially adversely affect our cash flow.
Our business strategy is increasingly focused on participating in the global LNG value chain, which is dependent, in part, on the growing U.S. LNG export market, a highly regulated and capital intensive industry with a number of inherent commercial risks. U.S. LNG exports have helped drive domestic demand for natural gas, and, as a natural gas producer, we could be materially and adversely impacted by a deterioration in the U.S. LNG export industry, which could in turn reduce demand for natural gas. In addition, we may seek to more directly participate in the LNG value chain through direct marketing arrangements with LNG export facilities and/or end users, which could expose us to additional commercial risks associated with the global LNG markets.
As a domestic natural gas exploration and production company, we may be indirectly exposed to certain risks in the U.S. LNG export markets, including to the extent that we have entered into, or may in the future enter into,
long-term natural gas supply agreements with LNG export facilities. The LNG export industry is a highly regulated and capital-intensive industry that is subject to a number of risks. Many facilities remain under construction or are expanding, and if these facilities are unable to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, construction and operation of their facilities, or if they are unable to secure financing in connection with their operations or the completion of their planned projects, the U.S. LNG market may be materially and adversely impacted, which could reduce demand for U.S. natural gas and have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
We may also in the future enter into other commercial arrangements directly with foreign LNG customers. LNG sale and purchase agreements commonly have terms exceeding 10 years, which could expose us to credit risk should a customer default and we are required to seek recourse. Additionally, long-term LNG sales and purchase agreements generally permit a customer to terminate their contractual obligations upon the occurrence of certain events, including: (i) a failure to make available specified scheduled cargo quantities, (ii) delays in the commencement of commercial operations and (iii) the occurrence of certain events of force majeure. The occurrence of these and other events permitting termination may be outside of our control and may expose us to unrecoverable losses.
Further, any future commercial agreement may expose us to commodity risks associated with differential pricing of natural gas in different markets. LNG and natural gas are traded according to prices determined with reference to a variety of international indices, including the Japan Korea Marker (JKM) and the Dutch TTF market, each of which may materially differ from prices that use the U.S. Henry Hub index as a reference price. If we are unable to manage the impacts of unfavorable price differentials between domestic and international indices for LNG or natural gas in the context of future agreements, this could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.
Regional epidemics or pandemics and related economic turmoil, including supply chain constraints, have affected, and could in the future adversely affect our business, financial condition, results of operations and cash flows.
The COVID-19 pandemic adversely impacted the entire global economy, including creating supply chain constraints, and any future regional epidemics or global pandemics and governmental and other measures implemented to try to address them, such as quarantines, shelter-in-place orders, business and government shutdowns and restrictions on operations, could adversely affect our business, financial condition, results of operations and cash flows. Actions by our customers and derivative contract counterparties in response to such events and their economic impacts, including potential non-performance or delays, could also have an adverse impact on our business.
Cyber-attacks targeting systems and infrastructure used by the gas and oil industry and related regulations may adversely impact our operations and, if we or our third-party providers are unable to obtain and maintain adequate protection for our key systems and data, our business may be harmed.
Cybersecurity threats present a large and growing risk to our business, as the energy industry has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain exploration, development and production activities. For example, we depend on sophisticated information technology (“IT”) and operational technology (“OT”) to estimate quantities of natural gas, oil and NGL reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our customers, employees and third-party partners. In addition, many third-party providers directly or indirectly provide us products and services across an array of internal and external functions that enable us to conduct, monitor and/or protect our business, systems and data assets. In addition, in the ordinary course of business, we and our service providers collect, process, transmit, and store proprietary and confidential data, including personal information.
We have been, and we and our customers, business partners, and counterparties may become, the subject of cyber-attacks on our and their internal IT and OT systems and through those of third parties. Any such cyber-attacks or information security breach could have a material adverse effect on our revenues and increase our operating and capital costs, as well as disrupt our business plans and negatively impact our reputation and operations. As an energy company, we expect to continue to be a target for such attacks in the future from nation-state sponsored foreign actors and other attackers. We face evolving cybersecurity risks that threaten the confidentiality, integrity
and availability of our digital technologies and business data, including malicious attacks by third parties or insiders, social engineering/phishing and human error, as well as bugs, misconfigurations of hardware or software and other vulnerabilities that may exist in our or our third-party providers’ systems or technologies. Unauthorized access to our seismic data, reserves information, customer or employee data or other proprietary or commercially sensitive information could lead to data corruption, communication interruption, or other disruptions in our exploration or production operations or planned business transactions, any of which could have a material adverse impact on our results of operations. If our information technology systems cease to function properly or our cybersecurity is breached or otherwise insufficient, we could suffer disruptions to our normal operations, which may include disruptions to our drilling, completion, production and corporate functions. There can also be no assurance that our cybersecurity risk management program and processes, including our policies, controls or procedures, will be fully implemented, complied with or effective in protecting our systems and data. A cyber-attack, or the perception thereof, involving our information systems and related infrastructure, or that of our business associates or third-party providers, could result in supply chain disruptions that delay or prevent the transportation and marketing of our production, non-compliance leading to regulatory fines or penalties, loss or disclosure of, damage to, our or any of our customer’s or supplier’s data or confidential information that could harm our business by damaging our reputation, subjecting us to potential financial or legal liability and requiring us to incur significant costs, including expensive and time-consuming costs to repair or restore our systems and data or to take other remedial steps, disproportionate attention of management, or damage to our reputation. Additionally, rapidly evolving laws and regulations governing cybersecurity pose increasingly complex compliance obligations and technical challenges, and failure to comply with these obligations, including incident notification requirements, could result in legal claims or proceedings (such as class actions), regulatory investigations and enforcement actions, fines and penalties and negative reputational impacts that could cause us to lose existing or future customers.
In the event of a cyber-attack, we may be required by federal and state laws or regulations to provide notification to regulators or individuals. For example, the Cyber Incident Reporting for Critical Infrastructure Act (CIRCIA) was signed into law on March 15, 2022. CIRCIA mandates that all owners and operators of critical infrastructure report cyber incidents to the U.S. Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) within 72 hours and ransomware payments within 24 hours. These new requirements will become effective once CISA promulgates rules pursuant to the CIRCIA. CISA issued a notice of proposed rulemaking on April 4, 2024 and is required to issue a final rule within 18 months of issuing the proposed rule.
Both the frequency and magnitude of cyberattacks is expected to increase as attackers are becoming more sophisticated. As a result, we may be unable to anticipate, detect, prevent, investigate or contain future attacks, particularly as the methodologies utilized by attackers change frequently or are not recognized until launched, and we may be unable to investigate or remediate incidents because attackers are increasingly using techniques and tools designed to circumvent controls, to avoid detection and to remove or obfuscate forensic evidence. Further, global remote working dynamics for our customers, employees and third-party providers present additional risk that threat actors may seek to engage in social engineering (for example, phishing) and to exploit vulnerabilities in corporate and non-corporate networks. As cyber-attacks continue to evolve, including the prevalence of reconnaissance or surveillance by threat actors, which may remain undetected for an extended period notwithstanding our monitoring and detection efforts, we may be required to spend significant additional resources to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber-attacks of our IT and OT systems.
Any losses, costs or liabilities directly or indirectly related to cyberattacks or similar incidents may not be covered by, or may exceed the coverage limits of, any or all of our insurance policies.
We collect, process, store and use personal information and other data, and our actual or perceived failure to protect such information and data or comply with data privacy and security laws and regulations could damage our reputation and brand and harm our business and operating results.
Along with our own data and information that we collect and retain in the normal course of our business, we and our business partners collect and retain significant volumes of certain other types of data, some of which are subject to data protection laws, including information related to our past, current and prospective employees, royalty owners, and other parties. The regulatory environment surrounding the collection, use, transfer and protection of such data, both domestically and internationally, is becoming increasingly complex, constantly evolving, and is subject to frequent significant change. We and our vendors are subject to a variety of federal and state data privacy
laws, rules, regulations, industry standards and other requirements governing data privacy and the unauthorized disclosure of confidential information. Complying with these jurisdictional requirements could increase the costs and complexity of compliance procedures, and any failure to comply with these laws and regulations could result in significant penalties and legal liability. For example, we are subject to various state privacy laws, such as the California Consumer Privacy Act (“CCPA”), which came into effect in January 2020, and the California Privacy Rights Act (“CPRA”), which expands upon the CCPA and came into effect in January 2023 (with a lookback period beginning January 2022). The CCPA and the CPRA, among other things, contain new disclosure obligations for businesses that collect personal information about California residents, provide such individuals expanded rights to access, delete and correct their personal information and opt-out of certain sales or transfers of personal information and provide for statutory fines and penalties for certain data security breaches or other CCPA and CPRA violations. The enactment of the CCPA has prompted a wave of similar legislative developments in other states in the United States, which creates the potential for a patchwork of overlapping but different state laws. Any failure or perceived failure by us to comply with data privacy laws, rules, regulations, industry standards and other requirements could result in proceedings or actions against us by individuals, consumer rights groups, government agencies or others. We could incur significant costs in investigating and defending such claims and, if found liable, pay significant damages or fines or be required to make changes to our business. Further, any such proceedings and any subsequent adverse outcomes may subject us to significant negative publicity and an erosion of trust. If any of these events were to occur, our business, reputation, financial condition or results of operations could be materially adversely affected.
Our business is subject to risks related to catastrophes, natural disasters, severe weather and human causes beyond our control, which may have a negative impact on our results of operations and financial condition.
Our operations are subject to disruption from human causes beyond our control and natural disasters, including extreme weather events the scientific community has concluded are associated with climate change, such as hurricanes, severe storms, floods, droughts, heat waves, winter storms, wildfires and ambient temperature, water level or precipitation changes as well as war, accidents, civil unrest, political events, earthquakes, system failures, cyber threats, terrorist acts and epidemic or pandemic diseases, any of which could result in suspension of operations (including those of our customers or suppliers) or harm to people, our assets or the environment.
It is difficult to predict with certainty the timing, frequency or severity of such events or how such frequency or severity may change. However, if any such events were to occur, potential adverse effects could include disruption of our production activities, delays in production or possibly shut-ins as a result of physical damage to wells, pumps, storage tanks and other infrastructure facilities, increases in our costs of operation or reductions in the efficiency of our operations, reduced availability of electrical power, road accessibility, and transportation facilities, impacts on our personnel, supply chain, distribution chain or customers, and potentially increased costs or limited availability for insurance coverages in the aftermath of such effects. Such events could also adversely affect or delay demand for our products or cause us to incur significant costs in preparing for, or responding to, the effects of climatic or weather events themselves. Any such events could have a material adverse effect on our results of operations or financial condition. Moreover, any changes in ambient temperatures or severe weather events may impact demand for natural gas if it results in lower energy needs for, among other things, temperature control.
In addition, our headquarters are located in Oklahoma City, Oklahoma, an area that experiences earthquakes and severe weather events, including tornadoes. Our information systems and administrative and management processes are primarily provided to our various drilling projects and producing wells throughout the United States from this location, which could be disrupted if a catastrophic event destroyed or severely damaged our headquarters. Any such catastrophic event could harm our ability to conduct normal operations and could adversely affect our business.
A deterioration in general economic, political, business or industry conditions would have a material adverse effect on our results of operations, liquidity and financial condition.
Historically, concerns about global economic growth and international political stability have had a significant impact on global financial markets and commodity prices, including petroleum products. If the economic or political climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers
to continue operations and materially adversely impact our results of operations, liquidity and financial condition. The global market is also continuing to experience inflationary pressure, including rising fuel costs, a tightening steel market and labor and supply chain shortages, which could result in increases to our operating and capital costs that are not fixed. Additionally, while concerns over energy security have, in some situations, seen increased demand for natural gas, sustained concerns over energy security may result in an accelerated adoption of renewable energy and other alternative energy generation or storage, or energy efficiency, technologies. Any such accelerated adoption of alternative energy sources or energy efficiency improvements may decrease demand for our products or otherwise adversely impact our financial condition or results of operations.
We may be unable to dispose of assets on attractive terms, and may be required to retain liabilities for certain matters.
Various factors could materially affect our ability to dispose of assets if and when we decide to do so, including the availability of purchasers willing to purchase the assets at prices acceptable to us, particularly in times of reduced and volatile commodity prices. Sellers typically retain liabilities for certain matters. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a sale, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.
Military and other armed conflicts, including terrorist activities, and related price volatility and geopolitical instability could materially and adversely affect our business and results of operations.
Military and other armed conflicts, terrorist attacks and the threat of both, whether domestic or foreign, could cause further instability in the global financial and energy markets. Continued instability in Europe and the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy in unpredictable ways, including the disruption of energy supplies and markets, increased volatility in commodity prices, including petroleum products, or the possibility that the infrastructure on which we rely could be a direct target or an indirect casualty of an act of terrorism, and, in turn, could materially and adversely affect our business and results of operations.
For example, in late February 2022, Russia launched a military invasion against Ukraine. Sustained conflict and disruption in the region are likely in the near term, and the longer-term duration of the war is uncertain. The Russian invasion has caused, and could intensify, volatility in natural gas, oil and NGL prices, driving a sharp upward spike in the short term, and may have an impact on global growth prospects, which could in turn affect demand for natural gas and oil. In addition, any exacerbation or spillover of the current armed conflict between Israel and Hamas into the broader region could produce similar impacts. Any such volatility, impacts on demand and disruptions may also magnify the impact of other risk factors described in this report.
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| Financial Risks Related to our Business |
We have significant capital needs, and our ability to access the capital and credit markets to raise capital on favorable terms is limited by industry conditions.
Disruptions in the capital and credit markets, in particular with respect to the energy sector, could limit our ability to access these markets or may significantly increase our cost to borrow. In the past, low commodity prices have caused and may continue to cause lenders to increase the interest rates under upstream operators’ credit facilities, enact tighter lending standards, refuse to refinance existing debt around maturity on favorable terms or at all and may reduce or cease to provide funding to borrowers. Additionally, certain financial institutions have announced their intention to cease investment banking and corporate lending activities in the North American gas and oil sector or have established climate-related funding commitments that could have the effect of limiting their investment in us or our industry. If we are unable to access the capital and credit markets on favorable terms, it could have a material adverse effect on our business, financial condition, results of operations, cash flows and liquidity and our ability to repay or refinance our debt. Additionally, challenges in the economy have led and could further lead to reductions in the demand for gas and oil, or further reductions in the prices of gas and oil, or both, which could have a negative impact on our financial position, results of operations and cash flows.
Restrictive covenants in certain of our existing and future debt instruments may limit our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.
Restrictive covenants in certain of our existing and future debt instruments may limit our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests. Certain of our debt instruments contain, and the terms of any future indebtedness may contain, restrictive covenants that limit our ability to, among other things: incur or guarantee additional indebtedness; create liens; merge or consolidate with another entity; make restricted payments; and engage in transactions with affiliates. A breach of any of these restrictive covenants could result in default under the applicable debt instrument.
We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants and financial covenants contained in our debt instruments. As an example, our Investment Grade Credit Agreement requires us to comply with a total indebtedness to capitalization ratio not to exceed 65%. The requirement that we comply with these provisions may adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.
Changes to the ability of our customers to receive our products or meet their financial, performance and other obligations to us could adversely impact our business and financial condition.
In addition to credit risk related to receivables from commodity derivative contracts, our principal exposures to credit risk are through receivables resulting from the sale of our natural gas, oil and NGL production that we market to energy companies, end users and refineries ($1,028 million as of December 31, 2024). We do not require all of our customers to post collateral. The inability or failure of our customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial condition.
Any failure to meet our debt obligations could harm our business, financial condition and results of operations.
Our earnings and cash flow fluctuate from year to year due to the variable nature of commodity prices. If our cash flow and capital resources are insufficient to fund our debt obligations, we may be forced to sell assets, seek equity sales or restructure our debt. Our ability to restructure our debt will depend on the condition of the capital markets and our financial condition at such time. Any restructuring of debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our operations and our financial flexibility. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives.
We receive debt ratings from the major credit rating agencies in the United States. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term cash flow relative to debt balances. Liquidity, asset quality, cost structure, product mix (natural gas, oil and NGLs) and projected commodity pricing levels are also considered by the rating agencies. A ratings downgrade could adversely impact our ability to access debt markets in the future, increase the cost of future debt and could require us to post letters of credit or other forms of collateral for certain obligations. Many of our existing commercial contracts contain, and future commercial contracts may contain, provisions permitting the counterparty to require increased security upon the occurrence of a downgrade in our credit rating. We cannot provide assurance that our current ratings will remain in effect for any given period of time or that a rating will not be downgraded in the future.
Our ability to comply with the covenants and other restrictions in our financing agreements may be affected by events beyond our control, including prevailing economic and financial conditions.
Failure to comply with the covenants and other restrictions could lead to an event of default and the acceleration of our obligations under our senior notes, credit facility or other financing agreements, and in the case of the lease agreements for drilling rigs, compressors and pressure pumping equipment, loss of use of the equipment. In particular, the occurrence of risks identified elsewhere in this section, such as declines in commodity prices, increases in basis differentials and inability to access markets, could reduce our profits and thus the cash we have to fulfill our financial obligations. If we are unable to satisfy our obligations with cash on hand, we could
attempt to refinance such debt, sell assets or repay such debt with the proceeds from an equity offering. We cannot assure that we will be able to generate sufficient cash flow to pay the interest on our debt, to meet our lease obligations, or that future borrowings, equity financings or proceeds from the sale of assets will be available to pay or refinance such debt or obligations. The terms of our financing agreements may also prohibit us from taking such actions. Factors that will affect our ability to raise cash through an offering of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions and our market value and operating performance at the time of such offering or other financing. We cannot assure that any such proposed offering, refinancing or sale of assets can be successfully completed or, if completed, that the terms will be favorable to us.
Our common stockholders will be diluted if additional shares are issued.
We endeavor to create value for our stockholders on a per share basis. From time to time, we have issued stock to raise capital for our business or as consideration for acquisitions. We also issue common stock from time to time as a result of Warrant exercise and we issue restricted stock and performance share units to our employees and directors as part of their compensation. In addition, we may issue additional shares of common stock, additional notes or other securities or debt convertible into common stock, to extend maturities or fund capital expenditures. If we issue additional shares of our common stock in the future, it may have a dilutive effect on our current outstanding stockholders.
The trading price and volume of our common stock may be volatile, and you could lose a significant portion of your investment.
The market price of our common stock could be volatile, and holders of our common stock may not be able to resell their shares of common stock at or above the price at which they acquired such securities due to fluctuations in the market price of our common stock. The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of the common stock. Specific factors that may have a significant effect on the market price for our common stock include:
•general economic conditions within the U.S. and internationally, including inflationary pressures and changes in interest rates;
•general market conditions, including fluctuations in commodity prices;
•domestic and international economic, legal and regulatory factors unrelated to our performance;
•changes in natural gas, oil and NGL prices;
•volatility in the financial markets or other global economic factors;
•actual or anticipated fluctuations in our and our competitors’ quarterly and annual results;
•quarterly variations in the rate of growth of our financial indicators;
•our business, operations, results and prospects;
•our operating and financial performance;
•future mergers and acquisitions, divestitures, joint ventures or similar strategic alliances;
•market conditions in the energy industry;
•changes in government regulation, taxes, legal proceedings or other developments;
•shortfalls in our operating results from levels forecasted by securities analysts;
•investor sentiment toward the stock of oil and gas companies;
•changes in revenue or earnings estimates, or changes in recommendations by equity research analysts;
•failure to achieve the perceived benefits of the acquisitions, including financial results and anticipated synergies, as rapidly as or to the extent anticipated by financial or industry analysts;
•speculation in the press or investment community;
•the failure of research analysts to cover our stock;
•sales of common stock by us, large shareholders or management, or the perception that such sales may occur;
•changes in accounting principles, policies, guidance, interpretations or standards;
•announcements concerning us or our competitors;
•public reaction to our press releases, other public announcements and filings with the SEC;
•strategic actions taken by competitors;
•actions taken by our shareholders;
•additions or departures of key management personnel;
•maintenance of acceptable credit ratings or credit quality; and
•the general state of the securities markets.
These and other factors may impair the market for our common stock and the ability of investors to sell shares at an attractive price. These factors also could cause the market price and demand for our common stock to fluctuate substantially, which may negatively affect the price and liquidity of our common stock. Many of these factors and conditions are beyond our control.
Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert management’s attention and resources and harm our business, operating results and financial condition.
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| Risks Related to the Company Following the Southwestern Merger |
Failure to successfully integrate the business of the Company and Southwestern or realize the anticipated benefits of the Southwestern Merger may adversely affect our future results and financial condition.
The Southwestern Merger involved the combination of two companies that previously operated as independent public companies until October 1, 2024. The combination of two independent businesses is complex, costly and time consuming, and we will be required to continue to devote significant management attention and resources to integrating the business practices and operations of Southwestern into the Company. Potential difficulties that we may encounter as part of the integration process include the following:
•the inability to successfully combine the business of the Company and Southwestern in a manner that permits us to achieve, on a timely basis, or at all, the enhanced revenue opportunities and cost savings and other benefits anticipated to result from the Southwestern Merger;
•complexities associated with managing the combined businesses, including difficulty addressing possible differences in operational philosophies and the challenge of integrating complex systems, technology, networks and other assets of each of the companies in a seamless manner that minimizes any adverse impact on customers, suppliers, employees and other constituencies;
•the assumption of contractual obligations with less favorable or more restrictive terms; and
•potential unknown liabilities and unforeseen increased expenses or delays following the Southwestern Merger.
As a result of the Southwestern Merger, the size of the Company’s business has increased significantly. Our future success will depend, in part, upon our ability to manage this expanded business, which will pose substantial challenges for management, including challenges related to the management and monitoring of new operations and associated increased costs and complexity. We may also face increased scrutiny from governmental authorities as a result of the significant increase in the size of the business.
We believe that, once the business of Southwestern is fully integrated into the Company, the Southwestern Merger will provide operational and financial scale, increasing free cash flow and an enhanced corporate rate of return. However, achieving these benefits requires, among other things, realization of the targeted cost and commercial synergies expected from the Southwestern Merger. This growth and the anticipated benefits of the transaction may not be realized fully or at all or may take longer to realize than expected. Actual operating, technological, strategic and revenue opportunities, if achieved at all, may be less significant than expected or may take longer to achieve than anticipated. If we are not able to achieve these objectives and realize the anticipated benefits and synergies expected from the Southwestern Merger within the anticipated timing or at all, our business, financial condition and operating results may be adversely affected, our earnings per share may be diluted, the accretive effect of the Southwestern Merger may decrease or be delayed and our share price may be negatively impacted.
The market price for our common stock as a result of the Southwestern Merger may be affected by factors different from those that historically have affected our common stock.
Upon completion of the Southwestern Merger, legacy Southwestern shareholders became shareholders of the Company. Our financial position may differ from our financial position before the completion of the Southwestern Merger, and the results of operations of the combined company may be affected by some factors that are different from those factors that affected the results of operations of the Company prior to the Southwestern Merger or those factors that previously affected ours and Southwestern’s results of operations. Accordingly, the market price and performance of our common stock is likely to be different from the performance of our common stock prior to the Southwestern Merger.
The Company’s operating results following the Southwestern Merger will suffer if we do not effectively manage our expanded operations.
Following the Southwestern Merger, the size of our business increased significantly. Our future success depends, in part, upon our ability to manage this expanded business, which will pose substantial challenges for management, including challenges related to the management and monitoring of new operations and associated increased costs and complexity. We may also face increased scrutiny from governmental authorities as a result of the significant increase in the size of our business. There can be no assurances that we will be successful or that we will realize the expected operating efficiencies, cost savings, revenue enhancements or other benefits anticipated from the Southwestern Merger.
We have a significant amount of indebtedness, which will limit our liquidity and financial flexibility. We may also incur additional indebtedness in the future.
As of December 31, 2024, we had indebtedness of approximately $5.7 billion and, as a result of the Southwestern Merger, we assumed approximately $3.7 billion of Southwestern’s senior notes. Accordingly, following the completion and as a result of the Southwestern Merger, we have substantial indebtedness. In addition, subject to the limits contained in the documents governing such indebtedness, we may be able to incur substantial additional debt from time to time to finance working capital, capital expenditures, investments or acquisitions or for other purposes. Our indebtedness and other financial commitments have important consequences to our business, including, but not limited to:
•making it more difficult for us to satisfy our obligations with respect to senior notes and other indebtedness due to the increased debt-service obligations, which could, in turn, result in an event of default on such other indebtedness or the senior notes;
•requiring us to dedicate a substantial portion of our cash flows from operations to debt service payments, thereby limiting our ability to fund working capital, capital expenditures, investments or acquisitions and other general corporate purposes;
•increasing our vulnerability to general adverse economic and industry conditions, including low commodity price environments;
•limiting our ability to obtain additional financing due to higher costs and more restrictive covenants;
•limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
•placing us at a competitive disadvantage compared with our competitors that have proportionately less debt and fewer guarantee obligations.
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| Legal and Regulatory Risks |
We are subject to extensive governmental regulation, which can change and could adversely impact our business.
Our operations are subject to extensive federal, state, local and other laws, rules and regulations, including with respect to the environment, worker health and safety, wildlife conservation, the gathering and transportation of gas, oil and NGLs, conservation policies, reporting obligations, royalty payments, unclaimed property, the imposition of taxes and tribal laws for a minor portion of our acreage. Such regulations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling, completion and well operations. If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling or completion activities, we may not be able to conduct our operations as planned. For example, in January 2024, the previous Presidential Administration announced a temporary pause on the DOE’s review of pending applications for authorization to export LNG to non-Free Trade Agreement countries until the DOE examines the economic and environmental impacts of increased LNG export volumes. In December 2024, the DOE released its report on LNG exports, which report is subject to a 60-day public comment period ending in February 2025. However, in January 2025, the current Presidential Administration issued an executive order directing the DOE to restart reviews of applications for approvals of LNG export projects as expeditiously as possible.
In addition, changes in public policy have affected, and in the future could further affect, our operations. At both the federal and state level, for example, there are an increasing number of legislative initiatives and proposals that may lead to reduced demand for fossil fuels such as oil and gas. These include certain tax advantages and other subsidies to support alternative energy sources or that mandate the use of specific fuels or technologies, in addition to the promotion of research into new technologies to reduce the cost and increase the scalability of alternative energy sources. The IRA, signed into law in August 2022, provides significant funding and incentives for research, development and implementation of low-carbon energy production methods, carbon capture, and other programs directed at addressing climate change. The IRA also includes a Methane Emissions Reduction Program that amends the CAA to require the EPA to impose a “Waste Emissions Charge” on methane emissions from certain natural gas and oil sources that are already required to report under EPA’s Greenhouse Gas Reporting Program. In May 2024, the EPA finalized revisions to the Greenhouse Gas Reporting Program for petroleum and natural gas facilities. Among other things, the final rule expands the emissions events that are subject to reporting requirements to include “other large release events” and applies reporting requirements to certain new sources and sectors. The emissions reported under the Greenhouse Gas Reporting Program will be the basis for any payments under the Methane Emissions Reduction Program in the IRA. However, petitions for reconsideration to the EPA are pending and litigation in the D.C. Circuit Court of Appeals has commenced. In addition, in November 2024, the EPA finalized a rule to implement the IRA’s Waste Emissions Charge that became effective in January 2025. The Waste Emissions Charge imposed under the Methane Emissions Reduction Program for 2024 reported amounts is $900
per metric ton emitted over permitted methane emissions thresholds, and increases to $1,200 for 2025 reported amounts, and $1,500 for 2026 reported amounts. In January 2025, industry associations challenged the Waste Emissions Charge rule in the D.C. Circuit Court of Appeals. Additionally, based on the timing of the rule’s finalization, the Waste Emissions Charge rule is potentially vulnerable to repeal by Congress under the Congressional Review Act. To the extent the rule is implemented, the emissions fee and funding provisions of the law could increase operating costs within the gas and oil industry and accelerate the transition away from fossil fuels, which could in turn adversely affect our business and results of operations. However, in January 2025, the current Presidential Administration issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. The Inflation Reduction Act may also be subject to amendment or repeal through the Congressional budget reconciliation. Consequently, future implementation and enforcement of these final rules remains uncertain at this time. Other regulatory developments could, among other things, restrict production levels, impose price controls, change environmental protection requirements with respect to the treatment of hazardous waste, air emissions, or water discharges, and increase taxes, royalties and other amounts payable to the government. Our operating and compliance costs could increase further if existing laws and regulations are revised, reinterpreted or if new laws and regulations become applicable to our operations. We do not expect that any of these laws and regulations will affect our operations materially differently than they would affect other companies with similar operations, size and financial strength. Although we are unable to predict changes to existing laws and regulations, such changes could materially adversely affect our profitability, financial condition and liquidity.
Pipeline Safety. The pipeline assets in which we own interests are subject to stringent and complex regulations related to pipeline safety and integrity management. The PHMSA has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, NGL and condensate transmission pipelines as well as for certain low stress pipelines and gathering lines transporting hazardous liquids, such as oil, that, in the event of a failure, could affect “high consequence areas.” Recent PHMSA rules have also extended certain requirements for integrity assessments and leak detections beyond high consequence areas and impose a number of reporting and inspection requirements on regulated pipelines. In November 2021, the PHMSA issued a final rule that expands certain federal pipeline safety requirements to all onshore gas gathering pipelines, regardless of size or location. The final rule establishes two new types of onshore gas gathering pipelines subject to varying degrees of regulation: all onshore gathering line operators are now subject to PHMSA’s annual reporting and incident reporting requirements, and certain previously unregulated rural gas gathering lines must now comply with PHMSA damage prevention and, depending on the size of the pipeline, construction and operational requirements. The final rule became effective on May 16, 2022. Further, legislation funding the PHMSA through 2023 requires the agency to engage in additional rulemaking (i) to amend the integrity management program, emergency response plan, operation and maintenance manual and pressure control recordkeeping requirements for gas distribution operators, (ii) to create new leak detection and repair program obligations and (iii) to set new minimum federal safety standards for onshore gas gathering lines. In January 2025, the PHMSA finalized a rule that requires pipelines, underground natural gas storage facilities, and liquefied natural gas facilities to update leak detection and repair programs to require companies to use commercially available technologies to find and fix methane leaks from pipelines and other facilities. At this time, we cannot predict the cost of these requirements or other potential new or amended regulations, but they could be significant. Moreover, violations of pipeline safety regulations can result in the imposition of significant penalties. However, in January 2025, the current Presidential Administration issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. Consequently, future implementation and enforcement of these final rules remains uncertain at this time.
Hydraulic Fracturing. Hydraulic fracturing typically is regulated by state oil and natural gas commissions or similar agencies, but EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuel in fracturing fluids and issued permitting guidance that applies to such activities.
Several states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure and/or well construction requirements on hydraulic fracturing operations. State and federal regulatory agencies have also recently focused on a possible connection between the operation of injection wells used for natural gas and oil waste disposal and seismic activity, which has caused some states, such as New
Mexico, Oklahoma and Texas, to implement seismicity response programs that allow state regulators to deny, modify, suspend or terminate injection well permits if the state regulator determines that the injection well is contributing or likely to contribute to seismic activity. In some instances, regulators may also order that disposal wells be shut in. States could also elect to prohibit high volume hydraulic fracturing altogether. A number of lawsuits have been filed alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular. We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, our business and operations could be subject to delays, increased operating and compliance costs and potential bans. Additional regulation could also lead to greater opposition to hydraulic fracturing, including litigation.
Climate Change and Regulation of Methane and Other Greenhouse Gas Emissions. Political and social attention to the issue of climate change has resulted in legislative, regulatory and other initiatives to reduce GHG emissions, such as carbon dioxide and methane. Policy makers at both the U.S. federal and state levels have adopted, or are considering adopting, rules designed to quantify and limit the emission of GHGs through inventories, limitations and/or taxes on GHG emissions. For example, the IRA appropriates significant federal funding for renewable energy initiatives and, for the first time ever, imposes a fee on GHG emissions from certain facilities (discussed above). The emissions fee and funding provisions of the law could increase operating costs within the oil and gas industry and accelerate the transition away from fossil fuels, which could in turn adversely affect our business and results of operations. However, in January 2025, the current Presidential Administration issued an executive order directing an immediate pause on the disbursement of funds appropriated through the IRA. In addition, the EPA has issued regulations for the control of methane emissions, which include leak detection and repair requirements, for the gas and oil industry. In November 2021, the EPA proposed new performance standards and emissions guidelines for new, modified, reconstructed and existing oil and gas facilities. The proposed rule sought to make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). In addition, the proposed rule sought to establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by EPA. In November 2022, the EPA issued a supplemental proposed rule, which among other things, removed an emissions monitoring exemption for small wellhead-only sites and created a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters”. In December 2023, the EPA issued the final rule, which imposes more stringent requirements on the natural gas and oil industry, including phasing out routine flaring of natural gas from new oil wells, requiring all well sites and compressor stations to be routinely monitored for leaks and eliminating or minimizing emissions from common pieces of equipment used in oil and gas operations, such as process controllers, pumps and storage tanks. Notably, EPA updated the applicability date for Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance dates under state plans. The final rule gives states, along with federal tribes that wish to regulate existing sources, until March 2026 to develop and submit their plans for reducing methane from existing sources. The final emissions guidelines under Subpart OOOOc provide until 2029 for existing sources to comply. The final rule is subject to ongoing litigation but remains in effect. This and other rules may require us to incur additional costs or otherwise impact the economics of certain of our operations. Additionally, in April 2024, the BLM finalized a rule to reduce the methane waste from venting, flaring, and leaks during oil and gas production activities on federal and Indian leases. The final rule took effect in June 2024. However, in May 2024, the states of North Dakota, Texas, Montana, Wyoming and Utah challenged the rule. In September 2024, a North Dakota district court granted a motion prohibiting the BLM from enforcing the rule against those states pending the outcome of the litigation. However, in January 2025, the current Presidential Administration issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. Consequently, future implementation and enforcement of these final rules remains uncertain at this time.
In addition, several states in which we operate have imposed limitations designed to reduce methane emissions from gas and oil exploration and production activities. Legislative and state initiatives to date have generally focused on the development of renewable energy standards and/or cap-and-trade and/or carbon tax
programs. Renewable energy standards (also referred to as renewable portfolio standards) require electric utilities to provide a specified minimum percentage of electricity from eligible renewable resources, with potential increases to the required percentage over time. The development of a federal renewable energy standard, or the development of additional or more stringent renewable energy standards at the state level could reduce the demand for gas and oil, thereby adversely impacting our earnings, cash flows and financial position. In addition, federal or state carbon taxes or fees could directly increase our costs of operation.
At the international level, the United Nations sponsored “Paris Agreement” requires member states to submit non-binding, individually determined reduction goals known as Nationally Determined Contributions every five years after 2020. In 2021, the previous Presidential Administration announced reentry of the U.S. into the Paris Agreement along with a new “nationally determined contribution” for U.S. GHG emissions that would achieve emissions reductions of at least 50% relative to 2005 levels by 2030. At COP26 in Glasgow in November 2021, the United States and the European Union jointly announced the Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector. COP26 concluded with the finalization of the Glasgow Climate Pact, which stated long-term global goals (including those in the Paris Agreement) to limit the increase in the global average temperature and emphasized reductions in GHG emissions. At COP27, the previous Presidential Administration announced the EPA’s standards to reduce methane emissions from new, modified and existing oil and gas sources (discussed above), and the United States agreed, in conjunction with the European Union and several other partner countries, to develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. At COP28, member countries entered into an agreement that calls for actions toward achieving, at a global scale, a tripling of renewable energy capacity and doubling energy efficiency improvements by 2030. In April 2024, the European Union adopted a regulation to track and reduce methane emissions in the energy sector, including requiring monitoring, reporting and verification measures to be applied by importers of oil, natural gas, and coal into the European Union by January 1, 2027, and “maximum methane intensity values” must be met by 2030 and every year thereafter. Each member state will have the power to impose administrative penalties for failure to comply and the standard will be mandatory for supply contracts signed after the law takes effect. At COP29, participants representing 159 countries met to review progress toward the goals of the Global Methane Pledge and the addition of nearly $500 million in new grant funding for methane abatement. However, in January 2025, the current Presidential Administration issued an executive order directing the immediate notice to the United Nations of the United States’ withdrawal from the Paris Agreement and all other agreements made under the United Nations Framework Convention on Climate Change. At the same time, various state and local governments have publicly committed to furthering the goals of the Paris Agreement. As a result, it is not possible at this time to predict how legislation or regulations that may be adopted to address climate change, methane and other GHG emissions would impact our business. Further, the Supreme Court’s decision in Loper Bright Enterprises v. Raimondo to overrule Chevron U.S.A. Inc. v. Natural Resources Defense Council, Inc. and end the concept of general deference to regulatory agency interpretations of laws introduces new complexity for federal agencies and administration of climate change policy and regulatory programs. However, many of these initiatives at the international, state and local levels are expected to continue.
These various legislative, regulatory and other activities addressing GHG emissions could adversely affect our business, including by imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations, which could require us to incur costs to reduce emissions of GHGs associated with our operations. Limitations on GHG emissions could also adversely affect demand for gas and oil, which could lower the value of our reserves and have a material adverse effect on our profitability, financial condition and liquidity. Additionally, political, litigation and financial risks may result in our restricting or canceling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing our ability to continue to operate in an economic manner. One or more of these developments could have a material adverse effect on our business, financial condition and results of operations.
Costs to comply with environmental, health and safety regulations and initiatives can be significant.
As an owner, lessee or operator of gas and oil properties, we are subject to various federal, state, tribal and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on us for the cost of remediating pollution that results from our operations. Environmental laws may impose strict, joint and several liability, and failure to comply with environmental laws and regulations can result in the imposition of administrative, civil or criminal fines and
penalties, as well as injunctions limiting operations in affected areas. Any future costs associated with these matters are uncertain and could be influenced by several factors, including any new or amended regulatory requirements or changes to the interpretation of existing regulatory requirements. One or more of these matters could have a material adverse effect on our business, financial condition and results of operations.
Increasing attention to ESG matters and our ability to achieve and maintain ESG certifications, goals and commitments may impact our business, financial results or stock price.
Increasing attention has been given to corporate activities related to ESG matters in public discourse and the investment community. Expectations regarding voluntary ESG initiatives and disclosures and consumer demand for more sustainable products, including alternative forms of energy, may result in increased costs (including but not limited to increased costs related to compliance, stakeholder engagement, contracting and insurance), changes in demand for certain products, increased availability of (and competition from) alternative energy sources and technologies, increased development of and demand for products that do not use fossil fuels or their derivatives, enhanced compliance or disclosure obligations or other adverse impacts to our business, financial condition or results of operations. Additionally, such expectations and related activism may result in demand shifts for natural gas, oil and NGLs in addition to potentially impacting our access to, and costs of, capital.
While we may at times engage in voluntary initiatives (such as voluntary disclosures, certifications or targets, among others) or commitments to improve our ESG profile and/or products or to respond to stakeholder expectations, such initiatives or achievement of such commitments may be costly and may not have the desired effect. For example, while we are exploring initiatives related to various energy-related technologies, such as carbon capture and sequestration, this may require us to incur significant costs, and there is no guarantee that markets will develop, either in the manner we anticipate or at all, for the technologies in which we invest. In addition, we may commit to certain initiatives or goals, and we may not ultimately be able to achieve such commitments or goals, either on the timeframes or costs initially anticipated or at all, due to factors that are within or outside of our control. Moreover, actions or statements that we may take based on expectations, assumptions or third-party information that we currently believe to be reasonable may subsequently be determined to be erroneous or be subject to misinterpretation. Even if this is not the case, our current actions may subsequently be determined to be insufficient by various stakeholders, and we may be subject to investor or regulator engagement on our ESG initiatives and disclosures, even if such initiatives are currently voluntary. Any failure to comply with investor, customer or other stakeholder expectations and standards, which are evolving and can conflict, or if we are perceived to not have responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, could cause reputational harm to our business, increase our risk of litigation, and could have a material adverse effect on our results of operations. For example, plaintiffs have brought litigation against various companies, including those in the fossil fuel sector, alleging that such companies created public nuisances by producing, handling or marketing fuels that contributed to climate change or that the companies have been aware of the adverse effects of climate change for some time but failed to adequately disclose those impacts. While we are not currently parties to any such litigation, the ultimate outcomes of such litigation and its impact to us are uncertain; we could incur substantial legal costs associated with defending against these or similar lawsuits in the future.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings systems for evaluating companies on their approach to ESG matters. These ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. To the extent ESG matters negatively affect our reputation, it may also harm our ability to attract or retain employees or customers.
Simultaneously, there are efforts by some stakeholders to reduce companies’ efforts on certain ESG-related matters. Both advocates and opponents to certain ESG initiatives are increasingly resorting to a range of activism forms, including media campaigns and litigation, to advance their perspectives. To the extent we are subject to such activism, it may require us to incur costs or otherwise adversely impact our business.
Separately, various regulators have adopted, or are considering adopting, regulations on environmental marketing claims or the prevention of greenwashing more generally, including, but not limited to the use of “sustainable,” “eco-friendly,” “green” or similar language in the marketing of products and services or the prevention of greenwashing more generally. Further, there have been increasing scrutiny on sustainability-related claims and
frequency of allegations of “greenwashing” against companies making sustainability-related claims due to, among other things, allegations of incomplete, false or misleading disclosures, including with respect to the sustainable nature of their operations and products, as well as to a variety of perceived deficiencies in performance, including as stakeholder perceptions of sustainability continue to evolve.
We expect there will likely be increasing levels of regulation, disclosure-related and otherwise, with respect to ESG matters, which will likely lead to increased compliance costs as well as scrutiny that could heighten all of the risks identified in this risk factor. Such ESG matters may also impact our suppliers or customers, which could augment existing, or cause additional, impacts to our business or operations. To date, we have not incurred material ESG-related costs, but we cannot guarantee that we will not incur such costs in the future.
The taxation of independent producers is subject to change, and changes in tax law could increase our cost of doing business.
We are subject to taxation by various governmental authorities at the federal, state and local levels in the jurisdictions in which we do business. New legislation could be enacted by any of these governmental authorities making it more costly for us to produce natural gas and oil by increasing our tax burden. The IRA was enacted on August 16, 2022, and included, among other things, a 15% corporate alternative minimum tax (“CAMT”) on adjusted financial statement income. Based on our book income in the past three years, we believe we have become subject to the CAMT in 2024 and should remain subject to the CAMT for the foreseeable future. Additionally, the current Presidential Administration has called for changes to fiscal and tax policies, which could lead to comprehensive tax reform. In addition, state and local authorities could enact new legislation that would increase various taxes such as sales, severance and ad valorem taxes as well as accelerate the collection of such taxes.
The completion of the Southwestern Merger triggered an annual limitation on the utilization of our tax attributes, reducing our ability to offset future taxable income, which may result in an increase to income tax liabilities. In addition, trading in our common stock, additional issuance of common stock, and certain other stock transactions could lead to an additional, potentially more restrictive, annual limitation.
Upon the completion of the Southwestern Merger, we experienced an ownership change under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code” and such change, a “Section 382 Ownership Change”), for purposes of both Southwestern’s tax attributes as well as for our own. We believe that the annual limitation on the utilization of our tax attributes resulting from the Southwestern Merger is less restrictive than the Section 382 Ownership Change we experienced in 2021. As a result, the new limitation would generally only apply to those tax attributes generated subsequent to that first ownership change.
Moreover, trading in our stock, additional issuances, and other stock transactions occurring subsequent to the Southwestern Merger could lead to a further Section 382 Ownership Change. In the event of any additional Section 382 Ownership Change a new annual limitation would be determined at such time that could be more restrictive than the current limitations. Depending on the market conditions and our tax basis, an additional Section 382 Ownership Change may result in a net unrealized built-in loss. The annual limitation in such a case would additionally be applied to certain of our tax items other than just net operating loss (NOL) carryforwards, disallowed business interest carryforwards and tax credits. For example, a portion of tax depreciation, depletion and amortization would also be subject to the annual limitation for a five-year period following the Section 382 Ownership Change but only to the extent of the net unrealized built-in loss existing at the time of the additional Section 382 Ownership Change. Whether the new annual limitation would be more restrictive would depend on the value of our stock and the long-term tax-exempt rate in effect at the time of such Section 382 Ownership Change.
Some states impose similar limitations on tax attribute utilization upon experiencing an additional Section 382 Ownership Change.
Judicial decisions can affect our rights and obligations.
Our ability to develop natural gas, oil and NGL depends on the leases and other mineral rights we acquire and the rights of owners of nearby properties. We operate in areas where judicial decisions have not yet definitively interpreted various contractual provisions or addressed relevant aspects of property rights, nuisance and other matters that could be the source of claims against us as a developer or operator of properties. Although we plan our activities according to our expectations of these unresolved areas, based on decisions on similar issues in these
jurisdictions and decisions from courts in other states that have addressed them, courts could resolve issues in ways that increase our liabilities or otherwise restrict or add costs to our operations.
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| Item 1B. | Unresolved Staff Comments |
Not applicable.
Cybersecurity Risk Management and Strategy
We have developed and implemented a cybersecurity risk management program intended to protect the confidentiality, integrity, and availability of our critical systems and information.
We design and assess our cybersecurity risk management program guided by the NIST Cybersecurity Framework to help us identify, assess and manage cybersecurity risks relevant to our business.
Our cybersecurity risk management program is integrated into our overall enterprise risk management program, and shares common methodologies, reporting channels and governance processes that apply across the enterprise risk management program to other legal, compliance, strategic, operational, and financial risk areas.
Our cybersecurity risk management program includes, but is not limited to, the following key elements:
•risk assessments designed to help identify and address material cybersecurity risks to our critical systems and information;
•a security team principally responsible for managing our cybersecurity risk assessment processes, our security controls, and our response to cybersecurity incidents;
•the use of external service providers, where appropriate, to assess, test or otherwise assist with aspects of our security processes;
•systems for protecting information technology systems and monitoring for suspicious events, such as threat protection, firewall and anti-virus software;
•cybersecurity awareness training for all of our employees and contractors;
•a cybersecurity incident response plan that includes procedures for responding to, escalating, and reporting cybersecurity incidents; and
•a third-party risk management process for service providers, suppliers, software, and vendors who access our data and/or systems.
We have not identified risks from known cybersecurity threats, including as a result of any prior cybersecurity incidents, that have materially affected us, including our operations, business strategy, results of operations, or financial condition. We face certain ongoing risks from cybersecurity threats that, if realized, are reasonably likely to materially affect us, including our operations, business strategy, results of operations, or financial condition. See Item 1A. Risk Factors “Cyber-attacks targeting systems and infrastructure used by the gas and oil industry and related regulations may adversely impact our operations and, if we or our third-party providers are unable to obtain and maintain adequate protection for our key systems and data, our business may be harmed.”
Cybersecurity Governance
Our Board of Directors considers cybersecurity risk as a critical part of the enterprise and its risk oversight function and has delegated to its Audit Committee oversight of cybersecurity and other information technology risks. Our Audit Committee oversees management’s implementation of our cybersecurity risk management program.
Our Audit Committee receives bi-annual updates from management on our cybersecurity risks. In addition, management updates our Audit Committee, as necessary, regarding any significant cybersecurity incidents.
Our Audit Committee reports to the full Board of Directors regarding its activities, including those related to cybersecurity. Our Board of Directors also receives briefings from management on our cybersecurity risk
management program. Board members receive presentations on cybersecurity topics from information security management, internal security staff, our internal audit group and external experts as part of our Board of Director’s continuing education on topics that impact public companies.
Our Cybersecurity Manager leads our cybersecurity risk management program and supervises both our internal cybersecurity personnel and our retained external cybersecurity consultants. Our Cybersecurity Manager is responsible for assessing and managing risks from cybersecurity threats and reporting significant incidents to our Cybersecurity Committee, which includes our Chief Financial Officer, General Counsel and Corporate Secretary, Chief Information Officer, Cybersecurity Manager and Director of Internal Audit. Our Cybersecurity Manager has over 20 years of experience in information security and incident response and our internal cybersecurity team has over 50 years of combined experience in information security and maintains several cybersecurity certificates including but not limited to CISSP, CISM, SRISC, GSEC, and GCFE. Our Cybersecurity team regularly participates with private energy industry and federal security working groups and organizations.
Our management team stays informed about and monitors efforts to prevent, detect, mitigate, and remediate cybersecurity risks and incidents through various means, including, as appropriate, briefings from internal security personnel, threat intelligence and other information obtained from governmental, public or private sources, such as external consultants engaged by us, and alerts and reports produced by security tools deployed in the IT environment.
Information regarding our properties is included in Item 1. Business of Part I of this report and in the Supplementary Information included in Item 8 of Part II of this report.
Litigation and Regulatory Proceedings
We are involved in various regulatory proceedings, lawsuits and disputes arising in the ordinary course of our business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. We are also party to the consolidated Chapter 11 Cases pending for the Debtors in the Bankruptcy Court. Legal proceedings that were in existence prior to the Petition Date and have not yet been settled as part of the Chapter 11 Cases will be resolved in connection with the claims reconciliation process before the Bankruptcy Court. Any allowed claim related to such prepetition litigation will be treated in accordance with the Plan. Any legal proceeding pending against Southwestern and assumed by us in connection with the Southwestern Merger is not subject to discharge or resolution as part of the Chapter 11 Cases.
See Note 5 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for information regarding our estimation and provision for potential losses related to litigation and regulatory proceedings. Based on management’s current assessment, we are of the opinion that no pending or threatened lawsuit or dispute relating to our business operations is likely to have a material adverse effect on our future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates. Environmental Contingencies
The nature of the natural gas and oil business carries with it certain environmental risks for us and our subsidiaries. We have implemented various policies, programs, procedures, training and audits to reduce and mitigate such environmental risks. We conduct periodic reviews, on a company-wide basis, to assess changes in our environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. We manage our exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, we may, among other things, exclude a property from the transaction, require the seller to remediate the property to our satisfaction in an acquisition or agree to assume liability for the remediation of the property.
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| Item 4. | Mine Safety Disclosures |
Not applicable.
PART II
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| Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Subsequent to the completion of the Southwestern Merger on October 1, 2024, we changed our company name to Expand Energy Corporation and changed the NASDAQ trading symbol for our common stock from “CHK” to “EXE”. Additionally, our Class A Warrants, Class B Warrants and Class C Warrants trading symbols changed from “CHKEW”, “CHKEZ”, and “CHKEL”, respectively, to “EXEEW”, “EXEEZ” and “EXEEL”, respectively, following the completion of the Southwestern Merger. Our common shares and Warrants have been trading under the updated trading symbols on NASDAQ since October 2, 2024. The Warrants are immediately exercisable and will expire on February 9, 2026. More information on our common stock and Warrants can be found in Note 10 of the notes to our consolidated financial statements included in Item 8 of Part II of this report. In March 2022, we adopted a variable return program that resulted in the payment of an additional variable dividend equal to the sum of Adjusted Free Cash Flow from the prior quarter less the base quarterly dividend, multiplied by 50%. Effective January 1, 2025, we updated our enhanced returns framework which prioritizes paying a base dividend per share and provides for annual net debt reduction prior to additional shareholder returns such as additional dividend payments or share repurchases. The declaration and payment of any future dividend is subject to the approval of our Board of Directors in its discretion. For additional information on our dividends, see Note 10 of the notes to our consolidated financial statements included in Item 8 of Part II of this report. | | |
| Repurchases of Equity Securities; Unregistered Sales of Equity Securities and Use of Proceeds |
On October 22, 2024 our Board of Directors authorized repurchases of up to $1.0 billion, in the aggregate, of the Company’s common stock and/or warrants under a share repurchase program. The repurchase authorization permits repurchases on a discretionary basis subject to market conditions, required internal approvals, applicable legal requirements, available liquidity, compliance with the Company’s debt agreements and other appropriate factors.
We did not repurchase any shares of our common stock during the quarter ended December 31, 2024. As of December 31, 2024, approximately $1.0 billion may yet be purchased under the share repurchase program described above.
As of February 19, 2025, there were approximately 1,226 holders of record of our common stock.
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| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
This Management’s Discussion and Analysis of Financial Condition and Results of Operations is intended to provide a reader of our financial statements with management’s perspective on our financial condition, liquidity, results of operations and certain other factors that may affect our future results. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with Item 8 of Part II of this report. On October 1, 2024, we completed the Southwestern Merger, creating a premier energy company that we believe is underpinned by a leading natural gas portfolio adjacent to the highest demand markets, premium inventory, a resilient financial foundation and an investment grade balance sheet. We believe that this new company is uniquely positioned to deliver affordable, lower-carbon energy to meet growing domestic and international demand while creating sustainable value for stakeholders. In conjunction with the closing of the Southwestern Merger, Chesapeake Energy Corporation changed its name to Expand Energy Corporation.
Expand Energy is the largest independent natural gas producer in the U.S., based on net daily production, and is focused on responsibly developing an abundant supply of natural gas, oil and NGL to expand energy access for all. Our operations are located in Louisiana in the Haynesville and Bossier Shales (“Haynesville”), in Pennsylvania in the Marcellus Shale (“Northeast Appalachia”) and in West Virginia and Ohio in the Marcellus and Utica Shales (“Southwest Appalachia”).
Our strategy is to create shareholder value through the responsible development of our significant resource plays while continuing to be a leading provider of natural gas to markets in need. We continue to focus on improving margins through operating efficiencies and financial discipline and improving our ESG performance. To accomplish these goals, we intend to allocate our human resources and capital expenditures to projects we believe offer the highest cash return on capital invested, to deploy leading drilling and completion technology throughout our portfolio, and to take advantage of acquisition and divestiture opportunities to strengthen our portfolio. We also intend to continue to dedicate capital to projects designed to reduce the environmental impact of our production activities.
Additionally, we aim to be conscientious in our efforts and how they will shape our approach to sustainability for the future and have established the following goals:
•Net zero (Scope 1 and 2) greenhouse gas emissions by 2035.
•Maintain 100% responsibly sourced gas (RSG) certification across our portfolio.
Southwestern Merger
On January 10, 2024, Chesapeake and Southwestern entered into an all-stock agreement and plan of merger (the “Merger Agreement”). Southwestern was an independent energy company engaged in development, exploration and production activities, including related marketing activities, within its operating areas in the Appalachia and Haynesville shale plays. Our Board of Directors and the Board of Directors of Southwestern both approved the Merger Agreement. At separate special meetings each held on June 18, 2024, Chesapeake’s stockholders approved the issuance of Chesapeake’s common stock to the stockholders of Southwestern in connection with the Southwestern Merger, and Southwestern’s stockholders approved the Merger Agreement.
On October 1, 2024, the Southwestern Merger was completed, and we issued approximately 95.7 million shares of our common stock to Southwestern’s shareholders in connection with the Merger Agreement. Under the terms of the Merger Agreement, subject to certain exceptions, each share of Southwestern common stock was converted into the right to receive 0.0867 of a share of the Company’s common stock. Based on the closing price of our common stock, the total value of such shares of our common stock issued to Southwestern’s shareholders was approximately $7.9 billion. See Note 2 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion. Investment Grade Rating
On October 1, 2024, we received an investment grade rating from S&P Global Ratings (“S&P”). S&P assigned an issuer-level rating of ‘BBB-’ on our unsecured debt and raised our issuer credit rating to ‘BBB-’, with a stable outlook. Additionally, on October 2, 2024, we received an investment grade rating from Fitch Ratings (“Fitch”). Fitch affirmed our revolver credit rating at ‘BBB-’ and upgraded the rating on our senior notes to ‘BBB-’, with a stable outlook. As a result of these investment grade ratings and the satisfaction of certain other conditions, certain restrictive covenants on our credit facility fell away and became more permissive. The leverage ratio and current ratio financial covenants and PV-9 Coverage Ratio are no longer effective, and the Company is required to maintain compliance with a total indebtedness to capitalization ratio, which is the ratio of the Company’s total indebtedness to the sum of total indebtedness plus stockholders’ equity, not to exceed 65%. See Note 4 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion. Issuance of Senior Notes, Senior Notes Tender Offer and Redemption of Debt
In December 2024, we completed our underwritten public offering of $750 million aggregate principal amount of our 5.70% Senior Notes due 2035 (the “2035 Notes”). Additionally, we announced an offer to purchase for cash, any and all of our outstanding 2026 Notes (the “Tender Offer”). Upon expiration of the Tender Offer, approximately 91%, or $453 million, of the 2026 Notes were validly tendered and not validly withdrawn. In a separate transaction during the fourth quarter of 2024, we redeemed all of the $304 million aggregate principal of the SWN 2028 Notes for approximately $312 million, which included an $8 million premium to call the notes.
Additionally, on January 23, 2025, the $389 million aggregate principal of the SWN 2025 Notes (as defined below) was repaid and terminated with cash on hand and borrowings on the Credit Facility. See Note 4 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion. Repurchase Program and Enhanced Returns Framework
In October 2024, our Board of Directors authorized the Company to repurchase up to $1.0 billion, in aggregate, of the Company’s common stock and/or warrants. Additionally, we also announced our enhanced capital returns framework which is designed to more effectively return cash to shareholders and reduce net debt. The plan became effective January 1, 2025, and prioritizes the base dividend of $2.30 per share and a targeted $500 million of annual net debt reduction in 2025, which target will be redetermined annually. Once both have been funded, it is anticipated that 75% of remaining free cash flow will be distributed as market conditions warrant, between share repurchases and additional dividend payments. The remaining free cash flow would be maintained on the balance sheet.
Divestitures
On January 17, 2023, we entered into an agreement to sell a portion of our Eagle Ford assets to WildFire Energy I LLC for approximately $1.425 billion, subject to post-closing adjustments. This transaction closed on March 20, 2023 (with an effective date of October 1, 2022) and resulted in the recognition of a gain of approximately $337 million.
On February 17, 2023, we entered into an agreement to sell a portion of our remaining Eagle Ford assets to INEOS Energy for approximately $1.4 billion, subject to post-closing adjustments. This transaction closed on April 28, 2023 (with an effective date of October 1, 2022) and resulted in the recognition of a gain of approximately $470 million.
On August 11, 2023, we entered into an agreement to sell the final portion of our remaining Eagle Ford assets to SilverBow Resources, Inc. (“SilverBow”) for approximately $700 million, subject to post-closing adjustments. This transaction closed on November 30, 2023 (with an effective date of February 1, 2023) and resulted in the recognition of a gain of approximately $140 million. Due to the satisfaction of certain commodity price triggers, we received an additional $25 million cash consideration during the fourth quarter of 2024.
LNG Agreement
On February 13, 2024, we announced our entrance into an LNG export deal that includes executed Sales and Purchase Agreements (“SPA”) for long-term liquefaction offtake. Under the SPAs, we will purchase approximately 0.5 million tonnes of LNG per annum from Delfin LNG LLC at a Henry Hub price with a contract targeted start date in 2028, then deliver to Gunvor Group Ltd on a free on board basis with the sales price linked to the Japan Korea Market for a period of 20 years.
Investments - Momentum Sustainable Ventures LLC
During the fourth quarter of 2022, we entered into an agreement with Momentum Sustainable Ventures LLC to build a new natural gas gathering pipeline and carbon capture project, which will gather and treat natural gas produced in the Haynesville Shale for re-delivery to Gulf Coast markets, including LNG export. The pipeline is expected to have an initial capacity of 1.7 Bcf/d expandable to 2.2 Bcf/d. The carbon capture portion of the project anticipates capturing approximately 1.0 million tons per annum of CO2 and delivering the CO2 to ExxonMobil Low Carbon Solutions Onshore Storage, LLC for additional transportation and storage. The natural gas gathering pipeline is projected for a potential in-service date in the fourth quarter of 2025. Through the end of 2024, we have made total capital contributions of $296 million to the project.
Economic and Market Conditions
Geopolitical risk and policy uncertainty continue to drive volatility in natural gas, oil and NGL prices, while macroeconomic headwinds in key consuming countries could impact global growth prospects, potentially affecting supply and demand for energy commodities. Domestically, the natural gas market balance has tightened, driven by increasing demand from new LNG export facilities, reduced industry activity levels, and a recent period of colder than average temperatures, providing support for prices in 2025 and 2026. Our future estimated cash flow is partially protected from commodity price volatility due to our current hedge positions that provide a floor price on over half of our projected gas volumes through the end of 2025 with significant upside participation via costless collars. For the foreseeable future, we believe our operational flexibility, cost structure and liquidity position will enable us to successfully navigate continued price volatility.
Rig count reductions across the lower 48 states of the United States led to service cost deflation in 2024 resulting in decreased operating and capital cost. Higher commodity prices in 2025 could lead to increased rig activity across the industry resulting in modest levels of inflation. We continue to monitor these situations, including the recently enacted tariff on steel by the current Presidential Administration, and assess their impact on our business, including business partners and customers. As a result of the Southwestern Merger, we assumed Southwestern’s oilfield service business that will allow for some vertical integration of our exploration and production operations, which may help to control costs and secure inputs for our operations. For additional discussion regarding risk associated with price volatility and economic uncertainty, see Item 1A Risk Factors in this report.
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| Liquidity and Capital Resources |
Liquidity Overview
Our primary sources of capital resources and liquidity are internally generated cash flows from operations and borrowings under our Credit Facility, and our primary uses of cash are for the development of our natural gas and oil properties, acquisitions of additional natural gas and oil properties and return of value to stockholders through dividends and equity repurchases. We believe our cash flow from operations, including from the acquired Southwestern business, cash on hand and unused borrowing capacity under the Credit Facility, as discussed below, will provide sufficient liquidity during the next 12 months and the foreseeable future. As of December 31, 2024, we had $2.8 billion of liquidity available, including $317 million of cash on hand and $2.5 billion of aggregate unused borrowing capacity available under the Credit Facility. As of December 31, 2024, we had no outstanding borrowings under our Credit Facility.
Further, we may from time to time seek to retire, refinance or amend some or all of our outstanding debt or debt agreements through exchanges, open market purchases, privately negotiated transactions, tender offers or otherwise. Such transactions, if any, and the terms thereof, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved in such financing transactions may be material. See Note 4 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion of our debt obligations, including principal and carrying amounts of our senior notes. Dividends
On February 26, 2025, we declared a base quarterly dividend payable of $0.575 per share, which will be paid on March 27, 2025 to stockholders of record at the close of business on March 11, 2025. See Note 10 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion. The declaration and payment of any future dividend, whether fixed or variable, will remain at the full discretion of the Board and will depend on the Company’s financial results, cash requirements, future prospects and other relevant factors. The Company’s ability to pay dividends to its stockholders is restricted by (i) Oklahoma corporate law, (ii) its Certificate of Incorporation, (iii) the terms and provisions of the Credit Agreement governing the Credit Facility and (iv) the terms and provisions of the indentures governing its 5.500% Senior Notes due 2026, 5.875% Senior Notes due 2029, 6.750% Senior Notes due 2029, and 5.70% Senior Notes due 2035 as well as the senior notes assumed from Southwestern, including the 5.375% Senior Notes due 2029, 5.375% Senior Notes due 2030 and 4.750% Senior Notes due 2032.
Derivative and Hedging Activities
Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. We enter into various derivative instruments to mitigate a portion of our exposure to commodity price declines, but these transactions may also limit our cash flows in periods of rising commodity prices. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to better predict the total revenue we expect to receive. See Item 7A Quantitative and Qualitative Disclosures About Market Risk included in Part II of this report for further discussion on the impact of commodity price risk on our financial position.
Contractual Obligations and Off-Balance Sheet Arrangements
As of December 31, 2024, our material contractual obligations include repayment of senior notes, derivative obligations, asset retirement obligations, lease obligations, undrawn letters of credit and various other commitments we enter into in the ordinary course of business that could result in future cash obligations. In addition, we have contractual commitments with midstream companies and pipeline carriers for future gathering, processing and transportation of natural gas to move certain of our production to market. The estimated gross undiscounted future commitments under these agreements were approximately $9.9 billion as of December 31, 2024. As discussed above, we believe our existing sources of liquidity will be sufficient to fund our near and long-term contractual obligations. See Notes 4, 5, 7, 13 and 16 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion. Credit Facility
On December 9, 2022, we entered into the Credit Agreement, as amended by the Initial Credit Agreement Amendment and the Investment Grade Credit Agreement Amendment, maturing in December 2027. The Credit Facility provides for aggregate commitments of $2.5 billion, with a $500 million sublimit available for the issuance of letters of credit and a $50 million sublimit available for swingline loans. As of December 31, 2024, we had approximately $2.5 billion available for borrowings under the Credit Facility.
Borrowings under the Credit Agreement may be alternate base rate loans or term SOFR loans, at the Company’s election. On October 1, 2024, we received an investment grade rating from S&P Global Ratings (“S&P”). S&P assigned an issuer-level rating of ‘BBB-’ on our unsecured debt and raised our issuer credit rating to ‘BBB-’, with a stable outlook. Additionally, on October 2, 2024, we received an investment grade rating from Fitch Ratings (“Fitch”). Fitch affirmed our revolver credit rating at ‘BBB-’ and upgraded the rating on our senior notes to ‘BBB-’, with a stable outlook. As a result of these investment grade ratings and the satisfaction of certain other conditions, (i) the Pre-IG Credit Agreement was automatically amended by the Investment Grade Credit Agreement Amendment, (ii) all liens and guarantees previously provided by the Company and its subsidiaries in connection with the Pre-IG Credit Agreement were released and (iii) all guarantees previously provided in connection with the Company’s senior notes were released. Such Investment Grade Credit Agreement Amendment, among other things, removed the application of the borrowing base provided for in the Pre-IG Credit Agreement and modified the pricing and covenants as discussed in Note 4 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion.
Assumption of Southwestern’s Senior Notes and Southwestern Credit Facility Extinguishment
On October 1, 2024, the Southwestern Merger was completed, and we assumed approximately $3.7 billion of Southwestern’s senior notes. On October 1, 2024, Southwestern’s existing credit facility was terminated, with all loan amounts and other obligations outstanding thereunder repaid in full and all commitments thereunder extinguished, for approximately $585 million, which included all outstanding borrowings, accrued interest and transaction fees. See Note 4 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion. Capital Expenditures
For the year ending December 31, 2025, we currently expect to complete and turn in line 240 to 270 gross wells utilizing approximately 11 to 15 rigs and plan to invest between approximately $2.9 – $3.1 billion in capital expenditures. We currently plan to fund our 2025 capital program through cash on hand, expected cash flow from our operations and borrowings under our Credit Facility. We may alter or change our plans with respect to our capital program and expected capital expenditures based on developments in our business, our financial position, our industry or any of the markets in which we operate.
Sources and (Uses) of Cash and Cash Equivalents
The following table presents the sources and uses of our cash and cash equivalents for the periods presented:
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| | Years Ended December 31, |
| | | 2024 | | 2023 | | 2022 |
| Cash provided by operating activities | | $ | 1,565 | | | $ | 2,380 | | | $ | 4,125 | |
| Proceeds from divestitures of property and equipment | | 21 | | | 2,533 | | | 407 | |
| Proceeds from Credit Facility, net | | — | | | — | | | 1,050 | |
| Receipts of deferred consideration | | 166 | | | — | | | — | |
| Proceeds from issuance of senior notes, net | | 747 | | | — | | | — | |
| Proceeds from warrant exercise | | 3 | | | — | | | 27 | |
| Capital expenditures | | (1,557) | | | (1,829) | | | (1,823) | |
| Contributions to investments | | (75) | | | (231) | | | (18) | |
| Payments on Credit Facility, net | | — | | | (1,050) | | | — | |
| Payments on Exit Credit Facility, net | | — | | | — | | | (221) | |
| Business combination, net | | (459) | | | — | | | (1,967) | |
| Cash paid to purchase debt | | (767) | | | — | | | — | |
| Debt issuance and other financing costs | | (11) | | | — | | | (17) | |
| Cash paid to repurchase and retire common stock | | — | | | (355) | | | (1,073) | |
| Cash paid for common stock dividends | | (388) | | | (487) | | | (1,212) | |
| Other | | (3) | | | — | | | — | |
| Net increase (decrease) in cash, cash equivalents and restricted cash | | $ | (758) | | | $ | 961 | | | $ | (722) | |
Cash Flow from Operating Activities
Cash provided by operating activities was $1.57 billion, $2.38 billion and $4.12 billion during the years ended December 31, 2024, 2023 and 2022, respectively. The decrease in 2024 is primarily due to lower prices for the natural gas, oil and NGL we sold. The decrease in 2023 is primarily due to lower prices for the natural gas, oil and NGL we sold as well as decreased sales volumes related to our Eagle Ford divestitures. Cash flows from operations are largely affected by the same factors that affect our net income, excluding various non-cash items, such as depreciation, depletion and amortization, certain impairments, gains or losses on sales of assets, deferred income taxes and mark-to-market changes in our open derivative instruments. See further discussion below under Results of Operations.
Proceeds from Divestitures of Property and Equipment
In 2023, we sold our Eagle Ford assets through three separate transactions resulting in total cash proceeds of $2.5 billion after customary post-closing adjustments. In 2022, we sold our Powder River Basin assets to Continental Resources, Inc. for approximately $400 million after customary closing adjustments. See Note 2 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion. Proceeds from Credit Facility, net
In 2022, we borrowed a net $1.05 billion under the Credit Facility. We utilized these borrowings to terminate the Exit Credit Facility. A portion of the borrowings under the Credit Facility were repaid with internally generated cash provided by operating activities.
Receipts of Deferred Consideration
During 2024, we received $166 million in deferred consideration associated with our Eagle Ford divestiture transactions. See Note 2 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion. Proceeds from Issuance of Senior Notes, net
In 2024, we completed our underwritten public offering of $750 million aggregate principal amount of our 5.70% Senior Notes due 2035. See Note 4 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion. Capital Expenditures
Our capital expenditures during the year ended December 31, 2024 decreased compared to the year ended December 31, 2023, primarily as a result of decreased drilling and completion activity within our Northeast Appalachia and Haynesville operating areas, as well as reduced activity in Eagle Ford due to our Eagle Ford divestitures. Our capital expenditures during the year ended December 31, 2023 were in line with the capital expenditures during the year ended December 31, 2022, primarily as a result of increased drilling and completion activity within our Haynesville operating area, partially offset by reduced activity due to our Eagle Ford divestitures. During the year ended December 31, 2024, our average operated rig count was 9 rigs and 133 spud wells, compared to an average operated rig count of 11 rigs and 193 spud wells in the year ended December 31, 2023 and 14 rigs and 217 spud wells in the year ended December 31, 2022. We completed 81 operated wells in the year ended December 31, 2024 compared to 166 in the year ended December 31, 2023 and 216 in the year ended December 31, 2022.
Contributions to Investments
During the years ended December 31, 2024, 2023 and 2022, contributions to investments primarily consisted of contributions to our investment with Momentum Sustainable Ventures LLC to build a new natural gas gathering pipeline and carbon capture project. See Note 15 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for additional information. Payments on Credit Facility, net
During the year ended December 31, 2023, we made net repayments of $1.05 billion on the Credit Facility, utilizing a portion of the proceeds from the Eagle Ford divestitures and internally generated cash provided by operating activities.
Payments on Exit Credit Facility, net
In December 2022, we entered into the Credit Facility and terminated the Exit Credit Facility, repaying all amounts outstanding and extinguishing all commitments thereunder.
Business Combination, net
In connection with the completion of the Southwestern Merger during 2024, we terminated Southwestern’s existing credit facility, with all loan amounts and other obligations outstanding thereunder repaid in full and all commitments thereunder extinguished, for approximately $585 million utilizing cash on hand as well as the cash assumed from Southwestern. During the year ended December 31, 2022, we completed the Marcellus Acquisition for approximately $2 billion and 9.4 million shares of our common stock. See Note 2 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion of these acquisitions.
Cash Paid to Purchase Debt
In 2024, we announced an offer to purchase for cash, any and all of our outstanding 2026 Notes, the “Tender Offer”. Upon expiration of the Tender Offer, approximately 91%, or $453 million, of the 2026 Notes were validly tendered and not validly withdrawn. In a separate transaction during the fourth quarter of 2024, we redeemed all of the $304 million aggregate principal of the 2028 Notes assumed in the Southwestern Merger for approximately $312 million, which included an $8 million premium to call the notes. See Note 4 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion. Debt Issuance and Other Financing Costs
During 2024, we paid $11 million of one-time fees to lenders related to the changes to our Credit Facility as well as for the issuance of the 2035 Senior Notes. During 2022, we paid $17 million of one-time fees to lenders to establish the Credit Facility.
Cash Paid to Repurchase and Retire Common Stock
We did not repurchase any shares during 2024. During 2023, we repurchased 4.4 million shares of our common stock for an aggregate cost of approximately $355 million. During 2022, we repurchased 11.7 million shares of our common stock for an aggregate cost of $1.1 billion. The repurchased shares of common stock were retired and recorded as a reduction to common stock and retained earnings. See Note 10 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion. Cash Paid for Common Stock Dividends
As part of our dividend program, we paid common stock dividends of $388 million, $487 million and $1.2 billion during the years ended December 31, 2024, 2023 and 2022, respectively. See Note 10 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion.
Year ended December 31, 2024 compared to the year ended December 31, 2023
Below is a discussion of changes in our results of operations for 2024 compared to 2023. The results of operations discussed below include amounts pertaining to Southwestern after the merger closed on October 1, 2024. A discussion of changes in our results of operations for 2023 compared to 2022 has been omitted from this Form 10-K, but may be found in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our Form 10-K for the year ended December 31, 2023 as filed with the SEC on February 21, 2024. Natural Gas, Oil and NGL Production and Average Sales Prices
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| | Year Ended December 31, 2024 |
| | Natural Gas | | Oil | | NGL | | Total |
| | MMcf per day | | $/Mcf | | MBbl per day | | $/Bbl | | MBbl per day | | $/Bbl | | MMcfe per day | | $/Mcfe |
| Haynesville | | 1,532 | | | 2.14 | | | — | | | — | | | — | | | — | | | 1,532 | | | 2.14 | |
| Northeast Appalachia | | 1,809 | | | 1.88 | | | — | | | — | | | — | | | — | | | 1,809 | | | 1.88 | |
| Southwest Appalachia | | 270 | | | 2.42 | | | 3 | | | 60.41 | | | 21 | | | 27.44 | | | 417 | | | 3.42 | |
| Total | | 3,611 | | | 2.03 | | | 3 | | | 60.41 | | | 21 | | | 27.44 | | | 3,758 | | | 2.16 | |
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| Average NYMEX Price | | | | 2.27 | | | | | 75.72 | | | | | | | | | |
| Average Realized Price (including realized derivatives) | | | | 2.75 | | | | | 61.04 | | | | | 26.91 | | | | | 2.84 | |
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| | Year Ended December 31, 2023 |
| | Natural Gas | | Oil | | NGL | | Total |
| | MMcf per day | | $/Mcf | | MBbl per day | | $/Bbl | | MBbl per day | | $/Bbl | | MMcfe per day | | $/Mcfe |
| Haynesville | | 1,551 | | | 2.30 | | | — | | | — | | | — | | | — | | | 1,551 | | | 2.30 | |
| Northeast Appalachia | | 1,834 | | | 2.22 | | | — | | | — | | | — | | | — | | | 1,834 | | | 2.22 | |
| | | | | | | | | | | | | | | | |
| Eagle Ford | | 85 | | | 2.25 | | | 21 | | | 77.80 | | | 10 | | | 25.62 | | | 274 | | | 7.64 | |
| Total | | 3,470 | | | 2.25 | | | 21 | | | 77.80 | | | 10 | | | 25.62 | | | 3,659 | | | 2.66 | |
| | | | | | | | | | | | | | | | |
| Average NYMEX Price | | | | 2.74 | | | | | 77.63 | | | | | | | | | |
| Average Realized Price (including realized derivatives) | | | | 2.64 | | | | | 72.89 | | | | | 25.62 | | | | | 2.99 | |
Natural Gas, Oil and NGL Sales
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| | Year Ended December 31, 2024 |
| | Natural Gas | | Oil | | NGL | | Total |
| Haynesville | | $ | 1,205 | | | $ | — | | | $ | — | | | $ | 1,205 | |
| Northeast Appalachia | | 1,242 | | | — | | | — | | | 1,242 | |
| Southwest Appalachia | | 239 | | | 69 | | | 214 | | | 522 | |
| Total natural gas, oil and NGL sales | | $ | 2,686 | | | $ | 69 | | | $ | 214 | | | $ | 2,969 | |
| | | | | | | | |
| | Year Ended December 31, 2023 |
| | Natural Gas | | Oil | | NGL | | Total |
| Haynesville | | $ | 1,300 | | | $ | — | | | $ | — | | | $ | 1,300 | |
| Northeast Appalachia | | 1,483 | | | — | | | — | | | 1,483 | |
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| Eagle Ford | | 70 | | | 596 | | | 98 | | | 764 | |
| Total natural gas, oil and NGL sales | | $ | 2,853 | | | $ | 596 | | | $ | 98 | | | $ | 3,547 | |
Natural gas, oil and NGL sales in 2024 decreased $578 million compared to 2023. Lower average prices, which were consistent with the downward trend in index prices for gas and oil, drove a $426 million decrease in 2024. The Eagle Ford divestitures resulted in a $764 million decrease. Additionally, planned curtailments and activity deferrals led to lower sales volumes in Haynesville and Northeast Appalachia for decreases of $243 million and $167 million, respectively. These decreases were partially offset by a $1.0 billion increase due to the Southwestern Merger.
Production Expenses
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2024 | | 2023 |
| | | | $/Mcfe | | | | $/Mcfe |
| Haynesville | | $ | 170 | | | 0.30 | | | $ | 185 | | | 0.33 | |
| Northeast Appalachia | | 97 | | | 0.15 | | | 81 | | | 0.12 | |
| Southwest Appalachia | | 49 | | | 0.32 | | | — | | | — | |
| Eagle Ford | | — | | | — | | | 90 | | | 0.91 | |
| Total production expenses | | $ | 316 | | | 0.23 | | | $ | 356 | | | 0.27 | |
Production expenses in 2024 decreased $40 million compared to 2023. The decrease was primarily due to a $90 million decrease due to the Eagle Ford divestitures, which was partially offset by a $49 million increase in Southwest Appalachia due to the Southwestern Merger. Haynesville had a net decrease of $15 million due to a $51 million decrease in workover activity, saltwater disposal expenses and treating expenses, partially offset by a $36 million increase related to the Southwestern Merger. Northeast Appalachia increased $16 million due to an additional $22 million of expense related to the Southwestern Merger, partially offset by a $6 million decrease related to lower workover expense, saltwater disposal and repairs and maintenance.
Gathering, Processing and Transportation Expenses (“GP&T”)
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| | Years Ended December 31, |
| | 2024 | | 2023 |
| | | | $/Mcfe | | | | $/Mcfe |
| Haynesville | | $ | 326 | | | 0.58 | | | $ | 263 | | | 0.46 | |
| Northeast Appalachia | | 507 | | | 0.77 | | | 433 | | | 0.65 | |
| Southwest Appalachia | | 202 | | | 1.33 | | | — | | | — | |
| Eagle Ford | | — | | | — | | | 157 | | | 1.57 | |
| Total GP&T | | $ | 1,035 | | | 0.75 | | | $ | 853 | | | 0.64 | |
Gathering, processing and transportation expenses in 2024 increased $182 million compared to 2023. The increase was primarily due to a $404 million increase related to the Southwestern Merger. The increase was partially offset by a $157 million decrease due to the Eagle Ford divestitures. Additionally, curtailments led to decreased volumes resulting in decreases of $58 million and $66 million in Haynesville and Northeast Appalachia, respectively. These decreases were partially offset by increases of $11 million and $48 million related to rate increases in Haynesville and Northeast Appalachia, respectively.
Severance and Ad Valorem Taxes
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| | Years Ended December 31, |
| | 2024 | | 2023 |
| | | | $/Mcfe | | | | $/Mcfe |
| Haynesville | | $ | 60 | | | 0.11 | | | $ | 105 | | | 0.19 | |
| Northeast Appalachia | | 15 | | | 0.02 | | | 14 | | | 0.02 | |
| Southwest Appalachia | | 22 | | | 0.14 | | | — | | | — | |
| Eagle Ford | | — | | | — | | | 48 | | | 0.48 | |
| Total severance and ad valorem taxes | | $ | 97 | | | 0.07 | | | $ | 167 | | | 0.13 | |
Severance and ad valorem taxes in 2024 decreased $70 million compared to 2023. The decrease was primarily related to a $48 million decrease due to the Eagle Ford divestitures and a $50 million decrease in Haynesville, which was driven by a decrease in the statutory severance tax rates. These decreases were partially offset by an increase of $5 million in Haynesville and an increase of $22 million in Southwest Appalachia due to the Southwestern Merger.
Natural Gas, Oil and NGL Derivatives | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2024 | | 2023 |
| Natural gas derivatives - realized gains | | $ | 919 | | | $ | 488 | |
| Natural gas derivatives - unrealized gains (losses) | | (951) | | | 1,199 | |
| Total gains (losses) on natural gas derivatives | | $ | (32) | | | $ | 1,687 | |
| | | | |
| Oil derivatives - realized gains (losses) | | $ | 1 | | | $ | (38) | |
| Oil derivatives - unrealized gains | | (3) | | | 88 | |
| Total gains (losses) on oil derivatives | | $ | (2) | | | $ | 50 | |
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| NGL derivatives - realized losses | | $ | (4) | | | $ | — | |
| NGL derivatives - unrealized losses | | (13) | | | — | |
| Total losses on NGL derivatives | | $ | (17) | | | $ | — | |
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| Contingent consideration - realized gains | | $ | 25 | | | $ | — | |
| Contingent consideration - unrealized losses | | (12) | | | (9) | |
| Total gains (losses) on contingent consideration | | $ | 13 | | | $ | (9) | |
| Total gains (losses) on natural gas, oil and NGL derivatives | | $ | (38) | | | $ | 1,728 | |
See Note 13 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for a complete discussion of our derivative activity. Marketing Revenues and Expenses
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| | Years Ended December 31, |
| | 2024 | | 2023 |
| Marketing revenues | | $ | 1,290 | | | $ | 2,500 | |
| Marketing expenses | | 1,310 | | | 2,499 | |
| Marketing margin | | $ | (20) | | | $ | 1 | |
Marketing revenues and expenses decreased in 2024 compared to 2023 as a result of decreased oil marketing activities, primarily as a result of the Eagle Ford divestitures in 2023.
Exploration Expenses
During 2024, exploration expense of $10 million was primarily the result of $6 million of non-cash impairment charges on unproved properties and $3 million of geological and geophysical expense. During 2023, exploration expense of $27 million was primarily the result of $12 million of non-cash impairment charges on unproved properties and $11 million of geological and geophysical expense.
General and Administrative Expenses
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| | Years Ended December 31, |
| | 2024 | | 2023 |
| Total G&A, net | | $ | 186 | | | $ | 127 | |
| G&A, net per Mcfe | | $ | 0.14 | | | $ | 0.09 | |
Total general and administrative expenses, net during 2024 increased $59 million compared to 2023, primarily due to a decrease in our producing well count following the Eagle Ford divestitures, which reduced our allocations and reimbursements of G&A. Additionally, compensation and other corporate expenses increased following the Southwestern Merger.
Separation and Other Termination Costs
During 2024 and 2023, we recognized $23 million and $5 million, respectively, of separation and other termination costs related to one-time termination benefits for certain employees.
Depreciation, Depletion and Amortization
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| | Years Ended December 31, |
| | 2024 | | 2023 |
| DD&A | | $ | 1,729 | | | $ | 1,527 | |
| DD&A per Mcfe | | $ | 1.26 | | | $ | 1.14 | |
The absolute increase in depreciation, depletion and amortization for 2024 compared to 2023 is primarily related to the Southwestern Merger. Depreciation, depletion and amortization per Mcfe increased for 2024 compared to 2023 primarily related to production curtailments during 2024.
Other Operating Expense, Net
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| | Years Ended December 31, |
| | 2024 | | 2023 |
| Other operating expense, net | | $ | 332 | | | $ | 18 | |
During 2024, we recognized approximately $312 million of costs related to the Southwestern Merger, which included $148 million related to employee expenses and the remainder of the costs relating to transaction fees, consulting and legal fees and other fees related to the transaction.
Interest Expense
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| | Years Ended December 31, |
| | 2024 | | 2023 |
| Interest expense on debt | | $ | 181 | | | $ | 143 | |
| | | | |
| Amortization of premium, discount, issuance costs and other | | (7) | | | (9) | |
| Capitalized interest | | (51) | | | (30) | |
| Total interest expense | | $ | 123 | | | $ | 104 | |
The increase in total interest expense 2024 compared to 2023, was primarily due to our assumption of Southwestern’s Senior Notes as a result of the Southwestern Merger, which resulted in an increase in interest expense on debt. Additionally, our capitalized interest increased in 2024 compared to 2023 primarily as a result of the capitalized interest related to our investment with Momentum Sustainable Ventures LLC. See Note 4 and Note 15 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for additional discussion.
Other Income, net
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| | Years Ended December 31, | | | | |
| | 2024 | | 2023 | | | | |
| Other income, net | | $ | 86 | | | $ | 79 | | | | | |
Other income during the time periods presented above primarily consists of interest income and deferred consideration amortization. The increase in 2024 compared to 2023 was primarily due to increased interest income related to our higher average cash balance in 2024.
Income Tax Expense (Benefit)
We recorded an income tax benefit of $127 million in 2024. Of this amount, $4 million is related to current federal and state income tax benefit, and the remainder is related to deferred federal and state income taxes. We recorded income tax expense of $698 million in 2023. Of this amount, $270 million is related to current federal and state income taxes, and the remainder is related to deferred federal and state income taxes. See Note 9 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for a discussion of income tax expense (benefit).
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| Critical Accounting Estimates |
The preparation of financial statements in accordance with accounting principles generally accepted in the United States require us to make estimates and assumptions. The accounting estimates and assumptions that involve a significant level of estimation uncertainty and have or are reasonably likely to have a material impact on our financial condition or results of operations are discussed below. Our management has discussed each critical accounting estimate with the Audit Committee of our Board of Directors.
Natural Gas and Oil Reserves. Estimates of natural gas and oil reserves and their values, future production rates, future development costs and commodity pricing differentials are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in natural gas, oil or NGL prices could result in actual results differing significantly from our estimates. See Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities included in Item 8 of Part II of this report for further information. Accounting for Business Combinations. We account for business combinations using the acquisition method, which is the only method permitted under FASB ASC Topic 805 – Business Combinations and involves the use of significant judgment. Under the acquisition method of accounting, a business combination is accounted for at a purchase price based on the fair value of the consideration given. The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess, if any, of the consideration given to acquire an entity over the net amounts assigned to its assets acquired and liabilities assumed is recognized as goodwill. The excess, if any, of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity is recognized immediately to earnings as a gain from bargain purchase.
The Company’s principal assets are its natural gas and oil properties, which are accounted for under the successful efforts accounting method. The Company determines the fair value of acquired natural gas and oil properties based on the discounted future net cash flows expected to be generated from these assets. Discounted cash flow models by operating area are prepared using the estimated future revenues and operating costs for all proved developed properties and undeveloped properties comprising the proved and unproved reserves. Significant inputs associated with the calculation of discounted future net cash flows include estimates of (i) future production volumes based on estimated reserves, (ii) future operating and development costs, (iii) future commodity prices escalated by an inflationary rate after three years, adjusted for differentials, and (iv) a market-based weighted average cost of capital by operating area. The Company utilizes NYMEX strip pricing, adjusted for differentials, to value the reserves. The NYMEX strip pricing inputs used are classified as Level 1 fair value assumptions and all other inputs are classified as Level 3 fair value assumptions. The discount rates utilized are derived using a weighted average cost of capital computation, which includes an estimated cost of debt and equity for market participants with similar geographies and asset development type by operating area.
See Note 2 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for additional information on our business combinations, including the Southwestern Merger, which was completed on October 1, 2024. Income Taxes. Income taxes are accounted for using the asset and liability method as required by GAAP. Deferred tax assets and liabilities arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. Deferred tax assets for tax attributes such as NOL carryforwards and disallowed business interest carryforwards are also recognized. Deferred tax assets represent potential future tax benefits and are reduced by a valuation allowance if it is more likely than not that such benefits will not be realized.
In assessing the need for a valuation allowance or adjustments to existing valuation allowances, one source of evidence is a projection of income exclusive of existing timing differences. Our judgement regarding the realizability of deferred tax assets is thus partially affected by estimates of future financial condition.
We also routinely assess potential uncertain tax positions and, if required, establish accruals for such positions. Accounting guidance for recognizing and measuring uncertain tax positions requires that a more likely than not threshold condition be met on a tax position, based solely on its technical merits of being sustained, before any benefit of the uncertain tax position can be recognized in the financial statements. If it is more likely than not a tax position will be sustained, we measure and recognize the position following a cumulative probability estimate.
Impairments. Long-lived assets used in operations, including proved gas and oil properties, are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows expected to be generated by an asset group. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. If there is an indication the carrying amount of an asset may not be recovered, the asset is assessed by management through an established process in which changes to significant assumptions such as prices, volumes, and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value by discounting using a weighted average cost of capital. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is assessed by management using the income approach. Level 3 inputs associated with the calculation of discounted cash flows used in the impairment analysis include our estimate of future natural gas and crude oil prices, production costs, development expenditures, anticipated production of proved reserves and other relevant data. Additionally, we utilize NYMEX strip pricing, adjusted for differentials, to value the reserves.
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| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk |
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our exposure to market risk. The term market risk relates to our risk of loss arising from adverse changes in natural gas, oil and NGL prices and interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. The forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.
Commodity Price Risk
Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL, which have historically been volatile. To mitigate a portion of our exposure to adverse price changes, we enter into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the revenue we will receive. We believe our derivative instruments continue to be highly effective in achieving our risk management objectives.
We determine the fair value of our derivative instruments utilizing established index prices, volatility curves and discount factors. These estimates are compared to counterparty valuations for reasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. Future risk related to counterparties not being able to meet their obligations has been partially mitigated under our commodity hedging arrangements that require counterparties to post collateral if their obligations to us are in excess of defined thresholds. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. See Note 13 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further discussion of the fair value measurements associated with our derivatives. For the year ended December 31, 2024, natural gas, oil and NGL revenues, excluding any effect of our derivative instruments, were $2,686 million, $69 million, and $214 million, respectively. Based on production, natural gas, oil and NGL revenue for the year ended December 31, 2024 would have increased or decreased by approximately $269 million, $7 million, and $21 million, respectively, for each 10% increase or decrease in prices. As of December 31, 2024, the fair value of our natural gas and NGL derivatives were net liabilities of $49 million and $9 million, respectively. As of December 31, 2024, the fair value of our oil derivatives was a net asset of $4 million. A 10% increase in forward gas prices would decrease the valuation of natural gas derivatives by approximately $493 million, while a 10% decrease would increase the valuation by approximately $482 million. A 10% fluctuation in forward oil prices would impact the valuation of oil derivatives by approximately $4 million. A 10% fluctuation in forward NGL prices would impact the valuation of NGL derivatives by $18 million. This fair value change assumes volatility based on prevailing market parameters at December 31, 2024. See Note 13 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for further information on our open derivative positions. Interest Rate Risk
Our exposure to interest rate changes relates primarily to borrowings under our Credit Facility. Interest is payable on borrowings under the Credit Facility based on floating rates. See Note 4 of the notes to our consolidated financial statements included in Item 8 of Part II of this report for additional information. As of December 31, 2024, we did not have any outstanding borrowings under our Credit Facility.
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| Item 8. | Financial Statements and Supplementary Data |
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| INDEX TO FINANCIAL STATEMENTS EXPAND ENERGY CORPORATION AND SUBSIDIARIES | |
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Expand Energy Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Expand Energy Corporation and its subsidiaries (the "Company") as of December 31, 2024 and 2023, and the related consolidated statements of operations, of stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 2024, including the related notes (collectively referred to as the "consolidated financial statements"). We also have audited the Company's internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As described in Management’s Report on Internal Control over Financial Reporting, management has excluded Southwestern Energy from its assessment of internal control over financial reporting as of December 31, 2024, because it was acquired by the Company in a purchase business combination during 2024. We have also excluded Southwestern Energy from our audit of internal control over financial reporting. Southwestern Energy is a wholly-owned subsidiary whose total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting represent 56% and 35%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2024.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting
includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
The Impact of Proved Developed Natural Gas and Oil Reserves on Proved Natural Gas and Oil Properties, Net
As described in Note 1 to the consolidated financial statements, the Company's property and equipment, net balance was $24.3 billion as of December 31, 2024, and the related depreciation, depletion and amortization expense for the year ended December 31, 2024 was $1.7 billion, both of which substantially related to proved natural gas and oil properties. The Company follows the successful efforts method to account for its natural gas and oil properties. Under this method, all capitalized well costs and leasehold costs of proved natural gas and oil properties are depreciated using the unit-of-production depreciation method based on total estimated proved developed natural gas and oil reserves. As disclosed by management, estimates of natural gas and oil reserves and their values, future production rates, future development costs and commodity pricing differentials are the most significant of management’s estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. The estimates of proved natural gas and oil reserves have been developed by specialists, specifically the Company’s reservoir engineers, and assessed by independent petroleum engineers (together “management’s specialists”).
The principal considerations for our determination that performing procedures relating to the impact of proved developed natural gas and oil reserves on proved natural gas and oil properties, net is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the estimates of proved developed natural gas and oil reserves and (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved developed natural gas and oil reserves.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved developed natural gas and oil reserves. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimates of proved developed natural gas and oil reserves. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included (i) evaluating the methods and assumptions used by the specialists; (ii) testing the completeness and accuracy of the underlying data used by the specialists related to historical production volumes; and (iii) evaluating the specialists’ findings related to future production volumes by comparing the future production volumes to relevant historical and current period production volumes, as applicable.
Southwestern Merger – Valuation of Proved Natural Gas and Oil Properties
As described in Note 2 to the consolidated financial statements, on October 1, 2024, the Company completed the merger with Southwestern (“Southwestern Merger”) and recorded estimated fair values of the acquired proved natural gas and oil properties of approximately $10.0 billion. As disclosed by management, management determines the fair value of acquired natural gas and oil properties based on the discounted future net cash flows expected to be generated from these assets. Discounted cash flow models by operating area are prepared using the estimated future revenues and operating costs for all proved developed properties. Significant inputs associated with the calculation of discounted future net cash flows include estimates of (i) future production volumes based on estimated reserves, (ii) future operating and development costs, (iii) future commodity prices escalated by an inflationary rate after three years, adjusted for differentials, and (iv) a market-based weighted average cost of capital by operating area.
The principal considerations for our determination that performing procedures relating to the valuation of proved natural gas and oil properties acquired in the Southwestern Merger is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the fair value estimate of the proved natural gas and oil properties acquired; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to future production volumes based on estimated reserves, future operating costs; future commodity prices escalated by an inflationary rate after three years, adjusted for differentials, and a market-based weighted average cost of capital by operating area; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to acquisition accounting, including controls over the valuation of proved natural gas and oil properties acquired. These procedures also included, among others (i) reading the merger agreement; (ii) testing management’s process for developing the fair value estimate of proved natural gas and oil properties acquired; (iii) evaluating the appropriateness of the discounted cash flow model; (iv) testing the completeness and accuracy of underlying data used in the discounted cash flow model; and (v) evaluating the reasonableness of the significant assumptions used by management related to future production volumes based on estimated reserves, future operating costs, future commodity prices escalated by an inflationary rate after three years, adjusted for differentials, and a market-based weighted average cost of capital by operating area. Evaluating the reasonableness of management’s assumption related to future operating costs involved considering the reasonableness of the costs as compared to the past performance of the acquired business. Evaluating the reasonableness of management’s assumption related to future commodity prices, adjusted for differentials, involved comparing the prices against observable market data and evaluating the reasonableness of the differentials as compared to the past performance of the acquired business. Professionals with specialized skill and knowledge were used to assist in evaluating (i) the appropriateness of the discounted cash flow model; (ii) the reasonableness of the market-based weighted average cost of capital by operating area assumption; and (iii) the reasonableness of the inflationary rate after three years used to escalate commodity prices. The work of management’s specialists was used in performing procedures to evaluate the reasonableness of the future production volumes based on estimated reserves used in the discounted cash flow model. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluating the methods and assumptions used by the specialists, testing the completeness and accuracy of the data used by the specialists related to historical production volumes, and evaluating the specialists’ findings related to future production volumes by comparing the future production volumes to relevant historical and current period production volumes, as applicable.
/s/ PricewaterhouseCoopers LLP
Oklahoma City, Oklahoma
February 26, 2025
We have served as the Company’s auditor since 1992.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
| | | | | | | | | | | | | | |
| ($ in millions, except per share data) | | December 31, 2024 | | December 31, 2023 |
| Assets | | | | |
| Current assets: | | | | |
| Cash and cash equivalents | | $ | 317 | | | $ | 1,079 | |
| Restricted cash | | 78 | | | 74 | |
| Accounts receivable, net | | 1,226 | | | 593 | |
| Derivative assets | | 84 | | | 637 | |
| | | | |
| Other current assets | | 292 | | | 226 | |
| Total current assets | | 1,997 | | | 2,609 | |
| Property and equipment: | | | | |
| Natural gas and oil properties, successful efforts method | | | | |
| Proved natural gas and oil properties | | 23,093 | | | 11,468 | |
| Unproved properties | | 5,897 | | | 1,806 | |
| Other property and equipment | | 654 | | | 497 | |
| Total property and equipment | | 29,644 | | | 13,771 | |
| Less: accumulated depreciation, depletion and amortization | | (5,362) | | | (3,674) | |
| | | | |
| Total property and equipment, net | | 24,282 | | | 10,097 | |
| Long-term derivative assets | | 1 | | | 74 | |
| Deferred income tax assets | | 589 | | | 933 | |
| Other long-term assets | | 1,025 | | | 663 | |
| Total assets | | $ | 27,894 | | | $ | 14,376 | |
| | | | |
| Liabilities and stockholders' equity | | | | |
| Current liabilities: | | | | |
| Accounts payable | | $ | 777 | | | $ | 425 | |
| Current maturities of long-term debt, net | | 389 | | | — | |
| Accrued interest | | 100 | | | 39 | |
| Derivative liabilities | | 71 | | | 3 | |
| Other current liabilities | | 1,786 | | | 847 | |
| Total current liabilities | | 3,123 | | | 1,314 | |
| Long-term debt, net | | 5,291 | | | 2,028 | |
| Long-term derivative liabilities | | 68 | | | 9 | |
| Asset retirement obligations, net of current portion | | 499 | | | 265 | |
| Long-term contract liabilities | | 1,227 | | | — | |
| Other long-term liabilities | | 121 | | | 31 | |
| Total liabilities | | 10,329 | | | 3,647 | |
Contingencies and commitments (Note 5) | | | | |
| Stockholders' equity: | | | | |
| Common stock, $0.01 par value, 450,000,000 shares authorized: 231,769,886 and 130,789,936 shares issued | | 2 | | | 1 | |
| Additional paid-in capital | | 13,687 | | | 5,754 | |
| Retained earnings | | 3,876 | | | 4,974 | |
| Total stockholders' equity | | 17,565 | | | 10,729 | |
| Total liabilities and stockholders' equity | | $ | 27,894 | | | $ | 14,376 | |
The accompanying notes are an integral part of these consolidated financial statements.
75
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| ($ in millions, except per share data) | | 2024 | | 2023 | | 2022 |
| Revenues and other: | | | | | | |
| Natural gas, oil and NGL | | $ | 2,969 | | | $ | 3,547 | | | $ | 9,892 | |
| Marketing | | 1,290 | | | 2,500 | | | 4,231 | |
| Natural gas, oil and NGL derivatives | | (38) | | | 1,728 | | | (2,680) | |
| Gains on sales of assets | | 14 | | | 946 | | | 300 | |
| Total revenues and other | | 4,235 | | | 8,721 | | | 11,743 | |
| Operating expenses: | | | | | | |
| Production | | 316 | | | 356 | | | 475 | |
| Gathering, processing and transportation | | 1,035 | | | 853 | | | 1,059 | |
| Severance and ad valorem taxes | | 97 | | | 167 | | | 242 | |
| Exploration | | 10 | | | 27 | | | 23 | |
| Marketing | | 1,310 | | | 2,499 | | | 4,215 | |
| General and administrative | | 186 | | | 127 | | | 142 | |
| Separation and other termination costs | | 23 | | | 5 | | | 5 | |
| Depreciation, depletion and amortization | | 1,729 | | | 1,527 | | | 1,753 | |
| | | | | | |
| Other operating expense, net | | 332 | | | 18 | | | 49 | |
| Total operating expenses | | 5,038 | | | 5,579 | | | 7,963 | |
| Income (loss) from operations | | (803) | | | 3,142 | | | 3,780 | |
| Other income (expense): | | | | | | |
| Interest expense | | (123) | | | (104) | | | (160) | |
| Losses on purchases, exchanges or extinguishments of debt | | (1) | | | — | | | (5) | |
| Other income, net | | 86 | | | 79 | | | 36 | |
| Total other income (expense) | | (38) | | | (25) | | | (129) | |
| Income (loss) before income taxes | | (841) | | | 3,117 | | | 3,651 | |
| Income tax expense (benefit) | | (127) | | | 698 | | | (1,285) | |
| Net income (loss) | | (714) | | 2,419 | | 4,936 |
| Deemed dividend on warrants | | — | | | — | | | (67) | |
| Net income (loss) available to common stockholders | | $ | (714) | | | $ | 2,419 | | | $ | 4,869 | |
| Earnings (loss) per common share: | | | | | | |
| Basic | | $ | (4.55) | | | $ | 18.21 | | | $ | 38.71 | |
| Diluted | | $ | (4.55) | | | $ | 16.92 | | | $ | 33.36 | |
| Weighted average common shares outstanding (in thousands): | | | | | | |
| Basic | | 156,989 | | 132,840 | | 125,785 |
| Diluted | | 156,989 | | 142,976 | | 145,961 |
The accompanying notes are an integral part of these consolidated financial statements.
76
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, |
| ($ in millions) | | 2024 | | 2023 | | 2022 |
| Cash flows from operating activities: | | | | | | |
| Net income (loss) | | $ | (714) | | | $ | 2,419 | | | $ | 4,936 | |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | | |
| Depreciation, depletion and amortization | | 1,729 | | | 1,527 | | | 1,753 | |
| Deferred income tax expense (benefit) | | (123) | | | 428 | | | (1,332) | |
| Derivative (gains) losses, net | | 38 | | | (1,728) | | | 2,680 | |
| Cash receipts (payments) on derivative settlements, net | | 947 | | | 354 | | | (3,561) | |
| Share-based compensation | | 38 | | | 33 | | | 22 | |
| Gains on sales of assets | | (14) | | | (946) | | | (300) | |
| | | | | | |
| Contract amortization | | (57) | | | — | | | — | |
| | | | | | |
| Losses on purchases, exchanges or extinguishments of debt | | 1 | | | — | | | 5 | |
| Other | | 35 | | | 18 | | | 45 | |
| Changes in assets and liabilities | | (315) | | | 275 | | | (123) | |
| Net cash provided by operating activities | | 1,565 | | 2,380 | | 4,125 |
| Cash flows from investing activities: | | | | | | |
| Capital expenditures | | (1,557) | | | (1,829) | | | (1,823) | |
| Receipts of deferred consideration | | 166 | | | — | | | — | |
| Business combination, net | | (459) | | | — | | | (1,967) | |
| Contributions to investments | | (75) | | | (231) | | | (18) | |
| Proceeds from divestitures of property and equipment | | 21 | | | 2,533 | | | 407 | |
| Net cash provided by (used in) investing activities | | (1,904) | | 473 | | (3,401) |
| Cash flows from financing activities: | | | | | | |
| Proceeds from Credit Facility | | 20 | | | 1,125 | | | 1,600 | |
| Payments on Credit Facility | | (20) | | | (2,175) | | | (550) | |
| Proceeds from Exit Credit Facility | | — | | | — | | | 9,583 | |
| Payments on Exit Credit Facility | | — | | | — | | | (9,804) | |
| | | | | | |
| Proceeds from issuance of senior notes, net | | 747 | | | — | | | — | |
| | | | | | |
| | | | | | |
| Proceeds from warrant exercise | | 3 | | | — | | | 27 | |
| Debt issuance and other financing costs | | (11) | | | — | | | (17) | |
| Cash paid to repurchase and retire common stock | | — | | | (355) | | | (1,073) | |
| Cash paid to purchase debt | | (767) | | | — | | | — | |
| Cash paid for common stock dividends | | (388) | | | (487) | | | (1,212) | |
| Other | | (3) | | | — | | | — | |
| Net cash used in financing activities | | (419) | | | (1,892) | | | (1,446) | |
| Net increase (decrease) in cash, cash equivalents and restricted cash | | (758) | | | 961 | | | (722) | |
| Cash, cash equivalents and restricted cash, beginning of period | | 1,153 | | | 192 | | | 914 | |
| Cash, cash equivalents and restricted cash, end of period | | $ | 395 | | | $ | 1,153 | | | $ | 192 | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| Cash and cash equivalents | | $ | 317 | | | $ | 1,079 | | | $ | 130 | |
| Restricted cash | | 78 | | | 74 | | | 62 | |
| Total cash, cash equivalents and restricted cash | | $ | 395 | | | $ | 1,153 | | | $ | 192 | |
| | | | | | |
| |
| | | | | | |
| | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
77
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Common Stock | | Additional Paid-in Capital | | Retained Earnings | | | | Total Stockholders’ Equity |
| ($ in millions) | Shares | | Amount |
| Balance as of December 31, 2021 | | 117,917,349 | | | $ | 1 | | | $ | 4,845 | | | $ | 825 | | | | | $ | 5,671 | |
| Issuance of common stock for Marcellus Acquisition | | 9,442,185 | | | — | | | 764 | | | — | | | | | 764 | |
| Share-based compensation | | 174,740 | | | — | | | 21 | | | — | | | | | 21 | |
| Issuance of common stock for warrant exchange offer | | 16,305,984 | | | — | | | 67 | | | — | | | | | 67 | |
| Issuance of common stock for warrant exercise | | 2,102,244 | | | — | | | 27 | | | — | | | | | 27 | |
| Issuance of reserved common stock and warrants | | 439,370 | | | — | | | — | | | — | | | | | — | |
| Repurchase and retirement of common stock | | (11,666,778) | | | — | | | — | | | (1,073) | | | | | (1,073) | |
| Net income | | — | | | — | | | — | | | 4,936 | | | | | 4,936 | |
| Dividends on common stock | | — | | | — | | | — | | | (1,222) | | | | | (1,222) | |
| Deemed dividend on warrants | | — | | | — | | | — | | | (67) | | | | | (67) | |
| Balance as of December 31, 2022 | | 134,715,094 | | | $ | 1 | | | $ | 5,724 | | | $ | 3,399 | | | | | $ | 9,124 | |
| Share-based compensation | | 214,684 | | | — | | | 31 | | | — | | | | | 31 | |
| Issuance of common stock for warrant exercise | | 221,952 | | | — | | | — | | | — | | | | | — | |
| Issuance of reserved common stock and warrants | | 12,089 | | | — | | | — | | | — | | | | | — | |
| Repurchase and retirement of common stock | | (4,373,883) | | | — | | | (1) | | | (357) | | | | | (358) | |
| Net income | | — | | | — | | | — | | | 2,419 | | | | | 2,419 | |
| Dividends on common stock | | — | | | — | | | — | | | (487) | | | | | (487) | |
| Balance as of December 31, 2023 | | 130,789,936 | | | $ | 1 | | | $ | 5,754 | | | $ | 4,974 | | | | | $ | 10,729 | |
| Issuance of common stock for Southwestern Merger | | 95,700,325 | | | 1 | | | 7,888 | | | — | | | | | 7,889 | |
| Share-based compensation | | 727,799 | | | — | | | 42 | | | — | | | | | 42 | |
| Issuance of common stock for warrant exercise | | 4,083,103 | | | — | | | 3 | | | — | | | | | 3 | |
| Issuance of reserved common stock and warrants | | 468,723 | | | — | | | — | | | — | | | | | — | |
| Net loss | | — | | | — | | | — | | | (714) | | | | | (714) | |
| Dividends on common stock | | — | | | — | | | — | | | (384) | | | | | (384) | |
| Balance as of December 31, 2024 | | 231,769,886 | | | $ | 2 | | | $ | 13,687 | | | $ | 3,876 | | | | | $ | 17,565 | |
The accompanying notes are an integral part of these consolidated financial statements.
78
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | | | | |
| 1. | Basis of Presentation and Summary of Significant Accounting Policies |
Description of Company
On October 1, 2024, Chesapeake Energy Corporation (“Chesapeake”) changed its name to Expand Energy Corporation ("Expand Energy," “we,” “our,” “us” or the "Company") in connection with the Southwestern Merger, further discussed in Note 2. Following the Southwestern Merger, Expand Energy is the largest natural gas producer in the U.S., based on net daily production, and is focused on responsibly developing an abundant supply of natural gas, oil and NGL to expand energy access for all. We have operations in Louisiana, Pennsylvania, West Virginia and Ohio, with all of our operations located onshore in the United States. Basis of Presentation
The accompanying consolidated financial statements of Expand Energy were prepared in accordance with GAAP and include the accounts of our direct and indirect wholly owned subsidiaries and entities in which Expand Energy has a controlling financial interest. Intercompany accounts and balances have been eliminated. All monetary values, other than per unit and per share amounts, are stated in millions of U.S. dollars unless otherwise specified.
This Annual Report on Form 10-K (this “Form 10-K”) relates to our financial position as of December 31, 2024 and as of December 31, 2023, and our results of operations for the year ended December 31, 2024, the year ended December 31, 2023 and the year ended December 31, 2022. For the time periods covered by this Form 10-K, we did not have any changes or items impacting other comprehensive income.
Accounting Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the related disclosures in the financial statements. Management evaluates its estimates and related assumptions regularly, including those related to the impairment of natural gas and oil properties, natural gas and oil reserves, derivatives, income taxes, impairment of other property and equipment, environmental remediation costs, asset retirement obligations, litigation and regulatory proceedings and fair values. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ significantly from these estimates.
Consolidation
We consolidate entities in which we have a controlling financial interest and variable interest entities in which we are the primary beneficiary. We consolidate subsidiaries in which we hold, directly or indirectly, more than 50% of the voting rights. We use the equity method of accounting to record our net interests where we have the ability to exercise significant influence through our investment but lack a controlling financial interest. Under the equity method, our share of net income (loss) is included in our consolidated statements of operations according to our equity ownership or according to the terms of the applicable governing instrument. See Note 15 for further discussion of our investments. Undivided interests in natural gas and oil properties are consolidated on a proportionate basis. Segments
Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker (“CODM”), who is our Chief Executive Officer, for the purpose of allocating an enterprise’s resources and assessing its operating performance. We have concluded that we have one reportable segment, due to the similar nature of the exploration and production business across Expand Energy and its consolidated subsidiaries and the fact that our marketing activities are ancillary to our operations. See Note 18 for additional information. Cash and Cash Equivalents
For purposes of the consolidated financial statements, we consider investments in all highly liquid instruments with original maturities of three months or less at the date of purchase to be cash equivalents.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Restricted Cash
As of December 31, 2024, we had restricted cash of $78 million. Our restricted cash represents funds legally restricted for future payment of certain royalties, as well as for payment of certain convenience class unsecured claims.
Accounts Receivable
Our accounts receivable are primarily from purchasers of natural gas, oil and NGL and from exploration and production companies that own interests in properties we operate. This industry concentration could affect our overall exposure to credit risk, either positively or negatively, because our purchasers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of all our counterparties and we generally require letters of credit or parent guarantees for receivables from parties deemed to have sub-standard credit, unless the credit risk can otherwise be mitigated. We utilize an allowance method in accounting for bad debt based on historical trends in addition to specifically identifying receivables that we believe may be uncollectible. See Note 8 for additional information regarding our accounts receivable. Natural Gas and Oil Properties
We follow the successful efforts method of accounting for our natural gas and oil properties. Under this method, exploration costs such as exploratory geological and geophysical costs, expiration of unproved leasehold, delay rentals and exploration overhead are expensed as incurred. All costs related to production, general corporate overhead and similar activities are also expensed as incurred. All property acquisition costs and development costs are capitalized when incurred.
Exploratory drilling costs are initially capitalized, or suspended, pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized and are classified as proved properties. Costs of unsuccessful wells are charged to exploration expense. For exploratory wells that find reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended exploratory drilling costs if there have been sufficient reserves found to justify completion as a producing well and sufficient progress is being made in assessing the reserves and the economic and operational viability of the project. If we determine that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year. We review the status of all suspended exploratory drilling costs quarterly. Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of natural gas and oil are capitalized.
Costs of drilling and equipping successful wells, costs to construct or acquire facilities, and associated asset retirement costs are depreciated using the unit-of-production (“UOP”) method based on total estimated proved developed gas and oil reserves. Costs of acquiring proved properties, including leasehold acquisition costs transferred from unproved properties, are depleted using the UOP method based on total estimated proved developed and undeveloped reserves.
Proceeds from the sales of individual natural gas and oil properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depreciation, depletion and amortization, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recognized until an entire amortization base is sold. However, a gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base.
When circumstances indicate that the carrying value of proved natural gas and oil properties may not be recoverable, we compare unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on our estimate of future natural gas and crude oil prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized costs, the capitalized costs are reduced to fair value. Fair value is generally estimated using the income approach described in the ASC 820, Fair Value Measurements. If applicable, we utilize prices and other relevant information generated by market transactions involving assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value measurements are typically based on judgmental
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
assessments of commodity prices, pricing adjustments for differentials, operating costs, capital investment plans, future production volumes, and estimated proved reserves, considering all available information at the date of review. These assumptions are applied to develop future cash flow projections that are then discounted to estimated fair value, using a market-based weighted average cost of capital. We have classified these fair value measurements as Level 3 in the fair value hierarchy.
Other Property and Equipment
Other property and equipment consists primarily of buildings and improvements, computers and office equipment, gathering and water systems, land and other assets that support our operations. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. Other property and equipment costs, excluding land, are depreciated on a straight-line basis and recorded within depreciation, depletion and amortization in the consolidated statement of operations.
Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including any disposal value, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets and discounted cash flow. See Note 14 for further discussion of other property and equipment. Assets Held for Sale
We may market certain non-core natural gas and oil assets or other properties for sale. At the end of each reporting period, we evaluate if these assets should be classified as held for sale. The held for sale criteria includes the following: management commits to a plan to sell, the asset is available for immediate sale, an active program to locate a buyer exists, the sale of the asset is probable and expected to be completed within a year, the asset is actively being marketed for sale and that it is unlikely that significant changes to the plan will be made. If each of the criteria are met, then the assets and associated liabilities are classified as held for sale. Additionally, once assets are classified as held for sale, we cease depreciation on those related assets.
Capitalized Interest
Interest from external borrowings is capitalized on significant investments in major development projects until the asset is ready for service using the weighted average borrowing rate of outstanding borrowings. Capitalized interest is determined by multiplying our weighted average borrowing cost on debt by the average amount of qualifying costs incurred. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying asset.
Accounts Payable
Included in accounts payable as of December 31, 2024 are liabilities of approximately $64 million, representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts.
Debt Issuance Costs
Costs associated with the arrangement of our credit facility are included in other long-term assets and are amortized over the life of the facility using the straight-line method. As of December 31, 2024, these costs were $17 million. Costs associated with the issuance of the senior notes are included in long-term debt and the remaining unamortized issuance costs are amortized over the life of the senior notes using the straight-line method. Unamortized issuance costs associated with our senior notes as of December 31, 2024 totaled $10 million.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Litigation Contingencies
We are subject to litigation and regulatory proceedings, claims and liabilities that arise in the ordinary course of business. We accrue losses associated with litigation and regulatory claims when such losses are probable and reasonably estimable. If we determine that a loss is probable and cannot estimate a specific amount for that loss but can estimate a range of loss, our best estimate within the range is accrued. Estimates are adjusted as additional information becomes available or circumstances change. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or third-party recoveries. Legal defense costs associated with loss contingencies are expensed in the period incurred. See Note 5 for further discussion of litigation contingencies. Environmental Remediation Costs
We record environmental reserves for estimated remediation costs related to existing conditions from past operations when the responsibility to remediate is probable and the costs can be reasonably estimated. Expenditures that create future benefits or contribute to future revenue generation are capitalized. See Note 5 for discussion of environmental contingencies. Asset Retirement Obligations
We recognize liabilities for obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which a natural gas or oil well is acquired or drilled. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is removed. The related asset retirement cost is capitalized as part of the carrying amount of our natural gas and oil properties. See Note 16 for further discussion of asset retirement obligations. Revenue Recognition
Revenue from the sale of natural gas, oil and NGL is recognized upon the transfer of control of the products, which is typically when the products are delivered to customers. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration we expect to receive in exchange for those products. We follow the sales method of accounting for our natural gas revenue whereby we recognize sales revenue on all natural gas sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property.
Revenue from contracts with customers includes the sale of our natural gas, oil and NGL production (recorded as natural gas, oil and NGL revenues in the consolidated statements of operations) as well as the sale of certain of our joint interest holders’ production which we purchase under joint operating arrangements (recorded in marketing revenues in the consolidated statements of operations). In connection with the marketing of these products, we obtain control of the natural gas, oil and NGL we purchase from other interest owners at defined delivery points and deliver the product to third parties, at which time revenues are recorded. See Note 8 for a presentation of the disaggregation of revenue. Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30 to 60 days. There are no significant judgments that significantly affect the amount or timing of revenue from contracts with customers.
We also generate revenue from other sources, including from a variety of derivative and hedging activities to reduce our exposure to fluctuations in future commodity prices and to protect our expected operating cash flow against significant market movements or volatility, as well as a variety of natural gas, oil and NGL purchase and sale contracts with third parties for various commercial purposes, including credit risk mitigation and satisfaction of our pipeline delivery commitments (recorded within marketing revenues in the consolidated statements of operations). In circumstances where we act as an agent rather than a principal, our results of operations related to natural gas, oil and NGL marketing activities are presented on a net basis.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Fair Value Measurements
Certain financial instruments are reported on a recurring basis at fair value on our consolidated balance sheets. We also use fair value measurements on a nonrecurring basis when a qualitative assessment of our assets indicates a potential impairment. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (i.e., an exit price). To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability and have the lowest priority.
The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).
The carrying values of financial instruments comprising cash and cash equivalents, accounts payable and accounts receivable approximate fair values due to the short-term maturities of these instruments. See Notes 4 and 13 for further discussion of fair value measurements. Derivatives
Derivative instruments are recorded at fair value, and changes in fair value are recognized currently in earnings unless specific hedge accounting criteria are followed. As of December 31, 2024, none of our open derivative instruments were designated as cash flow hedges.
Derivative instruments reflected as current in the consolidated balance sheets represent the estimated fair value of derivatives scheduled to settle over the next 12 months based on market prices/rates as of the respective balance sheet dates. Cash settlements of our derivative instruments are generally classified as operating cash flows unless the derivatives are deemed to contain, for accounting purposes, a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying consolidated statements of cash flows. All of our commodity derivative instruments are subject to master netting arrangements by contract type which provide for the offsetting of asset and liability positions within each contract type, as well as related cash collateral if applicable, by counterparty. Therefore, we net the value of our derivative instruments by contract type with the same counterparty in the accompanying consolidated balance sheets.
We have established the fair value of our derivative instruments using established index prices, volatility curves and discount factors. These estimates are compared to our counterparty values for reasonableness. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. Derivative transactions are subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. See Note 13 for further discussion of our derivative instruments.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Income Taxes
We are subject to current income taxes assessed by the federal and various state jurisdictions in the U.S. and account for current income taxes based on amounts paid or estimated to be payable net of amounts refunded or estimated to be refunded. Additionally, we account for deferred income taxes using the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate expected to be in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. Deferred income taxes are provided to recognize the income tax effect of reporting certain transactions in different years for income tax and financial reporting purposes. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized.
We are required to make judgments, including estimating reserves for potential adverse outcomes regarding tax positions that we have taken. We account for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties. We recognize accrued interest related to uncertain tax positions in interest expense and accrued penalties related to such positions in general and administrative expense in the consolidated statements of operations. See Note 9 for further discussion of income taxes. Share-Based Compensation
Our share-based compensation program consists of restricted stock units and performance share units granted to employees and restricted stock units granted to non-employee directors under our Long Term Incentive Plan. We recognize the cost of services received in exchange for restricted stock units based on the fair value of the equity instruments as of the grant date. This value is amortized over the vesting period, which is generally three years from the grant date. Forfeitures on our share-based compensation awards are recognized as they occur. Because performance share units are settled in shares, they are classified as equity and are measured at fair value as of the grant date.
To the extent compensation expense relates to employees directly involved in the acquisition of natural gas and oil leasehold and development activities, these amounts are capitalized to natural gas and oil properties. Amounts not capitalized to natural gas and oil properties are generally recognized as general and administrative expense, production expense, or exploration expense, based on the employees involved in those activities. See Note 11 for further discussion of share-based compensation. Recently Issued Accounting Standards
In November 2024, the FASB issued ASU 2024-03, Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. ASU 2024-03 expands disclosures about specific costs and expenses presented on the face of the income statement. This ASU is effective for annual reporting periods beginning after December 15, 2026 and for interim reporting periods within annual reporting periods beginning after December 15, 2027, with early adoption permitted. We are evaluating the impact this ASU will have on our disclosures.
In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. ASU 2023-09 intends to provide investors with additional information about an entity’s income taxes by requiring disclosure of items such as disaggregation of the effective tax rate reconciliation as well as information regarding income taxes paid. This ASU is effective for annual reporting periods beginning after December 15, 2024, with early adoption permitted for annual financial statements that have not yet been issued or made available for issuance. We are evaluating the impact this ASU will have on our disclosures.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segments Disclosures. Under ASU 2023-07, the scope and frequency of segment disclosures is increased to provide investors with additional detail about information utilized by an entity’s CODM, including information about significant segment expenses. This ASU is effective beginning with this annual report on Form 10-K and interim periods beginning in 2025. See Note 18 for further discussion on our segment reporting. | | | | | |
| 2. | Natural Gas and Oil Property Transactions |
Southwestern Merger
On January 10, 2024, Chesapeake and Southwestern entered into an all-stock agreement and plan of merger (the “Merger Agreement”). Southwestern was an independent energy company engaged in development, exploration and production activities, including related marketing activities, within its operating areas in the Appalachia and Haynesville shale plays. Our Board of Directors and the Board of Directors of Southwestern both approved the Merger Agreement. At separate special meetings each held on June 18, 2024, Chesapeake’s stockholders approved the issuance of Chesapeake’s common stock to the stockholders of Southwestern in connection with the Southwestern Merger, and Southwestern’s stockholders approved the Merger Agreement.
On October 1, 2024, the Southwestern Merger was completed, and we issued approximately 95.7 million shares of our common stock to Southwestern’s shareholders in connection with the Merger Agreement. Under the terms of the Merger Agreement, subject to certain exceptions, each share of Southwestern common stock was converted into the right to receive 0.0867 of a share of the Company’s common stock. Based on the closing price of our common stock, the total value of the shares of our common stock issued to Southwestern’s shareholders was approximately $7.9 billion. During 2024, we recognized approximately $312 million of costs related to the Southwestern Merger, which included $148 million related to employee expenses and the remainder of the costs relating to transaction fees, consulting and legal fees and other fees related to the transaction. These acquisition-related costs are included within other operating expense, net within our consolidated statements of operations. The Southwestern Merger was structured as a tax-free reorganization for United States federal income tax purposes.
Preliminary Southwestern Merger Purchase Price Allocation
We have accounted for the Southwestern Merger as a business combination, using the acquisition method, with Expand Energy (formerly Chesapeake) treated as the accounting acquirer. The following table represents the preliminary allocation of the total purchase price of Southwestern to the identifiable assets acquired and the liabilities assumed based on the fair values as of the acquisition date. 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 Southwestern’s assets and liabilities and final appraisals of assets acquired and liabilities assumed. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities may be revised as appropriate.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| | | | | | | | | | | |
| | | Preliminary Purchase Price Allocation |
| Consideration: | |
Cash(a) | $ | 585 | |
Fair value of Expand Energy common stock issued(b) | 7,871 | |
| Restricted stock unit and performance stock unit replacement awards | 17 | |
| Total consideration | $ | 8,473 | |
| |
| Fair Value of Assets Acquired: | |
| Cash and cash equivalents and restricted cash | $ | 126 | |
| Other current assets | 828 | |
| Proved natural gas and oil properties | 10,002 | |
| Unproved properties | 4,270 | |
| Other property and equipment | 128 | |
| Other long-term assets | 496 | |
| Amounts attributable to assets acquired | $ | 15,850 | |
| |
| Fair Value of Liabilities Assumed: | |
| Current liabilities | $ | 1,955 | |
| Long-term debt | 3,305 | |
| Deferred tax liabilities | 479 | |
| Long-term contract liabilities | 1,287 | |
| Other long-term liabilities | 351 | |
| Amounts attributable to liabilities assumed | 7,377 | |
| Total identifiable net assets | $ | 8,473 | |
____________________________________________
(a)Reflects the repayment of $585 million outstanding on Southwestern's 2022 revolving credit facility including $2 million of accrued interest and fees, as the facility was repaid and retired upon close of the Southwestern Merger.
(b)The fair value of our common stock is a Level 1 input, as our stock price is a quoted price in an active market as of the acquisition date.
Natural Gas and Oil Properties
For the Southwestern Merger, we applied the business combination guidance, under which an acquirer should recognize the identifiable assets acquired and the liabilities assumed on the acquisition date at fair value. The fair value estimate of proved and unproved natural gas and oil properties as of the acquisition date was based on estimated natural gas and oil reserves and related future net cash flows discounted using a weighted average cost of capital, including estimates of future production rates and future development costs. We utilized NYMEX strip pricing adjusted for inflation to value the reserves. We then applied various discount rates depending on the classification of reserves and other risk characteristics. Management utilized the assistance of a third-party valuation expert to estimate the value of the natural gas and oil properties acquired. Additionally, the fair value estimate of proved and unproved natural gas and oil properties was corroborated by utilizing a market approach, which considers recent comparable transactions for similar assets.
The inputs used to value natural gas and oil properties require significant judgment and estimates made by management and represent Level 3 inputs.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
As part of the Southwestern Merger, we assumed gathering, processing and transportation contracts, certain of which were deemed to be above or below current market rates. We recognized assets and liabilities for the difference in the contractual and market rates of these contracts, as of the date of the Merger. The terms of the contracts extend through 2035.
Southwestern Merger Revenues and Expenses Subsequent to Acquisition
We included in our consolidated statements of operations natural gas, oil and NGL revenues of $1,021 million, marketing revenues of $482 million, net losses on natural gas, oil and NGL derivatives of $34 million, and direct operating expenses of $1,384 million, including depreciation, depletion and amortization, and net earnings of $36 million, related to the Southwestern Merger businesses for the period from October 1, 2024 through December 31, 2024.
Marcellus Acquisition
On March 9, 2022, we completed the acquisition of Chief and associated non-operated interests held by affiliates of Tug Hill, of premium drilling locations in the Marcellus Shale in Northeast Pennsylvania (“Marcellus Acquisition”) for total consideration of approximately $2.77 billion, consisting of approximately $2 billion in cash, including working capital adjustments and approximately 9.4 million shares of our common stock, to acquire high quality producing assets and a deep inventory of premium drilling locations in the prolific Marcellus Shale in Northeast Pennsylvania. The Marcellus Acquisition was indebtedness free, effective as of January 1, 2022 and was subject to customary purchase price adjustments. We funded the cash portion of the consideration with cash on hand and $914 million of borrowings under the Company’s Exit Credit Facility. During 2022, we recognized approximately $41 million of costs related to our Marcellus Acquisition, which included integration costs, consulting fees, financial advisory fees, legal fees and change in control expense in accordance with Chief’s existing employment agreements. These acquisition-related costs are included within other operating expense, net within our consolidated statements of operations.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Marcellus Acquisition Purchase Price Allocation
We have accounted for the Marcellus Acquisition as a business combination, using the acquisition method. The following table represents the allocation of the total purchase price to the identifiable assets acquired and the liabilities assumed based on the fair values as of the acquisition date.
| | | | | |
| Purchase Price Allocation |
| Consideration: | |
| Cash | $ | 2,000 | |
Fair value of common stock issued in the merger (a) | 764 | |
| Working capital adjustments | 6 | |
| Total consideration | $ | 2,770 | |
| |
| Fair Value of Liabilities Assumed: | |
| Current liabilities | $ | 459 | |
| Other long-term liabilities | 129 | |
| Amounts attributable to liabilities assumed | $ | 588 | |
| |
| Fair Value of Assets Acquired: | |
| Cash, cash equivalents and restricted cash | $ | 39 | |
| Other current assets | 218 | |
| Proved natural gas and oil properties | 2,309 | |
| Unproved properties | 788 | |
| Other property and equipment | 1 | |
| Other long-term assets | 3 | |
| Amounts attributable to assets acquired | $ | 3,358 | |
| |
| Total identifiable net assets | $ | 2,770 | |
____________________________________________
(a)The fair value of our common stock is a Level 1 input, as our stock price is a quoted price in an active market as of the acquisition date.
Natural Gas and Oil Properties
For the Marcellus Acquisition, we applied the business combination guidance, under which an acquirer should recognize the identifiable assets acquired and the liabilities assumed on the acquisition date at fair value. The fair value estimate of proved and unproved natural gas and oil properties as of the acquisition date was based on estimated natural gas and oil reserves and related future net cash flows discounted using a weighted average cost of capital, including estimates of future production rates and future development costs. We utilized NYMEX strip pricing adjusted for inflation to value the reserves. We then applied various discount rates depending on the classification of reserves and other risk characteristics. Management utilized the assistance of a third-party valuation expert to estimate the value of the natural gas and oil properties acquired. Additionally, the fair value estimate of proved and unproved natural gas and oil properties was corroborated by utilizing a market approach, which considers recent comparable transactions for similar assets.
The inputs used to value natural gas and oil properties require significant judgment and estimates made by management and represent Level 3 inputs.
Marcellus Acquisition Revenues and Expenses Subsequent to Acquisition
We included in our consolidated statements of operations natural gas, oil and NGL revenues of $1,331 million, marketing revenues of $20 million, net losses on natural gas, oil and NGL derivatives of $379 million, and direct operating expenses of $483 million, including depreciation, depletion and amortization, and net earnings of
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
$381 million, related to the Marcellus Acquisition businesses for the period from March 10, 2022 (the date immediately following the completion of the Marcellus Acquisition) through December 31, 2022.
Combined Pro Forma Financial Information
The following unaudited pro forma financial information is based on our historical consolidated financial statements adjusted to reflect as if the Southwestern Merger and the divestiture of our Eagle Ford assets had each occurred on January 1, 2023. The information below reflects pro forma adjustments based on available information and certain assumptions that we believe are reasonable, including the estimated tax impact of the pro forma adjustments.
| | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2024 | | 2023 |
| Revenues | | $ | 8,193 | | | $ | 14,247 | |
| Net income (loss) available to common stockholders | | $ | (607) | | | $ | 3,852 | |
| Earnings (loss) per common share: | | | | |
| Basic | | $ | (2.65) | | | $ | 16.86 | |
| Diluted | | $ | (2.65) | | | $ | 16.14 | |
Eagle Ford Divestitures
In January 2023, we entered into an agreement to sell a portion of our Eagle Ford assets to WildFire Energy I LLC for approximately $1.425 billion, subject to customary post-closing adjustments. Approximately $225 million of the purchase price was recorded as deferred consideration and treated as a non-interest-bearing note to be paid in installments of $60 million per year for the first three years following the transaction close date, with $45 million to be paid in the fourth year following the transaction close date. During 2024, we received the first installment payment related to this transaction. The deferred consideration is recorded at fair value with an imputed rate of interest as a Level 2 input, and approximately $59 million and $58 million of the deferred consideration is reflected within other current assets and approximately $89 million and $135 million is reflected within other long-term assets on the consolidated balance sheets as of December 31, 2024 and December 31, 2023, respectively. The divestiture, which closed on March 20, 2023 (with an effective date of October 1, 2022), resulted in a gain of approximately $337 million, inclusive of post-closing adjustments, based on the difference between the carrying value of the assets and consideration received.
In February 2023, we entered into an agreement to sell a portion of our remaining Eagle Ford assets to INEOS Upstream Holdings Limited (“INEOS Energy”) for approximately $1.4 billion, subject to customary post-closing adjustments. Approximately $225 million of the purchase price was recorded as deferred consideration and treated as a non-interest-bearing note to be paid in installments of approximately $56 million per year for four years following the transaction close date. During 2024, we received the first installment payment related to this transaction. The deferred consideration is recorded at fair value with an imputed rate of interest as a Level 2 input, and approximately $55 million and $55 million of the deferred consideration is reflected within other current assets and approximately $99 million and $144 million is reflected within other long-term assets on the consolidated balance sheets as of December 31, 2024 and December 31, 2023, respectively. The divestiture, which closed on April 28, 2023 (with an effective date of October 1, 2022), resulted in a gain of approximately $470 million, based on the difference between the carrying value of the assets and consideration received. Included within the liabilities assumed by INEOS Energy was approximately $53 million of asset retirement obligations.
In August 2023, we entered into an agreement to sell the final portion of our remaining Eagle Ford assets to SilverBow Resources, Inc. (“SilverBow”) for approximately $700 million, subject to customary post-closing adjustments. Approximately $50 million of the purchase price was recorded as deferred consideration and treated as a non-interest-bearing note to be paid one year from the closing date. The deferred consideration is recorded at fair value with an imputed rate of interest as a Level 2 input, and approximately $46 million of the deferred consideration is reflected within other current assets on the consolidated balance sheets as of December 31, 2023. During 2024, we received the deferred consideration. Additionally, SilverBow agreed to pay us an additional contingent payment of $25 million should WTI NYMEX prices average between $75 and $80 per barrel or $50 million should WTI NYMEX prices average above $80 per barrel during the year following the close of the
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
transaction. On July 30, 2024, Crescent Energy Company (“Crescent”) acquired SilverBow. The fair value of the contingent consideration as of December 31, 2023 of $12 million is reflected within short-term derivative assets within our consolidated balance sheets. See Note 13 for additional information. During 2024, we received the contingent payment of $25 million from Crescent based upon the average NYMEX prices during the year following the close of the transaction. The divestiture, which closed on November 30, 2023 (with an effective date of February 1, 2023), resulted in a gain of approximately $140 million, based on the difference between the carrying value of the assets and consideration received. Included within the liabilities assumed by SilverBow was approximately $11 million of asset retirement obligations. During the years ended December 31, 2024 and 2023, we amortized approximately $31 million and $24 million related to the deferred consideration from the Eagle Ford divestiture transactions described above. The deferred consideration amortization is recorded within other income, net, in our consolidated statements of operations.
Powder River Divestiture
In January 2022, we signed an agreement to sell our Powder River Basin assets in Wyoming to Continental Resources, Inc. for approximately $450 million, subject to customary post-closing adjustments. The divestiture, which closed on March 25, 2022, resulted in the recognition of a gain of approximately $293 million, which included $13 million of post-close adjustments, based on the difference between the carrying value of the assets and the cash received.
Basic earnings (loss) per common share is computed by dividing the net income (loss) available to common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted earnings (loss) per common share is calculated in the same manner but includes the impact of potentially dilutive securities utilizing the treasury stock method. Potentially dilutive securities consists of issuable shares related to warrants, unvested restricted stock units (“RSUs”), and unvested performance share units (“PSUs”).
The reconciliations between basic and diluted earnings (loss) per share are as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2024 | | 2023 | | 2022 |
| Numerator | | | | | | |
| Net income (loss) available to common stockholders, basic and diluted | | $ | (714) | | | $ | 2,419 | | | $ | 4,869 | |
| | | | | | |
| Denominator (in thousands) | | | | | | |
| Weighted average common shares outstanding, basic | | 156,989 | | | 132,840 | | | 125,785 | |
| Effect of potentially dilutive securities | | | | | | |
| Warrants | | — | | | 9,750 | | | 19,734 | |
| Restricted stock units | | — | | | 338 | | | 395 | |
| Performance share units | | — | | | 48 | | | 47 | |
| Weighted average common shares outstanding, diluted | | 156,989 | | | 142,976 | | | 145,961 | |
| | | | | | |
| Earnings per common share: | | | | | | |
| Basic | | $ | (4.55) | | | $ | 18.21 | | | $ | 38.71 | |
| Diluted | | $ | (4.55) | | | $ | 16.92 | | | $ | 33.36 | |
During the years ended December 31, 2024, 2023 and 2022, the diluted earnings per share calculation excludes the effect of 308,646, 777,369 and 789,458 reserved shares of common stock and 582,109, 1,466,502 and 1,489,337 reserved Class C Warrants related to the settlement of General Unsecured Claims associated with the Chapter 11 Cases, as all necessary conditions had not been met for such shares to be considered dilutive shares during the years ended December 31, 2024, 2023 and 2022, respectively. Additionally, the diluted loss per
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
share calculation during the year ended December 31, 2024 excludes the antidilutive effect of 9,058,361 Warrants, 315,318 RSUs and 86,421 PSUs.
Our long-term debt consisted of the following as of December 31, 2024 and 2023:
| | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2024 | | December 31, 2023 |
| Carrying Amount | | Fair Value(a) | | Carrying Amount | | Fair Value(a) |
| Credit Facility | $ | — | | | $ | — | | | $ | — | | | $ | — | |
4.95% senior notes due 2025(b) | 389 | | | 389 | | | — | | | — | |
| 5.50% senior notes due 2026 | 47 | | | 47 | | | 500 | | | 496 | |
5.375% senior notes due 2029(b) | 700 | | | 684 | | | — | | | — | |
| 5.875% senior notes due 2029 | 500 | | | 494 | | | 500 | | | 489 | |
| 6.75% senior notes due 2029 | 950 | | | 959 | | | 950 | | | 958 | |
5.375% senior notes due 2030(b) | 1,200 | | | 1,174 | | | — | | | — | |
4.75% senior notes due 2032(b) | 1,150 | | | 1,067 | | | — | | | — | |
5.70% senior notes due 2035(c) | 750 | | | 734 | | | — | | | — | |
| Premiums on senior notes, net | 4 | | | — | | | 83 | | | — | |
| Debt issuance costs | (10) | | | — | | | (5) | | | — | |
| Total debt, net | 5,680 | | | 5,548 | | | 2,028 | | | 1,943 | |
| Less current maturities of long-term debt, net | (389) | | | (389) | | | — | | | — | |
| Total long-term debt, net | $ | 5,291 | | | $ | 5,159 | | | $ | 2,028 | | | $ | 1,943 | |
____________________________________________
(a)The carrying value of borrowings under our Credit Facility approximates fair value as the interest rates are based on prevailing market rates; therefore, they are a Level 1 fair value measurement. For all other debt, a market approach, based upon quotes from major financial institutions, which are Level 2 inputs, is used to measure the fair value.
(b)On October 1, 2024, we assumed the debt of Southwestern in connection with the Southwestern Merger, which primarily consisted of these senior notes. See Note 2 for additional discussion on the Southwestern Merger and further discussion of these senior notes below. (c)On December 2, 2024, we issued $750 million of 5.70% senior notes. See further discussion below.
The table below presents debt maturities as of December 31, 2024, excluding debt issuance costs, discounts and premiums:
| | | | | | | | |
| | Total |
| 2025 | | $ | 389 | |
| 2026 | | 47 | |
| 2027 | | — | |
| 2028 | | — | |
| 2029 | | 2,150 | |
| Thereafter | | 3,100 | |
| Total debt | | $ | 5,686 | |
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Credit Facility. In December 2022, we entered into a senior secured reserve-based credit agreement, as amended pursuant to the Amendment No. 1 and Borrowing Base Agreement, dated April 29, 2024 (the “Initial Credit Agreement Amendment”) and as automatically amended on October 28, 2024 by the Investment Grade Credit Agreement Amendment (as defined below), with the lenders and issuing banks party thereto from time to time (the “Lenders”), and JPMorgan Chase Bank, N.A., as administrative agent and collateral agent (in such capacity, the “Administrative Agent”) (such credit agreement as amended by the Initial Credit Agreement Amendment, the “Pre-IG Credit Agreement”, and as further amended by the Investment Grade Credit Agreement Amendment, the “Credit Agreement”), providing for a revolving credit facility (such facility as amended pursuant to the Initial Credit Agreement Amendment, the “Pre-IG Credit Facility”, and as further amended pursuant to the Investment Grade Credit Agreement Amendment, the “Credit Facility”) maturing in December 2027. The Initial Credit Agreement Amendment, among other things, increased the aggregate commitments under the Pre-IG Credit Facility from $2.0 billion to $2.5 billion and increased the sublimit available for the issuance of letters of credit from $200 million to $500 million. The Credit Facility continues to provide for a $50 million sublimit available for swingline loans. As of December 31, 2024, we had approximately $2.5 billion available for borrowings under the Credit Facility.
The obligations under the Pre-IG Credit Facility were guaranteed by certain of Expand Energy’s subsidiaries (the “Guarantors”), and the Pre-IG Credit Facility was secured by substantially all of the assets owned by the Company and the Guarantors (subject to customary exceptions), including mortgages on not less than 85% of the total PV-9 of the borrowing base properties evaluated in the most recent reserve report (where PV-9 is the net present value, discounted at 9% per annum, of the estimated future net revenues). Since the effectiveness of the Investment Grade Credit Agreement Amendment, the Credit Facility is no longer guaranteed or secured, or subject to a borrowing base.
The Pre-IG Credit Agreement contained restrictive covenants, subject to customary exceptions for reserve-based credit facilities, that limited Expand Energy and its subsidiaries’ ability to, among other things: (i) incur additional indebtedness, (ii) make investments, (iii) enter into mergers; (iv) make or declare dividends; (v) repurchase or redeem certain indebtedness; (vi) enter into certain hedges; (vii) incur liens; (viii) sell assets; and (ix) engage in certain transactions with affiliates. Since the effectiveness of the Investment Grade Credit Agreement Amendment on October 28, 2024, the Credit Agreement contains restrictive covenants that, subject to exceptions customary to investment grade credit facilities, limit Expand Energy and its subsidiaries’ ability to, among other things: (i) incur priority indebtedness, (ii) enter into mergers; (iii) make or declare dividends; (iv) incur liens; (v) sell all or substantially all of their assets; and (vi) engage in certain transactions with affiliates. The Pre-IG Credit Agreement required Expand Energy to maintain compliance with the following financial ratios: (A) a current ratio, which was the ratio of Expand Energy’s and its restricted subsidiaries’ consolidated current assets (including unused commitments under the Pre-IG Credit Facility but excluding certain non-cash assets) to their consolidated current liabilities (excluding the current portion of long-term debt and certain non-cash liabilities), of not less than 1.00 to 1.00; (B) a net leverage ratio, which was the ratio of total indebtedness (less unrestricted cash up to a specified threshold) to Consolidated EBITDAX (as defined in the Pre-IG Credit Agreement) for the prior four fiscal quarters, of not greater than 3.50 to 1.00 and (C) a PV-9 coverage ratio of the net present value, discounted at 9% per annum, of the estimated future net revenues expected in the proved reserves to Expand Energy’s and its restricted subsidiaries’ total indebtedness of not less than 1.50 to 1.00. The Investment Grade Credit Agreement Amendment, among other things, (i) removed the current ratio, net leverage ratio and PV-9 coverage ratio previously contained in the Pre-IG Credit Agreement and (ii) provides for our compliance with an indebtedness to capitalization ratio, which is the ratio of the Company’s total indebtedness to the sum of total indebtedness plus stockholders’ equity (the “Debt to Capitalization Ratio”), not to exceed 65%. As of December 31, 2024, we were in compliance with the Debt to Capitalization Ratio.
Borrowings under the Credit Agreement may be alternate base rate loans or term SOFR loans, at our election. Interest is payable quarterly for alternate base rate loans and at the end of the applicable interest period for term SOFR loans. Term SOFR loans bear interest at term SOFR plus an applicable rate ranging from 125 to 187.5 basis points per annum, depending on the Company’s unsecured debt ratings (which rate under the Pre-IG Credit Agreement previously ranged from 175 to 275 basis points per annum, depending on the percentage of the commitments utilized), plus an additional 10 basis points per annum credit spread adjustment. Alternate base rate loans bear interest at a rate per annum equal to the greatest of: (i) the prime rate; (ii) the federal funds effective rate plus 50 basis points; and (iii) the adjusted term SOFR rate for a one-month interest period plus 100 basis points, plus an applicable margin ranging from 25 to 87.5 basis points per annum, depending on the Company’s unsecured debt ratings (which applicable margin under the Pre-IG Credit Agreement previously ranged from 75 to 175 basis
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
points per annum, depending on the percentage of the commitments utilized). Expand Energy also pays a commitment fee on unused commitment amounts under the Credit Facility ranging from 15 to 27.5 basis points per annum, depending on the Company’s unsecured debt ratings (which commitment fee rate under the Pre-IG Credit Agreement previously ranged from 37.5 to 50 basis points per annum, depending on the percentage of the commitments utilized).
The Credit Facility is subject to customary events of default, remedies, and cure rights for investment grade credit facilities of this nature.
Investment Grade Rating.
On October 1, 2024, we received an investment grade rating from S&P Global Ratings (“S&P”). S&P assigned an issuer-level rating of ‘BBB-’ on our unsecured debt and raised our issuer credit rating to ‘BBB-’, with a stable outlook. Additionally, on October 2, 2024, we received an investment grade rating from Fitch Ratings (“Fitch”). Fitch affirmed our revolver credit rating at ‘BBB-’ and upgraded the rating on our senior notes to ‘BBB-’, with a stable outlook. As a result of these investment grade ratings and the satisfaction of certain other conditions, (i) the Pre-IG Credit Agreement was automatically amended in its entirety as set forth in an exhibit to the Pre-IG Credit Agreement (such automatic amendment, the “Investment Grade Credit Agreement Amendment”, and the Pre-IG Credit Agreement as amended by such amendment, the “Credit Agreement”), (ii) all liens and guarantees previously provided by the Company and its subsidiaries in connection with the Pre-IG Credit Agreement were released and (iii) all guarantees previously provided in connection with the Company’s senior notes were released. Such Investment Grade Credit Agreement Amendment, among other things, removed the application of the borrowing base provided for in the Pre-IG Credit Agreement and modified the pricing and covenants as described above.
Assumption of Southwestern’s Senior Notes and Southwestern Credit Facility Extinguishment.
On October 1, 2024, the Southwestern Merger was completed, and we became the successor issuer in respect to Southwestern’s (i) $389 million aggregate principal amount of 4.950% Senior Notes due 2025 (the “SWN 2025 Notes”), (ii) $304 million aggregate principal amount of 8.375% Senior Notes due 2028 (the “SWN 2028 Notes”), (iii) $700 million aggregate principal amount of 5.375% Senior Notes due 2029 (the “SWN 2029 Notes”), (iv) $1,200 million aggregate principal amount of 5.375% Senior Notes due 2030 (the “SWN 2030 Notes”) and (v) $1,150 million aggregate principal amount of 4.750% Senior Notes due 2032 (the “SWN 2032 Notes” and together with the SWN 2025 Notes, the SWN 2028 Notes, the SWN 2029 Notes and the SWN 2030 Notes, the “SWN Notes”). We assumed the obligations under (i) the SWN 2025 Notes pursuant to Supplemental Indenture No. 9 (“SWN 2025 Notes Supplemental Indenture No. 9”) to a base indenture dated January 23, 2015, by and among Southwestern and U.S. Bank National Association, as Trustee, (ii) the SWN 2028 Notes pursuant to Supplemental Indenture No. 9 (“SWN 2028 Notes Supplemental Indenture No. 9”) to a base indenture dated September 25, 2017, by and among Southwestern and U.S. Bank National Association, as Trustee, (iii) the SWN 2029 Notes pursuant to Supplemental Indenture No. 6 (“Supplemental Indenture No. 6”) to a base indenture dated August 30, 2021 (the “2021 Base Indenture”) by and among Southwestern and Regions Bank, as Trustee, (iv) the 2030 Notes pursuant to Supplemental Indenture No. 7 (“Supplemental Indenture No. 7”) to the 2021 Base Indenture and (v) the 2032 Notes pursuant to Supplemental Indenture No. 8 (“Supplemental Indenture No. 8” and, together with SWN 2025 Notes Supplemental Indenture No. 9, SWN 2028 Notes Supplemental Indenture No. 9, Supplemental Indenture No. 6 and Supplemental Indenture No. 7, the “SWN Supplemental Indentures”) to the 2021 Base Indenture. In addition, pursuant to each SWN Supplemental Indenture, existing subsidiaries of the Company that guarantee our notes provided guarantees of the SWN Notes. As a result of the investment grade ratings we received on October 1 and October 2, 2024, and the satisfaction of certain other conditions, all guarantees previously provided in connection with the Company’s outstanding senior notes, including the SWN Notes, were released.
The SWN 2025 Notes matured on January 23, 2025 and bore interest at a rate of 4.950% per annum, with interest that was payable on January 23 and July 23 of each year. The SWN 2029 Notes mature on February 1, 2029 and bear interest at a rate of 5.375% per annum, with interest payable on February 1 and August 1 of each year. The SWN 2030 Notes mature on March 15, 2030 and bear interest at a rate of 5.375% per annum, with interest payable on March 15 and September 15 of each year. The SWN 2032 Notes mature on February 1, 2032 and bear interest at a rate of 4.750% per annum, with interest payable on February 1 and August 1 of each year.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
On October 1, 2024, Southwestern’s existing credit facility was terminated, with all loan amounts and other obligations outstanding thereunder repaid in full and all commitments thereunder extinguished, for approximately $585 million, which included all outstanding borrowings, accrued interest and transaction fees.
Issuance of 5.70% Senior Notes
On December 2, 2024, we completed our underwritten public offering of $750 million aggregate principal amount of our 5.70% Senior Notes due 2035 (the “2035 Notes”). The 2035 Notes were issued pursuant to the Indenture (the “Base Indenture”), dated as of December 2, 2024, between the Company and Regions Bank (the “Trustee”), as trustee, as supplemented by the First Supplemental Indenture, dated as of December 2, 2024 (the “First Supplemental Indenture” and, together with the Base Indenture, the “Indenture”), between the Company and the Trustee, setting forth specific terms applicable to the 2035 Notes.
The 2035 Notes are the Company’s senior unsecured obligations and rank equally in right to payment of the holders of the Company’s other current and future unsecured senior debt, including debt under the Company’s revolving credit facility and the Company’s existing senior notes, and senior in right of payment to any future subordinated debt that the Company may incur. The 2035 Notes are not guaranteed by any of the Company’s subsidiaries and are therefore structurally subordinated to any indebtedness incurred by any of the Company’s subsidiaries.
The 2035 Notes mature on January 15, 2035 and interest on the 2035 Notes is payable semi-annually, on January 15 and July 15 of each year to holders of record on the immediately preceding January 1 and July 1. The first interest payment date will commence on July 15, 2025 to holders of record on July 1, 2025.
Outstanding Senior Notes. On October 28, 2024, the Company satisfied the “Investment Grade Date” conditions set forth under the Credit Facility (the “Investment Grade Date Event”) and, as a result, entered into supplemental indentures pursuant to which each subsidiary guarantor party thereto was released of all of its obligations under its guarantee of the Company’s obligations under the indenture, dated as of February 5, 2021, among the Issuer, the guarantor party thereto and Deutsche Bank Trust Company Americas, as trustee, that issued the $500 million aggregate principal amount of 5.50% Senior Notes due 2026 (“the 2026 Notes”) and the $500 million aggregate principal amount of 5.875% Senior Notes due 2029 (the “2029 Notes”). Additionally, as a result of receiving such investment grade rating, pursuant to the indenture governing the 2026 Notes and the 2029 Notes, certain restrictive covenants under such indentures are no longer in effect upon the Company.
Interest on the 2026 Notes and 2029 Notes is payable semi-annually, on February 1 and August 1 of each year to holders of record on the immediately preceding January 15 and July 15.
The Company and certain of its subsidiaries previously agreed to guarantee such obligations under the indenture dated April 7, 2021 with Wilmington Trust, National Association, as Trustee (the “Vine Indenture”) under which the Company assumed the obligations under Vine’s $950 million aggregate principal amount of 6.75% Senior Notes due 2029 (the “Vine Notes”). Additionally, certain subsidiaries of Vine entered into a supplemental indenture to the Company’s existing indenture, dated February 5, 2021, with Deutsche Bank Trust Company Americas as trustee (the “CHK Indenture”), pursuant to which such subsidiaries of Vine have agreed to guarantee obligations under the CHK Indenture. On October 28, 2024, in connection with the Investment Grade Date Event, the Company entered into a supplemental indenture to the CHK Indenture pursuant to which each subsidiary guarantor party thereto was released of all its obligations under its guarantee of the Company’s obligations under the CHK Indenture.
Interest on the Vine Notes is payable semi-annually, on April 15 and October 15 of each year to holders of record on the immediately preceding April 1 and October 1.
In connection with the completion of the Southwestern Merger, on October 1, 2024, the Company entered into (i) Supplemental Indenture No. 3 to the Indenture dated February 5, 2021, by and among Chesapeake Escrow LLC, as issuer, the guarantors signatory thereto and Deutsche Bank Trust Company, as Trustee governing the 2026 Notes and 2029 Notes and (ii) Supplemental Indenture No. 5 to the Indenture dated April 7, 2021, by and among Vine Energy Holdings LLC, the guarantors signatory thereto and Wilmington Trust, National Association, as Trustee governing the Company’s existing 6.75% Senior Notes due 2029 (the “Vine Notes” and together with the 2026 Notes and the 2029 Notes, the “Existing Notes”), in each case to add as guarantors of the Existing Notes, the subsidiaries of Southwestern that guarantee SWN Notes that are described above. As discussed above, on October
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
28, 2024, each Southwestern subsidiary guarantor was released of all its obligations under its guarantee of the Company’s obligations under each of the indentures governing the Existing Notes in connection with the Investment Grade Date Event.
The Credit Facility, the SWN Notes and the Existing Notes are the Company’s senior unsecured obligations. Accordingly, they rank (i) equal in right of payment to all existing and future senior unsecured indebtedness, (ii) effectively subordinate in right of payment to all existing and future secured indebtedness, to the extent of the value of the collateral securing such indebtedness, (iii) structurally subordinate in right of payment to all existing and future indebtedness and other liabilities of any future subsidiaries that do not guarantee the Credit Facility, the SWN Notes and/or Existing Notes and any entity that is not a subsidiary that does not guarantee the Credit Facility, the SWN Notes and/or Existing Notes and (iv) senior in right of payment to all future subordinated indebtedness.
The Company had no secured debt as of December 31, 2024.
Tender Offer and Early Redemption of Senior Notes
During the fourth quarter of 2024, we announced an offer to purchase for cash, any and all of our outstanding 2026 Notes, the “Tender Offer”. Upon expiration of the Tender Offer, approximately 91%, or $453 million, of the 2026 Notes were validly tendered and not validly withdrawn. In a separate transaction during the fourth quarter of 2024, we redeemed all of the $304 million aggregate principal of the SWN 2028 Notes for approximately $312 million, which included an $8 million premium to call the notes. We utilized the proceeds from the 2035 Notes to fund the Tender Offer for the 2026 Notes and the early redemption of the SWN 2028 Notes.
Subsequent Event - Maturity and Repayment of the SWN 2025 Notes
On January 23, 2025, the $389 million aggregate principal of SWN 2025 Notes was repaid and terminated with cash on hand and borrowings on the Credit Facility.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| | | | | |
| 5. | Contingencies and Commitments |
Contingencies
Business Operations and Litigation and Regulatory Proceedings
We are involved in, and expect to continue to be involved in, various lawsuits and disputes incidental to our business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. We are also party to the consolidated Chapter 11 Cases pending for the Debtors in the Bankruptcy Court.
Our total accrued liability in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, our experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. Significant judgment is required in making these estimates. While it is not possible at this time to estimate the amount of any additional loss, or range of loss that is reasonably possible, based on the nature of the claims, management believes that current litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on our financial position, results of operations or cash flows. Many of these matters are in early stages and are all subject to inherent uncertainties. Therefore, management’s view may change in the future. If an unfavorable final outcome were to occur, there exists the possibility of our final liabilities being materially different.
The majority of Chesapeake’s pre-petition legal proceedings were settled during the Chapter 11 Cases or will be resolved in connection with the claims reconciliation process before the Bankruptcy Court, together with actions seeking to collect pre-petition indebtedness or to exercise control over the property of Chesapeake’s bankruptcy estates. Any allowed claim related to such litigation will be treated in accordance with the Plan. The Plan in the Chapter 11 Cases, which became effective on February 9, 2021, provided for the treatment of claims against Chesapeake’s bankruptcy estates, including pre-petition liabilities that had not been satisfied or addressed during the Chapter 11 Cases. Many of these proceedings were in early stages as of the Petition Date, and many of them sought damages and penalties, the amount of which is indeterminate. Any legal proceeding pending against Southwestern and assumed by us in connection with the Southwestern Merger is not subject to discharge or resolution as part of the Chapter 11 Cases.
Environmental Contingencies
The nature of the natural gas and oil business carries with it certain environmental risks for us and our subsidiaries. We have implemented various policies, programs, procedures, training and audits to reduce and mitigate such environmental risks. We conduct periodic reviews, on a company-wide basis, to assess changes in our environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. We manage our exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, we may, among other things, exclude a property from the transaction, require the seller to remediate the property to our satisfaction in an acquisition or agree to assume liability for the remediation of the property.
Other Matters
Based on management’s current assessment, we are of the opinion that no pending or threatened lawsuit or dispute relating to our business operations is likely to have a material adverse effect on our future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Commitments
Gathering, Processing and Transportation Agreements
We have contractual commitments with midstream service companies and pipeline carriers for future gathering, processing and transportation of natural gas, oil and NGL to move certain of our production to market. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Commitments related to gathering, processing and transportation agreements are not recorded as obligations in the accompanying consolidated balance sheets.
The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners, credits for third-party volumes or future costs under cost-of-service agreements, are presented below:
| | | | | | | | |
| | | December 31, 2024 |
| 2025 | | $ | 1,377 | |
| 2026 | | 1,300 | |
| 2027 | | 1,189 | |
| 2028 | | 1,134 | |
| 2029 | | 943 | |
| Thereafter | | 3,937 | |
| Total | | $ | 9,880 | |
As a result of the Southwestern Merger, during the year ended December 31, 2024, we acquired certain gathering, processing and transportation agreements from Southwestern and have reflected these agreements within the table above. In addition, we have long-term agreements for certain natural gas gathering and related services within specified acreage dedication areas in exchange for cost-of-service based fees redetermined annually, or tiered fees based on volumes delivered relative to scheduled volumes. Future gathering fees may vary with the applicable agreement.
Other Commitments
As part of our normal course of business, we enter into various agreements providing, or otherwise arranging for, financial or performance assurances to third parties on behalf of our wholly owned guarantor subsidiaries. These agreements may include future payment obligations or commitments regarding operational performance that effectively guarantee our subsidiaries’ future performance.
In connection with acquisitions and divestitures, our purchase and sale agreements generally provide indemnification to the counterparty for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party and/or other specified matters. These indemnifications generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or cannot be quantified at the time of entering into or consummating a particular transaction. For divestitures of natural gas and oil properties, our purchase and sale agreements may require the return of a portion of the proceeds we receive as a result of uncured title or environmental defects.
While executing our strategic priorities, we have incurred certain cash charges, including contract termination charges, financing extinguishment costs and charges for unused natural gas transportation and gathering capacity.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Other current liabilities as of December 31, 2024 and 2023 are detailed below:
| | | | | | | | | | | | | | |
| | December 31, 2024 | | December 31, 2023 |
| Revenues and royalties due to others | | $ | 734 | | | $ | 360 | |
| Accrued drilling and production costs | | 296 | | | 211 | |
| Contract liabilities | | 284 | | | — | |
| Accrued compensation and benefits | | 124 | | | 64 | |
| Taxes payable | | 142 | | | 84 | |
| Operating leases | | 71 | | | 84 | |
| Joint interest prepayments received | | 13 | | | 8 | |
| Accrued hedging costs | | 9 | | | 2 | |
| Other | | 113 | | | 34 | |
| Total other current liabilities | | $ | 1,786 | | | $ | 847 | |
We are a lessee under various agreements for drilling rigs, pressure pumping equipment, vehicles, office space, compressors, certain water transportation lines and other equipment under non-cancelable operating leases expiring through 2036. Certain of our lease agreements include options to renew the lease, terminate the lease early or purchase the underlying asset at the end of the lease. We determine the lease term at the lease commencement date as the non-cancelable period of the lease, including options to extend or terminate the lease when we are reasonably certain to exercise the option. The Company’s vehicles are the only leases with renewal options that we are reasonably certain to exercise. The renewals are reflected in the right of use (“ROU”) asset and lease liability balances.
On October 1, 2024, we completed the Southwestern Merger. As part of the purchase price allocation, we recognized additional operating lease liabilities of $134 million and a related ROU asset of $134 million related to drilling rigs, pressure pumping equipment, vehicles, office space, compressors, certain water transportation lines and other equipment. Regarding our drilling rigs and pressure pumping equipment, our policy is to treat both lease and non-lease components as a single lease component. See Note 2 for additional information about the Southwestern Merger. Our operating ROU assets are included in other long-term assets while operating lease liabilities are included in other current and other long-term liabilities on the consolidated balance sheet.
The following table presents our ROU assets and lease liabilities as of December 31, 2024 and 2023. As of December 31, 2024 and 2023, we did not have any finance leases.
| | | | | | | | | | | | | | |
| | Operating Leases |
| | | December 31, 2024 | | December 31, 2023 |
| ROU assets | | $ | 145 | | | $ | 99 | |
| | | | |
| Lease liabilities: | | | | |
| Current lease liabilities | | $ | 71 | | | $ | 84 | |
| Long-term lease liabilities | | 74 | | | 15 | |
| Total lease liabilities, net | | $ | 145 | | | $ | 99 | |
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Additional information for the Company’s operating leases is presented below:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | | 2024 | | 2023 | | 2022 |
| Lease cost: | | | | | | |
| | | | | | |
| Operating lease cost | | $ | 88 | | | $ | 107 | | | $ | 51 | |
| Short-term lease cost | | 62 | | | 40 | | | 74 | |
| Total lease cost | | $ | 150 | | | $ | 147 | | | $ | 125 | |
| | | | | | |
| Other information: | | | | | | |
| Operating cash outflows from operating leases | | $ | 13 | | | $ | 10 | | | $ | 15 | |
| Investing cash outflows from operating leases | | $ | 137 | | | $ | 137 | | | $ | 110 | |
| | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2024 | | December 31, 2023 |
| Weighted average remaining lease term - operating leases | | 3.03 years | | 1.24 years |
| Weighted average discount rate - operating leases | | 5.99 | % | | 7.02 | % |
Maturity analysis of operating lease liabilities is presented below:
| | | | | | | | |
| | December 31, 2024 |
| 2025 | | $ | 71 | |
| 2026 | | 37 | |
| 2027 | | 30 | |
| 2028 | | 14 | |
| 2029 | | 6 | |
| Thereafter | | 1 | |
| Total lease payments | | 159 | |
| Less imputed interest | | (14) | |
| Present value of lease liabilities | | 145 | |
| Less current maturities | | (71) | |
| Present value of lease liabilities, less current maturities | | $ | 74 | |
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following tables show revenue disaggregated by operating area and product type, for the periods presented:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2024 |
| | Natural Gas | | Oil | | NGL | | Total |
| Haynesville | | $ | 1,205 | | | $ | — | | | $ | — | | | $ | 1,205 | |
| Northeast Appalachia | | 1,242 | | | — | | | — | | | 1,242 | |
| Southwest Appalachia | | 239 | | | 69 | | | 214 | | | 522 | |
| Natural gas, oil and NGL revenue | | $ | 2,686 | | | $ | 69 | | | $ | 214 | | | $ | 2,969 | |
| | | | | | | | |
| Marketing revenue | | $ | 1,095 | | | $ | 116 | | | $ | 79 | | | $ | 1,290 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2023 |
| | Natural Gas | | Oil | | NGL | | Total |
| Haynesville | | $ | 1,300 | | | $ | — | | | $ | — | | | $ | 1,300 | |
| Northeast Appalachia | | 1,483 | | | — | | | — | | | 1,483 | |
| | | | | | | | |
| Eagle Ford | | 70 | | | 596 | | | 98 | | | 764 | |
| Natural gas, oil and NGL revenue | | $ | 2,853 | | | $ | 596 | | | $ | 98 | | | $ | 3,547 | |
| | | | | | | | |
| Marketing revenue | | $ | 989 | | | $ | 1,332 | | | $ | 179 | | | $ | 2,500 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2022 |
| | Natural Gas | | Oil | | NGL | | Total |
| Haynesville | | $ | 3,481 | | | $ | — | | | $ | — | | | $ | 3,481 | |
| Northeast Appalachia | | 4,041 | | | — | | | — | | | 4,041 | |
| | | | | | | | |
| Eagle Ford | | 261 | | | 1,798 | | | 212 | | | 2,271 | |
| Powder River Basin | | 20 | | | 66 | | | 13 | | | 99 | |
| Natural gas, oil and NGL revenue | | $ | 7,803 | | | $ | 1,864 | | | $ | 225 | | | $ | 9,892 | |
| | | | | | | | |
| Marketing revenue | | $ | 2,455 | | | $ | 1,547 | | | $ | 229 | | | $ | 4,231 | |
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Major Customers
For the year ended December 31, 2024, we had no purchaser that accounted for 10% or greater of our total revenues (before the effects of hedging). For the year ended December 31, 2023, we had sales to two purchasers that accounted for approximately 17% and 10% of total revenues (before the effects of hedging). For the year ended December 31, 2022, was had sales to two purchasers that accounted for approximately 13% and 10% of total revenues (before the effects of hedging). No other purchasers accounted for more than 10% of our total revenues during the years ended December 31, 2023 or 2022.
Accounts Receivable
Accounts receivable as of December 31, 2024 and 2023 are detailed below:
| | | | | | | | | | | | | | |
| | December 31, 2024 | | December 31, 2023 |
| Natural gas, oil and NGL sales | | $ | 1,028 | | | $ | 406 | |
| Joint interest | | 191 | | | 180 | |
| Other | | 18 | | | 8 | |
| Allowance for doubtful accounts | | (11) | | | (1) | |
| Total accounts receivable, net | | $ | 1,226 | | | $ | 593 | |
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The components of the income tax expense (benefit) for each of the periods presented below are as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2024 | | 2023 | | 2022 |
| Current | | | | | | |
| Federal | | $ | (1) | | | $ | 264 | | | $ | 37 | |
| State | | (3) | | | 6 | | | 10 | |
| Current Income Taxes | | (4) | | | 270 | | | 47 | |
| Deferred | | | | | | |
| Federal | | (178) | | | 381 | | | (1,112) | |
| State | | 55 | | | 47 | | | (220) | |
| Deferred Income Taxes | | (123) | | | 428 | | | (1,332) | |
| Total | | $ | (127) | | | $ | 698 | | | $ | (1,285) | |
The income tax expense (benefit) reported in our consolidated statement of operations is different from the federal income tax expense (benefit) computed using the federal statutory rate for the following reasons:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2024 | | 2023 | | 2022 |
| Income tax expense (benefit) at the federal statutory rate of 21% | | $ | (177) | | 21.0 | % | | $ | 655 | | 21.0 | % | | $ | 767 | | 21.0 | % |
| State income taxes (net of federal income tax benefit) | | (5) | | 0.6 | % | | 76 | | 2.5 | % | | 45 | | 1.2 | % |
| Deferred remeasurement due to state rate changes | | 47 | | (5.6) | % | | (20) | | (0.6) | % | | 30 | | 0.8 | % |
| Change in valuation allowance due to acquisitions | | 14 | | (1.7) | % | | — | | — | % | | 19 | | 0.5 | % |
| Change in valuation allowance excluding impact of acquisitions | | (18) | | 2.1 | % | | (33) | | (1.1) | % | | (2,147) | | (58.8) | % |
| Research and development tax credits | | (31) | | 3.7 | % | | (3) | | (0.1) | % | | (19) | | (0.5) | % |
| Transaction costs | | 22 | | (2.6) | % | | — | | — | % | | 2 | | 0.1 | % |
| Compensation costs related to acquired company | | 11 | | (1.2) | % | | — | | — | % | | — | | — | % |
| Other | | 10 | | (1.2) | % | | 23 | | 0.7 | % | | 18 | | 0.5 | % |
| Total | | $ | (127) | | 15.1 | % | | $ | 698 | | 22.4 | % | | $ | (1,285) | | (35.2) | % |
In 2024, the Company’s overall effective tax rate decreased compared to 2023 due to the revaluation of state deferred taxes as a result of Louisiana’s recent enactment of a tax rate decrease and as a result of permanent differences for transaction and compensation costs associated with the Southwestern Merger. The Company’s effective tax rate in 2023 increased from 2022 due to the release of the valuation allowance in 2022 which resulted in that year being a net benefit.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Deferred income taxes are provided to reflect temporary differences in the tax basis of assets and liabilities and their reported amounts in the financial statements. The tax-effected temporary differences, net operating loss (“NOL”) carryforwards and excess business interest expense carryforwards that comprise our deferred income taxes are as follows:
| | | | | | | | | | | | | | |
| | December 31, 2024 | | December 31, 2023 |
| Deferred tax liabilities: | | | | |
| Property, plant and equipment | | $ | (1,730) | | | $ | (295) | |
| Derivative instruments | | — | | | (166) | |
| Right of use lease asset | | (36) | | | (25) | |
| Other | | (3) | | | (4) | |
| Deferred tax liabilities | | (1,769) | | | (490) | |
| | | | |
| Deferred tax assets: | | | | |
| | | | |
| Net operating loss carryforwards | | 1,258 | | | 848 | |
| Carrying value of debt | | 4 | | | 25 | |
| Excess business interest expense carryforward | | 777 | | | 646 | |
| Capital loss carryforwards | | 103 | | | 78 | |
| Tax credit carryforwards | | 53 | | | 15 | |
| Contract liabilities | | 261 | | | — | |
| Asset retirement obligations | | 123 | | | 65 | |
| Investments | | — | | | 1 | |
| Future lease payments | | 36 | | | 25 | |
| Accrued liabilities | | 39 | | | 15 | |
| Derivative instruments | | 13 | | | — | |
| Other | | 24 | | | 17 | |
| Deferred tax assets | | 2,691 | | | 1,735 | |
| Valuation allowance | | (343) | | | (312) | |
| Deferred tax assets after valuation allowance | | 2,348 | | | 1,423 | |
| Net deferred tax asset | | $ | 579 | | | $ | 933 | |
| | | | |
| Reflected in the accompanying balance sheets as: | | | | |
| Deferred income tax assets | | $ | 589 | | | $ | 933 | |
| Deferred income tax liabilities | | (10) | | | — | |
| Total | | $ | 579 | | | $ | 933 | |
As of December 31, 2024 and 2023, we had deferred tax assets of $2.691 billion and $1.735 billion, respectively, upon which we had a valuation allowance of $343 million and $312 million, respectively. The net change in the valuation allowance of $31 million is primarily due to the additional valuation allowance recorded related to the acquisition of Southwestern tax attributes partially offset by the expiration of a capital loss carryforward and state net operating loss carryforwards. Of this $31 million net change in the valuation allowance, $35 million is reflected in components of stockholders’ equity which is partially offset by $4 million reflected as a component of income tax benefit in the consolidated statements of operations.
We maintain a partial valuation allowance of $343 million against a portion of our federal and state deferred tax assets such as NOLs, credit carryovers, and capital losses, which may expire before we are able to utilize them due to the application of the limitations under Section 382 and the ordering in which such attributes may be applied.
Our ability to utilize NOL carryforwards, disallowed business interest carryforwards, tax credits and possibly other tax attributes to reduce future taxable income and federal income tax is subject to various limitations under Section 382 of the Code. The utilization of such attributes may be subject to an annual limitation under Section 382 of the Code should transactions involving our equity result in a cumulative shift of more than 50% in the beneficial ownership of our stock during any three-year testing period (an “Ownership Change”).
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The Company experienced an Ownership Change in 2021 (“First Ownership Change”). The amount of the annual limitation due to the First Ownership Change is $54 million. This limitation applies to our NOL carryforwards, disallowed business interest carryforwards and general business tax credits that existed at the time of the First Ownership Change until such attributes expire or are fully utilized. As a result of the Southwestern Merger on October 1, 2024, the Company experienced another Ownership Change (“Second Ownership Change”). The base amount of the annual limitation due to the Second Ownership Change has been estimated to be $380 million. This limitation applies to our NOL carryforwards, disallowed business interest carryforwards and general business credits generated subsequent to the First Ownership Change until such attributes expire or are fully utilized. We believe that we are in a net unrealized built-in gain position at the time of the Second Ownership Change, which may result in increases to the annual limitation amount for a 5-year period. Some states impose similar limitations on tax attribute utilization upon experiencing an Ownership Change.
On October 1, 2024, we completed the Southwestern Merger. For federal income tax purposes, the transaction qualified as a tax-free merger under Section 368 of the Code and, as a result, we acquired carryover tax basis in Southwestern’s assets and liabilities. We recorded a $479 million net deferred tax liability determined through business combination accounting. Additionally, we acquired NOL and interest expense carryforwards which were previously subject to base annual Section 382 limitations of $2 million and $48 million. The acquired NOL and interest expense carryforwards that were not previously subject to a base annual Section 382 limitation are now subject to a base annual Section 382 limitation of approximately $269 million as a result of the merger. The base annual limitation is estimated to be increased over the first five years for recognized built-in gains.
The Marcellus Acquisition during 2022 was treated as a taxable asset acquisition with no tax carryovers acquired.
As of December 31, 2024, and after taking into account each of the foregoing matters, the federal NOLs are as follows:
| | | | | | | | |
| Net operating losses, by year of expiration: | | |
| 2031 | | $ | 5 | |
| 2032 | | 8 | |
| 2033 | | 2 | |
| 2034 | | 2 | |
| 2035 | | 50 | |
| 2036 | | 618 | |
| 2037 | | 832 | |
| Indefinitely lived | | 3,640 | |
| Total federal net operating losses | | $ | 5,157 | |
We had state NOL carryforwards of approximately $4.296 billion. Several states adopt the federal NOL carryforward period such that our more recent state NOLs do not expire. The state NOL carryforwards are subject to apportioned amounts of the federal Section 382 limitations.
As of December 31, 2024 and 2023, we have an income tax receivable of $32 million and $33 million included in other current assets within our consolidated balance sheets, respectively.
On August 16, 2022, the President of the United States signed into law the Inflation Reduction Act of 2022 (“IRA”) which, among other things, includes provisions for a 15% corporate alternative minimum tax on book income for companies whose average book income exceeds $1 billion for any three consecutive years preceding the tax year. We believe that we are an applicable corporation beginning in 2024 for purposes of this alternative tax. We estimate no tax due to this as a result of the book loss.
Accounting guidance for recognizing and measuring uncertain tax positions requires a more likely than not threshold condition be met on a tax position, based solely on the technical merits of being sustained, before any benefit of the tax position can be recognized in the financial statements. Guidance is also provided regarding recognition, classification and disclosure of uncertain tax positions. As of December 31, 2024 and 2023, the amount of unrecognized tax benefits related to NOL carryforwards, tax credit carryforwards, and tax liabilities associated with uncertain tax positions was $80 million and $68 million, respectively. As of December 31, 2024, $24 million is related to
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
state tax receivables not expected to be recovered, $14 million is related to a liability for tax credits taken, $9 million is related to tax credit carryforwards, and the remainder is related to NOL carryforwards. As of December 31, 2023, $24 million is related to state tax receivables not expected to be recovered, $10 million is related to a liability for tax credits taken, and the remainder is related to NOL carryforwards. If recognized, $47 million of the uncertain tax positions identified would have an effect on the effective tax rate. As of December 31, 2024, we had $1 million accrued for interest related to these uncertain tax positions. As of December 31, 2023, we had no amounts accrued for interest related to these uncertain tax positions. We recognize interest related to uncertain tax positions as a component of interest expense. Penalties, if any, related to uncertain tax positions would be recorded in other expenses.
A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2024 | | 2023 | | 2022 |
| Unrecognized tax benefits at beginning of period | | $ | 68 | | | $ | 69 | | | $ | 74 | |
| Additions based on tax positions related to the current year | | 3 | | | 3 | | | 2 | |
| Additions to tax positions of prior years | | 1 | | | 3 | | | 2 | |
| Additions to tax positions related to acquisitions | | 9 | | | — | | | — | |
| Settlements | | — | | | (5) | | | — | |
| Expiration of the applicable statute of limitations | | — | | | — | | | — | |
| Reductions to tax positions of prior years | | (1) | | | (2) | | | (9) | |
| Unrecognized tax benefits at end of period | | $ | 80 | | | $ | 68 | | | $ | 69 | |
Our federal and state income tax returns are subject to examination by federal and state tax authorities. Our tax years 2021 through 2024 remain open for all purposes of examination by the IRS as well as the Southwestern 2021 through 2023 returns, the Southwestern short period return for January 1, 2024 through October 1, 2024, and the Vine short period return for January 1, 2021 through November 1, 2021. However, certain earlier tax years remain open for adjustment to the extent of their NOL carryforwards available for future utilization.
In addition, tax years 2021 through 2024 as well as certain earlier years remain open for examination by state tax authorities. We do not anticipate that the outcome of any federal or state audit will have a significant impact on our financial position or results of operations.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Common Stock
On March 9, 2022, we completed the Marcellus Acquisition and issued 9,442,185 shares of common stock. On October 1, 2024, we issued 95,700,325 shares of our common stock to Southwestern’s shareholders in connection with the closing of the Southwestern Merger. See further discussion of both transactions in Note 2. During the years ended December 31, 2024, 2023 and 2022, 468,723, 12,089 and 439,370 reserved shares, respectively, were issued to resolve allowed General Unsecured Claims.
Dividends
In May 2021, we initiated an annual base dividend on our shares of common stock, expected to be paid quarterly. In March 2022, we adopted a variable return program that resulted in the payment of an additional variable dividend equal to the sum of Adjusted Free Cash Flow from the prior quarter less the base quarterly dividend, multiplied by 50%. The following table summarizes our dividend payments during the years ended December 31, 2024, 2023 and 2022:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Base | | Variable | | Rate Per Share | | Total |
| 2024: | | | | | | | | |
| First Quarter | | $ | 0.575 | | | $ | — | | | $ | 0.575 | | | $ | 77 | |
| Second Quarter | | $ | 0.575 | | | $ | 0.14 | | | $ | 0.715 | | | $ | 95 | |
| Third Quarter | | $ | 0.575 | | | $ | — | | | $ | 0.575 | | | $ | 78 | |
| Fourth Quarter | | $ | 0.575 | | | $ | — | | | $ | 0.575 | | | $ | 134 | |
| | | | | | | | |
| 2023: | | | | | | | | |
| First Quarter | | $ | 0.55 | | | $ | 0.74 | | | $ | 1.29 | | | $ | 175 | |
| Second Quarter | | $ | 0.55 | | | $ | 0.63 | | | $ | 1.18 | | | $ | 160 | |
| Third Quarter | | $ | 0.575 | | | $ | — | | | $ | 0.575 | | | $ | 77 | |
| Fourth Quarter | | $ | 0.575 | | | $ | — | | | $ | 0.575 | | | $ | 75 | |
| | | | | | | | |
| 2022: | | | | | | | | |
| First Quarter | | $ | 0.4375 | | | $ | 1.33 | | | $ | 1.7675 | | | $ | 210 | |
| Second Quarter | | $ | 0.50 | | | $ | 1.84 | | | $ | 2.34 | | | $ | 298 | |
| Third Quarter | | $ | 0.55 | | | $ | 1.77 | | | $ | 2.32 | | | $ | 280 | |
| Fourth Quarter | | $ | 0.55 | | | $ | 2.61 | | | $ | 3.16 | | | $ | 424 | |
On February 26, 2025, we declared a base quarterly dividend payable of $0.575 per share, which will be paid on March 27, 2025 to stockholders of record at the close of business on March 11, 2025.
Share Repurchase Programs
As of December 2, 2021, the Company was authorized to purchase up to $1.0 billion of the Company’s common stock and/or warrants under a share repurchase program, and in March 2022, we commenced our share repurchase program. In June 2022, our Board of Directors authorized an expansion of the share repurchase program by $1.0 billion, bringing the total authorized share repurchase amount to $2.0 billion for common stock and/or warrants. The $2.0 billion share repurchase program expired on December 31, 2023.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The table below presents the shares purchased under the $2.0 billion share repurchase program.
| | | | | | | | | | | | | | | | | | | | |
| | Shares Purchased (thousands) | | Dollar Value of Shares Purchased | | Average Price Per Share |
| 2022 | | | | | | |
| First Quarter | | 1,000 | | $ | 83 | | | $ | 82.98 | |
| Second Quarter | | 5,812 | | $ | 515 | | | $ | 88.67 | |
| Third Quarter | | 750 | | $ | 69 | | | $ | 92.14 | |
| Fourth Quarter | | 4,105 | | $ | 406 | | | $ | 98.90 | |
| 2023 | | | | | | |
| First Quarter | | 793 | | $ | 60 | | | $ | 74.95 | |
| Second Quarter | | 1,444 | | $ | 115 | | | $ | 78.77 | |
| Third Quarter | | 1,509 | | $ | 130 | | | $ | 86.16 | |
| Fourth Quarter | | 627 | | $ | 52 | | | $ | 82.03 | |
| Total | | 16,040 | | $ | 1,430 | | | |
The repurchased shares of common stock were retired and recorded as a reduction to common stock and retained earnings. All share repurchases made after January 1, 2023 are subject to a 1% excise tax on share repurchases, as enacted under the Inflation Reduction Act of 2022. We are able to net this 1% excise tax on share repurchases against certain issuance of shares of our common stock. The impact of this 1% excise tax was immaterial during the year ended December 31, 2023.
On October 22, 2024, our Board of Directors authorized the Company to repurchase up to $1.0 billion, in aggregate, of the Company’s common stock and/or warrants under a new share repurchase program.
Enhanced Returns Framework
In October 2024, we announced our enhanced capital returns framework which is designed to more effectively return cash to shareholders and reduce net debt. The plan became effective January 1, 2025, and prioritizes the base dividend of $2.30 per share and a targeted $500 million of annual net debt reduction in 2025, which target will be redetermined annually. Once both have been funded, it is anticipated that 75% of remaining free cash flow will be distributed as market conditions warrant, between share repurchases and additional dividend payments. The remaining free cash flow will be maintained on the balance sheet.
Warrants | | | | | | | | | | | | | | | | | |
| Class A Warrants | | Class B Warrants | | Class C Warrants(a) |
| Outstanding as of December 31, 2021 | 10,856,852 | | | 12,313,273 | | | 11,388,371 | |
Converted into common stock(b) | (1,609,641) | | | (29,679) | | | (959,247) | |
Converted in warrant exchange offer(b) | (4,752,207) | | | (7,879,030) | | | (7,252,004) | |
| Issued for General Unsecured Claims | — | | | — | | | 829,109 | |
| Outstanding as of December 31, 2022 | 4,495,004 | | | 4,404,564 | | | 4,006,229 | |
Converted into common stock(b) | (247,389) | | | (1,500) | | | (5,581) | |
| Issued for General Unsecured Claims | — | | | — | | | 22,835 | |
| Outstanding as of December 31, 2023 | 4,247,615 | | | 4,403,064 | | | 4,023,483 | |
Converted into common stock(b) | (2,993,136) | | | (1,329,870) | | | (524,242) | |
| Issued for General Unsecured Claims | — | | | — | | | 884,393 | |
| Outstanding as of December 31, 2024 | 1,254,479 | | | 3,073,194 | | | 4,383,634 | |
_________________________________________ (a)As of December 31, 2024, we had 582,109 of reserved Class C Warrants.
(b)During the years ended December 31, 2024 and December 31, 2023, we issued 4,083,103 and 221,952 common shares, respectively, as a result of Warrant exercises. During the year ended December 31, 2022, we
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
issued 18,408,228 common shares as a result of Warrant exercises, inclusive of the shares issued as part of the Warrant exchange offers described below.
Our Class A, Class B and Class C Warrants were initially exercisable for one share of common stock per Warrant at initial exercise prices of $27.63, $32.13 and $36.18 per share, respectively, subject to adjustments pursuant to the terms of the Warrants. The Warrants are exercisable until February 9, 2026. The Warrants contain customary anti-dilution adjustments in the event of any stock split, reverse stock split, reclassification, stock dividend or other distributions. The exercise prices of the Warrants were adjusted to prevent the dilution of rights for the effects of the quarterly dividend distribution on December 4, 2024, and the adjusted exercise prices are $22.58, $26.25, and $29.56 per share for the Class A, Class B and Class C Warrants, respectively. Additionally, we have recalculated the number of shares of common stock issuable upon the exercise of each of the Class A, Class B and Class C Warrants, respectively, and as a result, 1.22 shares are issuable upon the exercise of a Class A, Class B or Class C Warrant.
On August 18, 2022, we announced exchange offers relating to our outstanding Class A Warrants, Class B Warrants and Class C Warrants. The exchange offers expired on October 7, 2022 and resulted in the issuance of 16,305,984 shares of our common stock in exchange for the cancellation of (i) 4,752,207 Class A Warrants, (ii) 7,879,030 Class B Warrants and (iii) 7,252,004 Class C Warrants. Under the exchange offers, the Warrants were exchanged in a cashless transaction and were converted to shares of our common stock at a ratio of 0.8636 for Class A Warrants, 0.8224 for Class B Warrants and 0.7890 for Class C Warrants, respectively. As the fair value of the common stock issued was greater than the fair value of the Warrants tendered in the exchange offers due to stated exchange premiums, we recorded a non-cash deemed dividend of $67 million. Such fair values were determined using our stock price that is considered a Level 1 input.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| | | | | |
| 11. | Share-Based Compensation |
Our long-term incentive plan, as amended and adopted by our Board of Directors (the “LTIP”), provides for the grant of restricted stock units (“RSUs”), restricted stock awards, stock options, stock appreciation rights, performance awards and other stock awards to the Company’s employees and non-employee directors and has a share reserve equal to 6,800,000 shares of common stock.
Restricted Stock Units. During the years ended December 31, 2024, 2023 and 2022, we granted RSUs to employees and non-employee directors under the LTIP, which will vest over a three-year to five-year period and one-year period, respectively. The fair value of RSUs is based on the closing sales price of our common stock on the date of grant, and compensation expense is recognized ratably over the requisite service period. A summary of the changes in unvested RSUs is presented below:
| | | | | | | | | | | | | | |
| |
Unvested
Restricted Stock Units | | Weighted Average
Grant Date
Fair Value Per Share |
| | (in thousands) | | |
| Unvested as of December 31, 2021 | | 775 | | | $ | 46.77 | |
| Granted | | 666 | | | $ | 81.87 | |
| Vested | | (300) | | | $ | 48.11 | |
| Forfeited | | (184) | | | $ | 56.54 | |
| Unvested as of December 31, 2022 | | 957 | | | $ | 68.91 | |
| Granted | | 440 | | | $ | 72.25 | |
| Vested | | (329) | | | $ | 61.66 | |
| Forfeited | | (128) | | | $ | 68.42 | |
| Unvested as of December 31, 2023 | | 940 | | | $ | 73.08 | |
Granted (a) | | 962 | | | $ | 83.09 | |
Vested (a) | | (925) | | | $ | 74.18 | |
| Forfeited | | (20) | | | $ | 77.71 | |
| Unvested as of December 31, 2024 | | 957 | | | $ | 81.99 | |
_________________________________________(a)Approximately 5.2 million Southwestern RSUs were converted to 478 thousand Company RSUs, of which approximately 384 thousand RSUs were accelerated. We recognized the accelerated share-based compensation expense related to these awards in other operating expense, net on our consolidated statements of operations. Additionally, approximately 105 thousand RSUs were accelerated related to one-time termination benefits for certain employees.
The aggregate intrinsic value of RSUs that vested during the years ended December 31, 2024, 2023 and 2022 was approximately $77 million, $25 million and $26 million, respectively, based on the stock price at the time of vesting.
As of December 31, 2024, there was approximately $46 million of total unrecognized compensation expense related to unvested RSUs. The expense is expected to be recognized over a weighted average period of approximately 2.04 years.
Performance Share Units. During the years ended December 31, 2024, 2023 and 2022, we granted performance share units (“PSUs”) to senior management under the LTIP, which will generally vest over a three-year period and will be settled in shares. The performance criteria include total shareholder return (“TSR”) and relative TSR (“rTSR”) and could result in a total payout between 0% - 200% of the target units. The fair value of the PSUs was measured on the grant date using a Monte Carlo simulation, and compensation expense is recognized ratably over the requisite service period because these awards depend on a combination of service and market criteria.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
The following table presents the assumptions used in the valuation of the PSUs granted during the years ended December 31, 2024, 2023 and 2022.
| | | | | | | | | | | | | | | | | | | | |
| Assumption - TSR, rTSR | | 2024 PSU Awards | | 2023 PSU Awards | | 2022 PSU Awards |
| Risk-free interest rate | | 4.55 | % | | 3.85 | % | | 2.00 | % |
| Volatility | | 39.36 | % | | 64.4 | % | | 70.2 | % |
A summary of the changes in unvested PSUs is presented below:
| | | | | | | | | | | | | | |
| | Unvested Performance Share Units | | Weighted Average
Grant Date
Fair Value Per Share |
| | (in thousands) | | |
| Unvested as of December 31, 2021 | | 183 | | | $ | 66.12 | |
| Granted | | 133 | | | $ | 109.65 | |
| Vested | | — | | | $ | — | |
| Forfeited | | (40) | | | $ | 57.48 | |
| Unvested as of December 31, 2022 | | 276 | | | $ | 88.28 | |
| Granted | | 131 | | | $ | 78.78 | |
| Vested | | — | | | $ | — | |
| Forfeited | | (13) | | | $ | 68.77 | |
| Unvested as of December 31, 2023 | | 394 | | | $ | 85.78 | |
| Granted | | 133 | | | $ | 95.33 | |
| Vested | | (151) | | | $ | 71.29 | |
| Forfeited | | — | | | $ | — | |
| Unvested as of December 31, 2024 | | 376 | | | $ | 94.67 | |
The aggregate intrinsic value of PSUs that vested during the year ended December 31, 2024 was approximately $19 million based on the stock price at the time of vesting.
As of December 31, 2024, there was approximately $14 million of total unrecognized compensation expense related to unvested PSUs. The expense is expected to be recognized over a weighted average period of approximately 1.84 years.
RSU and PSU Compensation.
We recognized the following compensation costs, net of actual forfeitures, related to RSUs and PSUs for the periods presented:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2024 | | 2023 | | 2022 |
| General and administrative expenses | | $ | 33 | | | $ | 29 | | | $ | 19 | |
| Natural gas and oil properties | | 7 | | | 6 | | | 4 | |
| Production expense | | 4 | | | 4 | | | 3 | |
| Separation and other termination costs | | 9 | | | — | | | — | |
| Other operating expense, net | | 28 | | | — | | | — | |
| Total RSU and PSU compensation | | $ | 81 | | | $ | 39 | | | $ | 26 | |
| Related income tax benefit | | $ | 13 | | | $ | 7 | | | $ | 6 | |
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| | | | | |
| 12. | Employee Benefit Plans |
Our qualified 401(k) profit sharing plan (“401(k) Plan”) is the Expand Energy Corporation 401(k) Plan, which is open to employees of Expand Energy and all our subsidiaries. Eligible employees may elect to defer compensation through voluntary contributions to their 401(k) Plan accounts, subject to plan limits and those set by the IRS. We match employee contributions dollar for dollar (subject to a maximum contribution of 6% of an employee's base salary and performance bonus) in cash. In addition to our employer match contributions, in 2022 we commenced a discretionary fixed dollar contribution benefit for all employees, paid quarterly, which is based upon a calculation of 1% of Adjusted Free Cash Flow less the base quarterly dividend. This discretionary fixed dollar contribution is subject to an annual maximum contribution of $15,000 per employee. We contributed $8 million, $13 million and $22 million to the 401(k) Plan during the years ended December 31, 2024, 2023 and 2022, respectively.
| | | | | |
| 13. | Derivative and Hedging Activities |
We use derivative instruments to reduce our exposure to fluctuations in future commodity prices and to protect our expected operating cash flow against significant market movements or volatility. All of our natural gas, oil and NGL derivative instruments are net settled based on the difference between the fixed-price payment and the floating-price payment, resulting in a net amount due to or from the counterparty. None of our open natural gas, oil and NGL derivative instruments were designated for hedge accounting as of December 31, 2024 and 2023.
Natural Gas, Oil and NGL Derivatives
As of December 31, 2024 and 2023, our natural gas, oil and NGL derivative instruments consisted of the following types of instruments:
•Swaps: We receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. In exchange for higher fixed prices on certain of our swap trades, we may sell call options and swap options.
•Options: We have bought and sold call options in exchange for a premium. At the time of settlement, if the market price exceeded the fixed price of the call option, we paid the counterparty the excess on sold call options and received the excess on bought call options. If the market price settled below the fixed price of the call option, no payment was due from either party.
•Collars: These instruments contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the put and the call strike prices, no payments are due from either party. Three-way collars included the sale by us of an additional put option in exchange for a more favorable strike price on the call option. This eliminated the counterparty’s downside exposure below the second put option strike price.
•Basis Protection Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. We receive the fixed price differential and pay the floating market price differential to the counterparty for the hedged commodity.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Contingent Consideration Arrangement
In November 2023, we sold the final portion of our Eagle Ford assets to SilverBow. As part of the divestiture agreement, SilverBow agreed to pay the Company an additional contingent payment of $25 million should WTI NYMEX prices average between $75 and $80 per barrel or $50 million should WTI NYMEX prices average above $80 per barrel during the year following the close of the transaction. On July 30, 2024, Crescent acquired SilverBow. The changes in fair value, and the realized gains were recognized as a gain or loss in earnings in the period they occurred within natural gas, oil and NGL derivatives in our consolidated statements of operations. During 2024, we received the contingent payment of $25 million from Crescent based upon the average NYMEX prices during the year following the close of the transaction.
The estimated fair values of our natural gas, oil and NGL derivative instrument assets (liabilities) as of December 31, 2024 and 2023 are provided below:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2024 | | December 31, 2023 |
| | Notional Volume | | Fair Value | | Notional Volume | | Fair Value |
| Natural gas (Bcf): | | | | | | | | |
| Fixed-price swaps | | 369 | | | $ | (28) | | | 343 | | | $ | 188 | |
| Collars | | 1,098 | | | (27) | | | 558 | | | 497 | |
| Three-way collars | | 161 | | | 60 | | | — | | | — | |
| Call options (purchased) | | 73 | | | 1 | | | — | | | — | |
| Call options (sold) | | 219 | | | (16) | | | — | | | — | |
| Basis protection swaps | | 279 | | | (39) | | | 578 | | | 2 | |
| Total natural gas | | 2,199 | | | (49) | | | 1,479 | | | 687 | |
| Oil (MMBbls): | | | | | | | | |
| Three-way collars | | 2 | | | $ | 4 | | | — | | | $ | — | |
| Total oil | | 2 | | | 4 | | | — | | | — | |
| NGLs (MMBbls): | | | | | | | | |
| Fixed-price swaps | | 7 | | | $ | (9) | | | — | | | $ | — | |
| Total NGL | | 7 | | | (9) | | | — | | | — | |
| Contingent Consideration: | | | | | | | | |
| Eagle Ford divestiture | | | | — | | | | | 12 | |
| Total estimated fair value | | | | $ | (54) | | | | | $ | 699 | |
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Effect of Derivative Instruments – Consolidated Balance Sheets
The following table presents the fair value and location of each classification of derivative instrument included in the consolidated balance sheets as of December 31, 2024 and 2023 on a gross basis and after same-counterparty netting:
| | | | | | | | | | | | | | | | | | | | |
| | Gross Fair Value(a) | | Amounts Netted in the Consolidated Balance Sheets | | Net Fair Value Presented in the Consolidated Balance Sheets |
| As of December 31, 2024 | | | | | | |
| Commodity Contracts: | | | | | | |
| Short-term derivative asset | | $ | 191 | | | $ | (107) | | | $ | 84 | |
| Long-term derivative asset | | 6 | | | (5) | | | 1 | |
| Short-term derivative liability | | (178) | | | 107 | | | (71) | |
| Long-term derivative liability | | (73) | | | 5 | | | (68) | |
| Contingent Consideration: | | | | | | |
| Short-term derivative asset | | — | | | — | | | — | |
| Total derivatives | | $ | (54) | | | $ | — | | | $ | (54) | |
| | | | | | |
| As of December 31, 2023 | | | | | | |
| Commodity Contracts: | | | | | | |
| Short-term derivative asset | | $ | 661 | | | $ | (36) | | | $ | 625 | |
| Long-term derivative asset | | 101 | | | (27) | | | 74 | |
| Short-term derivative liability | | (39) | | | 36 | | | (3) | |
| Long-term derivative liability | | (36) | | | 27 | | | (9) | |
| Contingent Consideration: | | | | | | |
| Short-term derivative asset | | 12 | | | — | | | 12 | |
| Total derivatives | | $ | 699 | | | $ | — | | | $ | 699 | |
___________________________________________
(a)These financial assets (liabilities) are measured at fair value on a recurring basis utilizing significant other observable inputs; see further discussion on fair value measurements below.
Fair Value
The fair value of our commodity derivatives is based on third-party pricing models, which utilize inputs that are either readily available in the public market, such as natural gas, oil and NGL forward curves and discount rates, or can be corroborated from active markets or broker quotes, and, as such, are classified as Level 2. These values are compared to the values given by our counterparties for reasonableness. Derivatives are also subject to the risk that either party to a contract will be unable to meet its obligations. We factor non-performance risk into the valuation of our derivatives using current published credit default swap rates. To date, this has not had a material impact on the values of our derivatives. The valuation of the contingent consideration is based on an option pricing model using significant Level 2 inputs that include quoted future commodity prices based on active markets.
Credit Risk Considerations
Our derivative instruments expose us to our counterparties’ credit risk. To mitigate this risk, we only enter into commodity contracts derivatives with counterparties that are highly rated or deemed by us to have acceptable credit strength and deemed by management to be competent and competitive market-makers, and we attempt to limit our exposure to non-performance by any single counterparty. As of December 31, 2024, our commodity contracts derivative instruments were spread among 20 counterparties.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Hedging Arrangements
Certain of our hedging arrangements are with counterparties that are also Lenders (or affiliates of Lenders) under our Credit Facility. The contracts entered into with these counterparties were previously secured by the same collateral that secured the Pre-IG Credit Facility, but such collateral was released on October 28, 2024 in connection with the Investment Grade Credit Agreement Amendment. We do not expect to post cash or letters of credit to secure our obligations under such contracts while we have the investment grade ratings described in Note 4. The obligations under these contracts must be secured by cash or letters of credit to the extent that any mark-to-market amounts exceed defined thresholds. As of December 31, 2024, we did not have any cash or letters of credit posted as collateral for our commodity derivatives. | | | | | |
| 14. | Other Property and Equipment |
A summary of other property and equipment held for use and the estimated useful lives thereof is as follows:
| | | | | | | | | | | | | | | | | | | | |
| | | | Estimated Useful Life |
| | December 31, 2024 | | December 31, 2023 | |
| | | | | | (in years) |
| Buildings and improvements | | $ | 329 | | | $ | 316 | | | 10 - 39 |
| Computer equipment | | 110 | | | 94 | | | 5 |
Gathering and water systems(a) | | 78 | | | — | | | 7 - 20 |
| Machinery and equipment | | 40 | | | 19 | | | 7 - 10 |
| Land | | 29 | | | 28 | | | |
| Other | | 68 | | | 40 | | | 3 - 30 |
| Total other property and equipment, at cost | | 654 | | | 497 | | | |
| Less: accumulated depreciation | | (127) | | | (90) | | | |
| Total other property and equipment, net | | $ | 527 | | | $ | 407 | | | |
___________________________________________
(a)These assets were acquired as a result of the Southwestern Merger. See Note 2 for further discussion of this transaction.
Momentum Sustainable Ventures LLC. During the fourth quarter of 2022, the Company entered into an agreement with Momentum Sustainable Ventures LLC to build a new natural gas gathering pipeline and carbon capture project, which will gather and treat natural gas produced in the Haynesville Shale for re-delivery to Gulf Coast markets, including LNG export. The pipeline is expected to have an initial capacity of 1.7 Bcf/d expandable to 2.2 Bcf/d. The carbon capture portion of the project anticipates capturing approximately 1.0 million tons per annum of CO2 and delivering the CO2 to ExxonMobil Low Carbon Solutions Onshore Storage, LLC for additional transportation and storage. The natural gas gathering pipeline is projected for a potential in-service date in the fourth quarter of 2025. We have a 35% interest in the joint venture entity. We have accounted for this investment as an equity method investment, and its carrying value, which is reflected within other long-term assets on the consolidated balance sheets, was $307 million and $238 million as of December 31, 2024 and December 31, 2023, respectively. As of December 31, 2024, the carrying value of our investment included approximately $17 million of capitalized interest related to the project.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
| | | | | |
| 16. | Asset Retirement Obligations |
The components of the change in our asset retirement obligations are shown below:
| | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2024 | | 2023 |
| Asset retirement obligations, beginning of period | | $ | 276 | | | $ | 335 | |
Additions(a) | | 263 | | | 9 | |
Revisions(b) | | (21) | | | (9) | |
Settlements and disposals(c) | | (5) | | | (75) | |
| Accretion expense | | 18 | | | 16 | |
| Asset retirement obligations, end of period | | 531 | | | 276 | |
| Less current portion | | 32 | | | 11 | |
| Asset retirement obligations, long-term | | $ | 499 | | | $ | 265 | |
___________________________________________
(a) During the year ended December 31, 2024, approximately $251 million of additions relate to the Southwestern Merger. See Note 2 for further discussion of this transaction. (b) Revisions primarily represent changes in the present value of liabilities resulting from changes in estimated costs and economic lives of producing properties.
(c) During the year ended December 31, 2023, approximately $64 million of disposals related to the divestitures of our Eagle Ford assets. See Note 2 for further discussion of these transactions.
| | | | | |
| 17. | Supplemental Cash Flow Information |
Supplemental disclosures to the consolidated statements of cash flows are presented below.
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2024 | | 2023 | | 2022 |
| Changes in assets and liabilities | | | | | | |
| Accounts receivable | | $ | (168) | | | $ | 857 | | | $ | (106) | |
| Accounts payable | | (62) | | | (152) | | | 49 | |
| Other current assets | | 3 | | | 143 | | | (182) | |
| Other current liabilities | | (88) | | | (573) | | | 116 | |
| Total | | $ | (315) | | | $ | 275 | | | $ | (123) | |
| | | | | | |
| Supplemental cash flow information: | | | | | | |
| Interest paid, net of capitalized interest | | $ | 93 | | | $ | 117 | | | $ | 146 | |
| Income taxes paid (refunds received), net | | $ | (3) | | | $ | 132 | | | $ | 193 | |
| | | | | | |
Supplemental disclosure of significant
non-cash investing and financing activities: | | | | | | |
| Change in accrued drilling and completion costs | | $ | (49) | | | $ | (31) | | | $ | 148 | |
| Common stock issued for business combination | | $ | 7,888 | | | $ | — | | | $ | 764 | |
| Operating lease obligations recognized | | $ | 137 | | | $ | 96 | | | $ | 120 | |
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Operating segments are defined as components of an enterprise that engage in activities from which it may earn revenues and incur expenses for which separate operational financial information is available and is regularly evaluated by the CODM, who is our Chief Executive Officer, for the purpose of allocating an enterprise’s resources and assessing its operating performance. Our revenues are derived from the production, marketing and sale of natural gas, oil and NGL. Additional information on our revenues, including the disaggregation of our revenues and major customers, is found in Note 8. As of December 31, 2024, we considered each of our operating areas as operating segments, however, we have aggregated those operating segments into one reportable segment due to the similar nature of the exploration and production business across Expand Energy and its consolidated subsidiaries and the fact that our marketing activities are ancillary to our operations. Our CODM uses consolidated net income (loss), for purposes of allocating resources and in assessing Expand Energy’s operating performance. Additionally, our CODM is regularly provided information on production expense, gathering, processing and transportation expense, severance and ad valorem taxes and general and administrative expense, which are our significant segment expenses. Other segment items primarily consist of depreciation, depletion and amortization, marketing expense, interest expense and income tax expense (benefit). Our significant segment expenses and other segment items are derived from, and can be found within the consolidated statements of operations.
The measure of segment assets is total assets as reported on our consolidated balance sheets, and as of December 31, 2024 and 2023 our total assets were $27,894 million and $14,376 million, respectively. Additionally, in analyzing company performance, our CODM reviews capital expenditures. During the years ended December 31, 2024, 2023 and 2022, our capital expenditures were $1,529 million, $1,782 million and $1,936 million, respectively. During the years ended December 31, 2024, 2023 and 2022, we contributed approximately $58 million, $220 million and $18 million, respectively, to equity method investments, which primarily consisted of our investment with Momentum Sustainable Ventures LLC. Additional discussion around our investment with Momentum Sustainable Ventures LLC is in Note 15. Our interest revenue during the years ended December 31, 2024, 2023 and 2022 was $45 million, $29 million and $1 million, respectively.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
SUPPLEMENTARY INFORMATION
| | | | | |
| Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities (unaudited) | |
Net Capitalized Costs
Capitalized costs related to our natural gas, oil and NGL producing activities are summarized as follows:
| | | | | | | | | | | | | | |
| | December 31, 2024 | | December 31, 2023 |
| Natural gas and oil properties: | | | | |
| Proved | | $ | 23,093 | | | $ | 11,468 | |
| Unproved | | 5,897 | | | 1,806 | |
| Total | | 28,990 | | | 13,274 | |
| Less accumulated depreciation, depletion and amortization | | (5,235) | | | (3,584) | |
| Net capitalized costs | | $ | 23,755 | | | $ | 9,690 | |
Unproved properties as of December 31, 2024 consisted mainly of leasehold acquired through our Southwestern Merger in 2024 and Marcellus Acquisition in 2022 and unproved properties as of December 31, 2023, consisted mainly of leasehold acquired through our Marcellus Acquisition in 2022. We will continue to evaluate our unproved properties, and although the timing of the ultimate evaluation or disposition of the properties cannot be determined, we can expect the majority of our unproved properties not held by production to be transferred into the amortization base over the next five years.
Costs Incurred in Natural Gas and Oil Property Acquisition, Exploration and Development
Costs incurred in natural gas and oil property acquisition, exploration and development, including capitalized interest and asset retirement costs, are summarized as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2024 | | 2023 | | 2022 |
Acquisition of properties(a): | | | | | | |
| Proved properties | | $ | 10,010 | | | $ | 10 | | | $ | 2,321 | |
| Unproved properties | | 4,393 | | | 52 | | | 795 | |
| Exploratory costs | | 17 | | | 15 | | | 15 | |
| Development costs | | 1,420 | | | 1,721 | | | 1,918 | |
| Costs incurred | | $ | 15,840 | | | $ | 1,798 | | | $ | 5,049 | |
___________________________________________
(a) Includes $10.0 billion and $4.3 billion of proved and unproved property acquisitions, respectively, related to the Southwestern Merger in 2024. Includes $2.3 billion and $0.8 billion of proved and unproved property acquisitions, respectively, related to our Marcellus Acquisition in 2022.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
SUPPLEMENTARY INFORMATION - (Continued)
Results of Operations from Natural Gas, Oil and NGL Producing Activities
The following table includes revenues and expenses associated directly with our natural gas, oil and NGL producing activities for the periods presented. It does not include any derivative activity, interest costs or indirect general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our natural gas, oil and NGL operations.
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2024 | | 2023 | | 2022 |
| Natural gas, oil and NGL sales | | $ | 2,969 | | | $ | 3,547 | | | $ | 9,892 | |
| Production expenses | | (316) | | | (356) | | | (475) | |
| Gathering, processing and transportation expenses | | (1,035) | | | (853) | | | (1,059) | |
| Severance and ad valorem taxes | | (97) | | | (167) | | | (242) | |
| Exploration | | (10) | | | (27) | | | (23) | |
| Depletion and depreciation | | (1,673) | | | (1,478) | | | (1,703) | |
| Accretion of asset retirement obligations | | (18) | | | (16) | | | (17) | |
Imputed income tax provision(a) | | 42 | | | (152) | | | (1,440) | |
| Results of operations from natural gas, oil and NGL producing activities | | $ | (138) | | | $ | 498 | | | $ | 4,933 | |
___________________________________________
(a) The imputed income tax provision is hypothetical (at the statutory tax rate) and determined without regard to our deduction for general and administrative expenses, interest costs and other income tax credits and deductions, nor whether the hypothetical tax provision (benefit) will be payable (receivable).
Natural Gas, Oil and NGL Reserve Quantities
Our petroleum engineers estimated all of our proved reserves as of December 31, 2024, 2023 and 2022. Independent petroleum engineering firm Netherland, Sewell & Associates, Inc. audited our total proved reserves as of December 31, 2024.
Proved natural gas, oil and NGL reserves are those quantities of natural gas, oil and NGL which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. Based on reserve reporting rules, the price is calculated using the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within the period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. A project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible natural gas or oil on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
SUPPLEMENTARY INFORMATION - (Continued)
was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.
The information provided below on our natural gas, oil and NGL reserves is presented in accordance with regulations prescribed by the SEC. Our reserve estimates are generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates will change as future information becomes available and as commodity prices change. These changes could be material and could occur in the near term.
Presented below is a summary of changes in estimated proved reserves for the periods presented: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Natural Gas | | Oil | | NGL | | Total |
| | (Bcf) | | (MMBbl) | | (MMBbl) | | (Bcfe) |
| December 31, 2024 | | | | | | | | |
| Proved reserves, beginning of period | | 9,688 | | | — | | | — | | | 9,688 | |
| Extensions, discoveries and other additions | | 124 | | | — | | | — | | | 124 | |
| Revisions of previous estimates | | (1,654) | | | — | | | — | | | (1,654) | |
| Production | | (1,321) | | | (1.2) | | | (7.8) | | | (1,375) | |
| Sale of reserves-in-place | | — | | | — | | | — | | | — | |
| Purchase of reserves-in-place | | 10,087 | | | 69.1 | | | 585.9 | | | 14,017 | |
| Proved reserves, end of period | | 16,924 | | | 67.9 | | | 578.1 | | | 20,800 | |
| Proved developed reserves: | | | | | | | | |
| Beginning of period | | 6,363 | | | — | | | — | | | 6,363 | |
| End of period | | 14,418 | | | 40.3 | | | 383.0 | | | 16,958 | |
| Proved undeveloped reserves: | | | | | | | | |
| Beginning of period | | 3,325 | | | — | | | — | | | 3,325 | |
End of period(a) | | 2,506 | | | 27.6 | | | 195.1 | | | 3,842 | |
| | | | | | | | |
| December 31, 2023 | | | | | | | | |
| Proved reserves, beginning of period | | 11,369 | | | 198.4 | | | 73.9 | | | 13,002 | |
| Extensions, discoveries and other additions | | 415 | | | — | | | — | | | 415 | |
| Revisions of previous estimates | | (325) | | | — | | | — | | | (325) | |
| Production | | (1,266) | | | (7.7) | | | (3.8) | | | (1,335) | |
| Sale of reserves-in-place | | (563) | | | (190.7) | | | (70.1) | | | (2,127) | |
| Purchase of reserves-in-place | | 58 | | | — | | | — | | | 58 | |
| Proved reserves, end of period | | 9,688 | | | — | | | — | | | 9,688 | |
| Proved developed reserves: | | | | | | | | |
| Beginning of period | | 7,385 | | | 157.2 | | | 58.9 | | | 8,681 | |
| End of period | | 6,363 | | | — | | | — | | | 6,363 | |
| Proved undeveloped reserves: | | | | | | | | |
| Beginning of period | | 3,984 | | | 41.2 | | | 15.0 | | | 4,321 | |
End of period(a) | | 3,325 | | | — | | | — | | | 3,325 | |
| | | | | | | | |
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
SUPPLEMENTARY INFORMATION - (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Natural Gas | | Oil | | NGL | | Total |
| | (Bcf) | | (MMBbl) | | (MMBbl) | | (Bcfe) |
| | | | | | | | |
| | | | | | | | |
| December 31, 2022 | | | | | | | | |
| Proved reserves, beginning of period | | 7,824 | | | 209.7 | | | 82.0 | | | 9,573 | |
| Extensions, discoveries and other additions | | 60 | | | 2.1 | | | 1.5 | | | 82 | |
| Revisions of previous estimates | | 1,989 | | | 22.5 | | | 5.0 | | | 2,155 | |
| Production | | (1,308) | | | (19.4) | | | (6.0) | | | (1,461) | |
| Sale of reserves-in-place | | (122) | | | (16.5) | | | (8.6) | | | (273) | |
| Purchase of reserves-in-place | | 2,926 | | | — | | | — | | | 2,926 | |
| Proved reserves, end of period | | 11,369 | | | 198.4 | | | 73.9 | | | 13,002 | |
| Proved developed reserves: | | | | | | | | |
| Beginning of period | | 4,246 | | | 165.7 | | | 61.7 | | | 5,610 | |
| End of period | | 7,385 | | | 157.2 | | | 58.9 | | | 8,681 | |
| Proved undeveloped reserves: | | | | | | | | |
| Beginning of period | | 3,578 | | | 44.0 | | | 20.3 | | | 3,963 | |
End of period(a) | | 3,984 | | | 41.2 | | | 15.0 | | | 4,321 | |
___________________________________________(a) As of December 31, 2024, 2023 and 2022, there were no PUDs that had remained undeveloped for five years or more.
During 2024, we acquired 14,017 Bcfe, primarily related to the Southwestern Merger. We recorded extensions and discoveries of 124 Bcfe, primarily related to new PUDs in Northeast Appalachia and previously unproved producing wells in both Northeast Appalachia and Haynesville. We recorded 1,654 Bcfe of downward revisions of previous estimates, with 2,395 Bcfe of downward revisions due to lower natural gas, oil and NGL prices in 2024, partially offset by 741 Bcfe of non-price related positive revisions. The non-price revisions primarily consisted of 750 Bcfe of reserves increases on existing proved properties, related to increases in PUD forecasts and aligning forecasts for proved developed wells with latest production trends, increased ownership interests in some of the locations, and improved differentials in Haynesville. Also included within the non-price revisions were 174 Bcfe of new PUDs and producing wells in areas previously classified as proved, and 183 Bcfe of downward revisions due to development plan and other changes in Northeast Appalachia and Haynesville. The natural gas, oil and NGL prices used in computing our reserves as of December 31, 2024, were $2.13 per Mcf, $75.48 per Bbl and $75.48 per Bbl, respectively, before basis differential adjustments.
During 2023, we divested 2,127 Bcfe, primarily related to our Eagle Ford divestitures. We recorded extensions and discoveries of 415 Bcfe, primarily related to new PUDs and previously unproved producing wells in the Upper Marcellus and Bossier Shales. We recorded 325 Bcfe of downward revisions of previous estimates, with 1,623 Bcfe of downward revisions due to lower natural gas, oil and NGL prices in 2023, partially offset by 1,298 Bcfe of non-price related positive revisions. The non-price revisions primarily consisted of 1,517 Bcfe from new PUDs and producing wells added in previously proved areas, 469 Bcfe of positive revisions to previously recorded PUD reserves primarily due to expected longer laterals in both Northeast Appalachia and Haynesville, partially offset by downward revisions of 451 Bcfe due to development plan and other changes in Northeast Appalachia and Haynesville, and a downward revision of 237 Bcfe on proved developed reserves related to aligning forecasts with latest production trends. The natural gas, oil and NGL prices used in computing our reserves as of December 31, 2023, were $2.64 per Mcf, $78.22 per Bbl and $28.61 per Bbl, respectively, before basis differential adjustments.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
SUPPLEMENTARY INFORMATION - (Continued)
During 2022, we acquired 2,926 Bcfe, primarily related to the Marcellus Acquisition. We recorded extensions and discoveries of 82 Bcfe, primarily related to new PUDs and previously unproved producing wells in emerging plays. We recorded 2,155 Bcfe of upward revisions of previous estimates, which consisted of 866 Bcfe of revisions to PUDs, primarily due to development plan optimization through prioritizing longer laterals and multi-well pad development in the Haynesville, 1,156 Bcfe of revisions to existing or new proved developed properties, primarily due to performance and 133 Bcfe of revisions due to higher natural gas, oil and NGL prices in 2022. The natural gas, oil and NGL prices used in computing our reserves as of December 31, 2022, were $6.36 per Mcf, $93.67 per Bbl and $43.58 per Bbl, respectively, before basis differential adjustments.
Standardized Measure of Discounted Future Net Cash Flows
Accounting Standards Codification Topic 932 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Expand Energy has followed these guidelines which are briefly discussed below.
Future cash inflows and future production and development costs as of December 31, 2024, 2023 and 2022 were determined by applying the average of the first-day-of-the-month prices for the 12 months of the year and year-end costs to the estimated quantities of natural gas, oil and NGL to be produced. Actual future prices and costs may be materially higher or lower than the prices and costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for that year. Estimated future income taxes are computed using current statutory income tax rates including consideration of the current tax basis of the properties and related carryforwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.
The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting Standards Board and do not necessarily reflect our expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.
The following summary sets forth our future net cash flows relating to proved natural gas, oil and NGL reserves based on the standardized measure:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, | |
| | 2024 | | 2023 | | 2022 | |
| Future cash inflows | | $ | 24,213 | | (a) | $ | 14,659 | | (b) | $ | 76,626 | | (c) |
| Future production costs | | (7,007) | | | (3,326) | | | (10,177) | | |
| Future development costs | | (3,537) | | (d) | (2,779) | | (e) | (5,343) | | (f) |
| Future income tax provisions | | (119) | | | (174) | | | (10,440) | | |
| Future net cash flows | | 13,550 | | | 8,380 | | | 50,666 | | |
| Less effect of a 10% discount factor | | (6,019) | | | (3,903) | | | (24,361) | | |
| Standardized measure of discounted future net cash flows | | $ | 7,531 | | | $ | 4,477 | | | $ | 26,305 | | |
___________________________________________
(a) Calculated using prices of $2.13 per Mcf of natural gas, $75.48 per Bbl of oil and $75.48 per Bbl of NGL, before basis differential adjustments.
(b) Calculated using prices of $2.64 per Mcf of natural gas, before basis differential adjustments.
(c) Calculated using prices of $6.36 per Mcf of natural gas, $93.67 per Bbl of oil and $43.58 per Bbl of NGL, before basis differential adjustments.
(d) Included approximately $1,625 million of future plugging and abandonment costs as of December 31, 2024.
(e) Included approximately $730 million of future plugging and abandonment costs as of December 31, 2023.
(f) Included approximately $979 million of future plugging and abandonment costs as of December 31, 2022.
EXPAND ENERGY CORPORATION AND SUBSIDIARIES
SUPPLEMENTARY INFORMATION - (Continued)
The principal sources of change in the standardized measure of discounted future net cash flows are as follows:
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2024 | | 2023 | | 2022 |
| Standardized measure, beginning of period | | $ | 4,477 | | | $ | 26,305 | | | $ | 12,287 | |
Sales of natural gas and oil produced, net of production costs and gathering, processing and transportation(a) | | (1,521) | | | (2,171) | | | (8,116) | |
| Net changes in prices and production costs | | (2,266) | | | (23,535) | | | 14,256 | |
Extensions and discoveries, net of production and
development costs | | 50 | | | 182 | | | 251 | |
| Changes in estimated future development costs | | 652 | | | 346 | | | (1,512) | |
| Previously estimated development costs incurred during the period | | 396 | | | 818 | | | 690 | |
| Revisions of previous quantity estimates | | (922) | | | (205) | | | 6,697 | |
| Purchase of reserves-in-place | | 5,409 | | | 77 | | | 7,047 | |
| Sales of reserves-in-place | | — | | | (7,158) | | | (402) | |
| Accretion of discount | | 457 | | | 3,270 | | | 1,371 | |
| Net change in income taxes | | 58 | | | 6,301 | | | (4,972) | |
| Changes in production rates and other | | 741 | | | 247 | | | (1,292) | |
Standardized measure, end of period(a) | | $ | 7,531 | | | $ | 4,477 | | | $ | 26,305 | |
___________________________________________
(a) Excludes gains and losses on derivatives. Production costs includes severance and ad valorem taxes.
| | | | | |
| Item 9. | Changes In and Disagreements with Accountants on Accounting and Financial Disclosure |
Not applicable.
| | | | | |
| Item 9A. | Controls and Procedures |
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in reports we file or submit under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure.
As of the end of the period covered by this report, we carried out an evaluation, 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 Exchange Act Rule 13a-15(b). Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded as of December 31, 2024 that our disclosure controls and procedures were effective.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
It is the responsibility of the management of Expand Energy Corporation to establish and maintain adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Management utilized the Committee of Sponsoring Organizations of the Treadway Commission's Internal Control-Integrated Framework (2013) in conducting the required assessment of effectiveness of the Company's internal control over financial reporting.
Management has performed an assessment of the effectiveness of the Company's internal control over financial reporting and has determined the Company’s internal control over financial reporting was effective as of December 31, 2024.
Management’s assessment and conclusion on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2024 excludes an assessment of the internal control over financial reporting of Southwestern Energy, which was acquired in a business combination on October 1, 2024. Southwestern Energy represents approximately 56% of our consolidated total assets as of December 31, 2024 and approximately 35% of our consolidated revenues for the year ended December 31, 2024.
The effectiveness of our internal control over financial reporting as of December 31, 2024 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report which appears herein.
| | | | | | | | | | | | | | |
| /s/ DOMENIC J. DELL'OSSO, JR. | |
| Domenic J. Dell'Osso, Jr. |
| President and Chief Executive Officer |
| | |
| /s/ MOHIT SINGH | |
| Mohit Singh |
| Executive Vice President and Chief Financial Officer |
| | | | |
| February 26, 2025 |
| | | | |
| | | | | |
| Item 9B. | Other Information |
Rule 10b5-1 Trading Arrangements
During the three months ended December 31, 2024, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement”, as each term is defined in Item 408 of Regulation S-K.
Compensatory Arrangements
On February 21, 2025, our Compensation Committee approved a supplement to outstanding restricted stock unit and performance share unit award agreements under the LTIP (the “Global Supplement”) held by certain of our employees, including our executive officers. The Global Supplement provides for a pro rata acceleration and vesting of such awards in connection with a termination by the Company without Cause (as defined in the LTIP); provided, however, that such acceleration will not apply (1) if the holder of such awards has not been employed for at least one year as of the date of termination or (2) if such awards are already subject to full acceleration pursuant to another agreement with the Company.
This summary of the Global Supplement does not purport to be complete and is subject to, and qualified in its entirety by reference to, the full text of the Global Supplement, which is filed as Exhibit 10.34 to this Annual Report on Form 10-K and incorporated herein by reference.
| | | | | |
| Item 9C. | Disclosure Regarding Foreign Jurisdictions that Prevent Inspections |
Not applicable.
PART III
| | | | | |
| Item 10. | Directors, Executive Officers and Corporate Governance |
The names of executive officers of the Company and their ages, titles and biographies as of the date hereof are incorporated by reference from Item 1 of Part I of this report. The other information called for by this Item 10 is incorporated herein by reference to the definitive proxy statement to be filed by Expand Energy pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 no later than 120 days following the fiscal year ended December 31, 2024 (the “2025 Proxy Statement”).
Code of Business Conduct
The Company has adopted a Code of Business Conduct that applies to all of its officers, directors and employees. We have posted a copy of our Code of Business Conduct on the “Sustainability” section of our website at www.expandenergy.com. Any amendments to, or waivers from, our Code of Business Conduct that apply to our executive officers and directors will be posted on the “Sustainability” section of our website at www.expandenergy.com. Note that the information on the Company’s website is not incorporated by reference into this filing.
| | | | | |
| Item 11. | Executive Compensation |
The information called for by this Item 11 is incorporated herein by reference to the 2025 Proxy Statement.
| | | | | |
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
The information called for by this Item 12 is incorporated herein by reference to the 2025 Proxy Statement.
| | | | | |
| Item 13. | Certain Relationships and Related Transactions, and Director Independence |
The information called for by this Item 13 is incorporated herein by reference to the 2025 Proxy Statement.
| | | | | |
| Item 14. | Principal Accountant Fees and Services |
The information called for by this Item 14 is incorporated herein by reference to the 2025 Proxy Statement.
PART IV
| | | | | |
| Item 15. | Exhibits and Financial Statement Schedules |
____________________________________________
(a) The following financial statements, financial statement schedules and exhibits are filed as a part of this report:
1.Financial Statements. Expand Energy's consolidated financial statements are included in Item 8 of Part II of this report. Reference is made to the accompanying Index to Financial Statements. 2.Financial Statement Schedules. No financial statement schedules are applicable or required.
3.Exhibits. The exhibits listed below in the Index of Exhibits are filed, furnished or incorporated by reference pursuant to the requirements of Item 601 of Regulation S-K.
INDEX OF EXHIBITS
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Incorporated by Reference | | |
Exhibit Number | | Exhibit Description | | Form | | SEC File Number | | Exhibit | | Filing Date | | Filed or Furnished Herewith |
| 2.1 | | | | 8-K | | 001-13726 | | 2.1 | | 1/19/2021 | | |
| | | | | | | | | | | | |
| 2.2 | | | | 10-K | | 001-13726 | | 10.36 | | 2/24/2022 | | |
| | | | | | | | | | | | |
| 2.3 | | | | 10-K | | 001-13726 | | 10.37 | | 2/24/2022 | | |
| | | | | | | | | | | | |
| 2.4 | | | | 10-K | | 001-13726 | | 10.38 | | 2/24/2022 | | |
| | | | | | | | | | | | |
| 2.5* | | | | 8-K | | 001-13726 | | 2.1 | | 1/11/2024 | | |
| | | | | | | | | | | | |
| 3.1 | | | | 8-K | | 001-13726 | | 3.1 | | 10/1/2024 | | |
| | | | | | | | | | | | |
| 3.2 | | | | 8-K | | 001-13726 | | 3.2 | | 10/1/2024 | | |
| | | | | | | | | | | | |
| 4.1 | | | | 8-A | | 001-13726 | | N/A | | 2/9/2021 | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 10.1 | | | | 8-K | | 001-13726 | | 10.1 | | 6/29/2020 | | |
| | | | | | | | | | | | |
| 10.2 | | | | 8-K | | 001-13726 | | 10.1 | | 6/29/2020 | | |
| | | | | | | | | | | | |
| 10.3 | | | | 8-K | | 001-13726 | | 10.2 | | 2/9/2021 | | |
| | | | | | | | | | | | |
| 10.4 | | | | 8-K | | 001-13726 | | 10.3 | | 2/9/2021 | | |
| | | | | | | | | | | | |
| 10.5 | | | | 8-K | | 001-13726 | | 10.4 | | 2/9/2021 | | |
| | | | | | | | | | | | |
| 10.6 | | | | 8-K | | 001-13726 | | 10.5 | | 2/9/2021 | | |
| | | | | | | | | | | | |
| 10.7 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 10.8† | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 10.9 | | | | 10-K | | 001-13726 | | 10.10 | | 3/1/2021 | | |
| | | | | | | | | | | | |
| 10.10 | | | | 10-K | | 001-13726 | | 10.11 | | 3/1/2021 | | |
| | | | | | | | | | | | |
| 10.11 | | | | 10-K | | 001-13726 | | 10.12 | | 3/1/2021 | | |
| | | | | | | | | | | | |
| 10.12 | | | | 10-K | | 001-13726 | | 10.13 | | 3/1/2021 | | |
| | | | | | | | | | | | |
| 10.13† | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 10.14† | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 10.15† | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 10.16† | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 10.17† | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 10.18† | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 10.19† | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 10.20† | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 10.21 | | | | 8-K | | 001-13726 | | 4.1 | | 11/2/2021 | | |
| | | | | | | | | | | | |
| 10.22 | | | | 8-K | | 001-13726 | | 4.2 | | 11/2/2021 | | |
| | | | | | | | | | | | |
| 10.23 | | | | 8-K | | 001-13726 | | 10.1 | | 3/9/2022 | | |
| | | | | | | | | | | | |
| 10.24 | | | | 8-K | | 001-13726 | | 10.2 | | 3/9/2022 | | |
| | | | | | | | | | | | |
| 10.25 | |
| | S-4 | | 333-266961 | | 10.34 | | 8/18/2022 | | |
| | | | | | | | | | | | |
| 10.26 | |
| | S-4/A | | 333-266961 | | 10.35 | | 9/12/2022 | | |
| | | | | | | | | | | | |
| 10.27 | | | | 8-K | | 001-13726 | | 10.1 | | 12/12/2022 | | |
| | | | | | | | | | | | |
| 10.28† | | | | 8-K | | 001-13726 | | 10.1 | | 1/11/2024 | | |
| | | | | | | | | | | | |
| 10.29† | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 10.30 | | | | 8-K | | 001-13726 | | 4.1 | | 12/2/2024 | | |
| | | | | | | | | | | | |
| 10.31 | | | | 8-K | | 001-13726 | | 4.2 | | 12/2/2024 | | |
| | | | | | | | | | | | |
| 10.32 | | | | 10-Q | | 001-13726 | | 10.1 | | 7/29/2024 | | |
| | | | | | | | | | | | |
| 10.33 | | | | 8-K | | 001-13726 | | 10.1 | | 11/1/2024 | | |
| | | | | | | | | | | | |
| 10.34† | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 19.1 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 21 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 23.1 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 23.2 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 31.1 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 31.2 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 32.1** | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 32.2** | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 97.1 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 99.1 | | | | | | | | | | | | X |
| | | | | | | | | | | | |
| 101 INS | | Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | | | | | | | | | | X |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 101 SCH | | Inline XBRL Taxonomy Extension Schema Document. | | | | | | | | | | X |
| | | | | | | | | | | | |
| 101 CAL | | Inline XBRL Taxonomy Extension Calculation Linkbase Document. | | | | | | | | | | X |
| | | | | | | | | | | | |
| 101 DEF | | Inline XBRL Taxonomy Extension Definition Linkbase Document. | | | | | | | | | | X |
| | | | | | | | | | | | |
| 101 LAB | | Inline XBRL Taxonomy Extension Labels Linkbase Document. | | | | | | | | | | X |
| | | | | | | | | | | | |
| 101 PRE | | Inline XBRL Taxonomy Extension Presentation Linkbase Document. | | | | | | | | | | X |
| | | | | | | | | | | | |
| 104 | | Cover Page Interactive Data file (formatted as Inline XBRL and contained in Exhibit 101). | | | | | | | | | | X |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
| * | | Schedules have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The registrant hereby undertakes to furnish supplemental copies of any of the omitted schedules upon request by the SEC. |
| ** | | Furnished herewith. | | | | | | | | | | |
| † | | Management contract or compensatory plan or arrangement. |
| | | | | | | | | | | | |
| PLEASE NOTE: Pursuant to the rules and regulations of the Securities and Exchange Commission, we have filed or incorporated by reference the agreements referenced above as exhibits to this Annual Report on Form 10-K. The agreements have been filed to provide investors with information regarding their respective terms. The agreements are not intended to provide any other factual information about Expand Energy Corporation or its business or operations. In particular, the assertions embodied in any representations, warranties and covenants contained in the agreements may be subject to qualifications with respect to knowledge and materiality different from those applicable to investors and may be qualified by information in confidential disclosure schedules not included with the exhibits. These disclosure schedules may contain information that modifies, qualifies and creates exceptions to the representations, warranties and covenants set forth in the agreements. Moreover, certain representations, warranties and covenants in the agreements may have been used for the purpose of allocating risk between the parties, rather than establishing matters as facts. In addition, information concerning the subject matter of the representations, warranties and covenants may have changed after the date of the respective agreement, which subsequent information may or may not be fully reflected in our public disclosures. Accordingly, investors should not rely on the representations, warranties and covenants in the agreements as characterizations of the actual state of facts about Expand Energy Corporation or its business or operations on the date hereof. |
| | | | | |
| Item 16. | Form 10-K Summary |
Not applicable.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| | | | | | | | | | | |
| EXPAND ENERGY CORPORATION |
| | | |
| Date: February 26, 2025 | By: | | /s/ DOMENIC J. DELL’OSSO, JR. |
| | | Domenic J. Dell’Osso, Jr. |
| | | President and Chief Executive Officer |
POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints Domenic J. Dell'Osso, Jr. his true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any or all amendments to this Annual Report on Form 10-K, and to file the same, with all, exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent full power and authority to do and perform each, and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, and each of them, or the substitute or substitutes of any or all of them, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| | | | | | | | | | | | | | |
| Signature | | Capacity | | Date |
| /s/ DOMENIC J. DELL’OSSO, JR. | | President and Chief Executive Officer (Principal Executive Officer) | | February 26, 2025 |
| Domenic J. Dell’Osso, Jr. |
| | | | |
| /s/ MOHIT SINGH | | Executive Vice President and Chief Financial Officer (Principal Financial Officer) | | February 26, 2025 |
| Mohit Singh |
| | | | |
| /s/ GREGORY M. LARSON | | Vice President - Accounting & Controller (Principal Accounting Officer) | | February 26, 2025 |
| Gregory M. Larson |
| | | | |
| /s/ MICHAEL A. WICHTERICH | | Chairman of the Board | | February 26, 2025 |
| Michael A. Wichterich |
| | | | |
| /s/ TIMOTHY S. DUNCAN | | Director | | February 26, 2025 |
| Timothy S. Duncan |
| | | | |
| /s/ BENJAMIN C. DUSTER, IV | | Director | | February 26, 2025 |
| Benjamin C. Duster, IV |
| | | | |
| /s/ SARAH A. EMERSON | | Director | | February 26, 2025 |
| Sarah A. Emerson |
| | | | |
| /s/ MATTHEW M. GALLAGHER | | Director | | February 26, 2025 |
| Matthew M. Gallagher |
| | | | |
| /s/ JOHN D. GASS | | Director | | February 26, 2025 |
| John D. Gass |
| | | | |
| /s/ SYLVESTER P. JOHNSON IV | | Director | | February 26, 2025 |
| Sylvester P. Johnson IV |
| | | | |
| /s/ CATHERINE A. KEHR | | Director | | February 26, 2025 |
| Catherine A. Kehr |
| | | | |
| /s/ SHAMEEK KONAR | | Director | | February 26, 2025 |
| Shameek Konar |
| | | | |
| /s/ BRIAN STECK | | Director | | February 26, 2025 |
| Brian Steck |
