
	Three Months Ended June 30,		Six Months Ended June 30,
(In millions, except per share amounts)	2025	2024	2025	2024
OPERATING REVENUES
Oil	$	$	$	$
Natural gas
NGL
Gain (loss) on derivative instruments		()		()
Other

OPERATING EXPENSES
Direct operations
Gathering, processing and transportation
Taxes other than income
Exploration
Depreciation, depletion and amortization

General and administrative


Gain on sale of assets
INCOME FROM OPERATIONS

Interest expense
Interest income	()	()	()	()
Other income	()		()
Income before income taxes
Income tax expense
NET INCOME	$	$	$	$


Earnings per share
Basic	$	$	$	$
Diluted	$	$	$	$

Weighted-average common shares outstanding
Basic
Diluted

The accompanying notes are an integral part of these condensed consolidated financial statements.

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COTERRA ENERGY INC.

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)


	Six Months Ended June 30,
(In millions)	2025	2024
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	$
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization

Deferred income tax expense (benefit)		()
Gain on sale of assets	()

(Gain) loss on derivatives	()
Net cash received on settlement of derivative instruments


Amortization of debt premium, discount and debt issuance costs, net	()	()

Stock-based compensation and other
Changes in assets and liabilities:
Accounts receivable, net		()
Income taxes	()	()
Inventories	()
Other current assets		()
Accounts payable and accrued liabilities	()	()
Interest payable
Other assets and liabilities		()

Net cash provided by operating activities

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for drilling, completion and other fixed asset additions	()	()
Capital expenditures for leasehold and property acquisitions	()	()
Cash consideration paid for business combinations, net of cash received	()
Purchases of short-term investments		()

Proceeds from sale of assets



Other	()
Net cash used in investing activities	()	()

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of debt
Repayments of debt	()
Common stock repurchases	()	()
Dividends paid	()	()




Tax withholding on vesting of stock awards	()


Other	()	()
Net cash provided by (used in) financing activities		()

Net (decrease) increase in cash, cash equivalents and restricted cash	()
Cash, cash equivalents and restricted cash, beginning of period
Cash, cash equivalents and restricted cash, end of period	$	$

The accompanying notes are an integral part of these condensed consolidated financial statements.

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COTERRA ENERGY INC.

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (Unaudited)

(In millions, except per share amounts)

Common Shares

Common Stock Par

Treasury Shares

Treasury Stock

Additional Paid-In Capital

Accumulated Other Comprehensive Income

Retained Earnings

Total

Balance at December 31, 2024

Net income

—

Issuance of common stock for acquisition

—

Stock amortization and vesting

—

()

—

()

Common stock repurchases

—

()

—

()

Common stock retirements

()

—

()

—

Cash dividends on common stock at $ per share

—

()

Other comprehensive income

—

Balance at March 31, 2025

Net income

—

Stock amortization and vesting

—

Common stock repurchases

—

()

—

()

Common stock retirements

()

—

()

—

Cash dividends on common stock at $ per share

—

()

Balance at June 30, 2025

(In millions, except per share amounts)

Common Shares

Common Stock Par

Treasury Shares

Treasury Stock

Additional Paid-In Capital

Accumulated Other Comprehensive Income

Retained Earnings

Total

Balance at December 31, 2023

Net income

—

Stock amortization and vesting

—

Common stock repurchases

—

()

—

()

Common stock retirements

()

—

()

—

Cash dividends on common stock at $ per share

—

()

Balance at March 31, 2024

Net income

—

Exercise of stock options

—

Stock amortization and vesting

—

Common stock repurchases

—

()

—

()

Common stock retirements

()

—

Cash dividends on common stock at $ per share

—

()

Balance at June 30, 2024

The accompanying notes are an integral part of these condensed consolidated financial statements.

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COTERRA ENERGY INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

Significant Accounting Policies

reportable operating segment, oil and natural gas development, exploration and production. Refer to Note 1 of the Notes to the Consolidated Financial Statements in the Form 10-K for further information.

billion, which included $ billion in cash and the issuance of shares of the Company’s common stock valued at $ million based on the closing price of the Company’s common stock on the closing date.

Preliminary Purchase Price Allocation

The transaction was accounted for using the acquisition method of accounting. Under the acquisition method of accounting, the assets and liabilities of the FME Interests were recorded at their respective fair values as of the effective closing date of the acquisition. The purchase price allocation is substantially complete; however, management continues to refine the preliminary valuation of certain assets acquired and liabilities assumed, and may adjust the allocation in subsequent periods. Determining the fair value of the assets and liabilities of the FME Interests requires judgment and certain assumptions to be made. The most significant fair value estimates relate to the valuation of the oil and gas properties and gathering and pipeline systems. Oil and gas properties and gathering and pipeline systems were valued using an income and market approach utilizing Level 3 inputs including internally generated production and development data and estimated price and cost estimates.

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Coterra common stock closing price on January 27, 2025$ Total value of Coterra common stock issued$

Cash consideration (1) (2)

Total consideration$ Assets acquired:Current assets$ Proved oil and gas properties Unproved oil and gas properties Gathering and pipeline systems Other assets Total assets acquired$ Liabilities assumed:Current liabilities$

Asset retirement obligations

Other liabilities Total liabilities assumed$ Net assets acquired$

________________________________________________________

(1)Cash consideration included the release of escrow funds in the amount of $ million. These funds were included in restricted cash in the Condensed Consolidated Balance Sheet as of December 31, 2024.

(2)As of June 30, 2025, cash consideration of $ million remains in escrow and is included in restricted cash and accounts payable on the Company’s Condensed Consolidated Balance Sheet.

FME Post-Acquisition Operating Results

Net income$

Avant Acquisition

On January 17, 2025, the Company closed on the acquisition of certain interests in oil and gas properties located in the Delaware Basin in New Mexico from certain privately owned sellers for total cash consideration of $ billion (the “Avant assets”).

Preliminary Purchase Price Allocation

The transaction was accounted for using the acquisition method of accounting. Under the acquisition method of accounting, the assets and liabilities acquired in the Avant assets acquisition were recorded at their respective fair values as of

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Asset retirement obligations

Other liabilities Total liabilities assumed$ Net assets acquired$

________________________________________________________

million. These funds were included in restricted cash in the Condensed Consolidated Balance Sheet as of December 31, 2024.

Avant Post-Acquisition Operating Results

Net income$

Combined Unaudited Pro Forma Financial Information

The results of operations of the FME Interests and Avant assets have been included in the Company’s condensed consolidated financial statements since the closing date of the acquisitions. The following supplemental pro forma financial information for the six months ended June 30, 2025 and 2024 have been prepared to give effect to the acquisitions of the FME Interests and the Avant assets as if they had occurred on January 1, 2024. The information below reflects pro forma adjustments based on available information and certain assumptions that the Company believes are factual and supportable. The pro forma results of operations do not include any cost savings or other synergies that may result from the acquisitions or any estimated costs that have been or will be incurred by the Company to integrate the FME Interests and Avant assets.

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$ $ Pro forma net income$ $ $

Other Information

million of transaction costs for the six months ended June 30, 2025. These costs are primarily related to integration costs, advisory and legal fees and are included in G&A expense in the condensed consolidated financial statements.

$ Unproved oil and gas properties Gathering and pipeline systems Land, buildings and other equipment Finance lease right-of-use asset Accumulated DD&A()() $ $

Capitalized Exploratory Well Costs

As of and for the six months ended June 30, 2025, the Company did not have any projects with exploratory well costs capitalized for a period of greater than after drilling.

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% senior notes due September 18, 2026$ $ Senior notes:

% senior notes due May 15, 2027

% senior notes due March 15, 2029

% senior notes due March 15, 2034

% senior notes due February 15, 2035

% senior notes due February 15, 2055

Term loan:Tranche A term loan due January 27, 2027 Tranche B term loan due January 17, 2028 Unamortized debt premium Unamortized debt discount()()Unamortized debt issuance costs()()

Long-term debt

$ $

As of June 30, 2025, the Company was in compliance with all financial covenants for its term loan, revolving credit agreement and % private placement senior notes.

Revolving Credit Agreement

During the first half of 2025, the Company borrowed and repaid $ million under its revolving credit agreement. The Company’s weighted-average interest rate for borrowings under the revolving credit agreement for the three and six months ended June 30, 2025 was percent. There were borrowings under the revolving credit agreement during the first half of 2024.

As of June 30, 2025, the Company had borrowings outstanding under its revolving credit agreement and unused commitments of $ billion.

Term Loan

In December 2024, the Company entered into a delayed draw term loan credit agreement with Toronto Dominion (Texas), LLC, as administrative agent, and certain other lenders and issuing banks (the “Term Loan”), which consists of a $ million Tranche A Term Loan and a $ million Tranche B Term Loan. In January 2025, the Company borrowed $ million under the Tranche A Term Loan to partially fund the FME Interests acquisition and $ million under the Tranche B Term Loan to partially fund the acquisition of the Avant assets. During the first half of 2025, the Company repaid $ million of the Tranche A Term Loan.

During the three and six months ended June 30, 2025, the weighted-average effective interest rate on the Company’s Term Loan was approximately percent. As of June 30, 2025, the effective interest rate on the Company’s Term Loan was approximately percent.

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$ $ $ $ $ $ $ $ $ $ WTI-NYMEX oil swaps $ $ $ $ $ WTI Midland oil basis swaps $ $ $ $ $



	2026
	Fourth Quarter			First Quarter			Second Quarter			Third Quarter			Fourth Quarter
NYMEX gas collars

		$			$			$			$			$
		$			$			$			$			$

Transco Leidy gas basis swaps

()		$	()

Transco Zone 6 Non-NY gas basis swaps

()		$	()

Waha gas basis swaps

()		$	()		$	()		$	()		$	()		$	()

$ $— $— Commodity contractsAccrued liabilities— — Commodity contractsOther assets — — Commodity contractsOther liabilities— — $ $ $ $

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$ Gross amounts offset in the condensed consolidated balance sheet()()Net amounts of assets presented in the condensed consolidated balance sheet Gross amounts of financial instruments not offset in the condensed consolidated balance sheet Net amount$ $ Derivative liabilities Gross amounts of recognized liabilities$ $ Gross amounts offset in the condensed consolidated balance sheet()()Net amounts of liabilities presented in the condensed consolidated balance sheet Gross amounts of financial instruments not offset in the condensed consolidated balance sheet Net amount$ $ $ $ $()Gas contracts Non-cash gain (loss) on derivative instruments Oil contracts () ()Gas contracts () () $ $()$ $()

$ $ $ Derivative instruments $ $ $ $ Liabilities Deferred compensation plan$ $ $ $ Derivative instruments $ $ $ $

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$ $ $ Derivative instruments $ $ $ $ Liabilities Deferred compensation plan$ $ $ $ Derivative instruments $ $ $ $

The Company’s investments associated with its deferred compensation plans consist of mutual funds that are publicly traded and for which market prices are readily available.

The derivative instruments were measured based on quotes from the Company’s third-party valuation service provider and the Company’s counterparties. Such quotes have been derived using an income approach that considers various inputs, including current market and contractual prices for the underlying instruments, quoted forward commodity prices, basis differentials, volatility factors and interest rates for a similar length of time as the derivative contract term as applicable. Estimates are derived from or verified using relevant NYMEX futures contracts and are compared to multiple quotes obtained from counterparties or third-party valuation services, or a combination of the foregoing. The determination of the fair values presented above also incorporates a credit adjustment for non-performance risk. The Company measured the non-performance risk of its counterparties by reviewing credit default swap spreads for the various financial institutions with which it has derivative contracts while non-performance risk of the Company is evaluated using credit default swap spreads for various similarly rated companies in the same sector as the Company. The Company has not incurred any losses related to non-performance risk of its counterparties and does not anticipate any material impact on its financial results due to non-performance by third parties.

The most significant unobservable inputs relative to the Company’s Level 3 derivative contracts are basis differentials, discount rates and volatility factors. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in the models provided by third-party valuation service providers or its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided.

)$ Total gain (loss) included in earnings ()Settlement gain()()Balance at end of period$ $ Change in unrealized gains (losses) relating to assets and liabilities still held at the end of the period$ $()

Non-Financial Assets and Liabilities

The Company discloses or recognizes its non-financial assets and liabilities, such as impairments of oil and gas properties or acquisitions, at fair value on a nonrecurring basis. In January 2025, the Company completed the FME and Avant acquisitions and recorded the assets acquired and liabilities assumed at fair value. The most significant fair value determinations for non-financial assets and liabilities are related to acquired oil and gas properties and gathering and pipeline systems. Refer to Note 2 of the Notes to the Condensed Consolidated Financial Statements in this report for additional information. As of the Company’s other non-financial assets and liabilities were measured at fair value as of June 30, 2025, additional disclosures were not required.

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$ $ $

$ Liabilities incurred Liabilities settled ()Liabilities assumed in acquisitions
________________________________________________________

(1) Increases to the Company’s base dividends were previously approved by the Company’s Board of Directors in the February meeting of the respective year presented.

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million shares for $ million and million shares for $ million, respectively. As of June 30, 2025, the Company had $ billion remaining under its current share repurchase program.

12.

$ $ $ Restricted stock awards Performance share awards Total stock-based compensation expense$ $ $ $ Income tax benefit$ $ $ $

Refer to Note 13 of the Notes to the Consolidated Financial Statements in the Form 10-K for further description of the various types of stock-based compensation awards and the applicable award terms.

Restricted Stock Units - Employees

During the six months ended June 30, 2025, the Company granted restricted stock units to employees of the Company with a weighted average grant date value of $ per unit. The fair value of restricted stock unit grants is based on the closing stock price on the grant date. Restricted stock units generally vest at the end of a service period. The Company assumed a to percent annual forfeiture rate for purposes of recognizing stock-based compensation expense for awards granted in 2025 based on the Company’s actual forfeiture history and expectations for this type of award.

During the six months ended June 30, 2025, restricted stock units granted in 2022 vested. The weighted average grant date value was $ per unit.

Restricted Stock Units - Non-Employees Directors

During the six months ended June 30, 2025, the Company granted restricted stock units, with a weighted-average grant date value of $ per unit, to the Company’s non-employee directors. The fair value of these units is measured based on the closing stock price on grant date. These units will vest on the earlier of April 2026 or upon the director’s separation from the Company. Accordingly, the Company recognized this compensation expense immediately.

During the six months ended June 30, 2025, restricted stock units granted in 2024 were issued to the Company’s non-employee directors and restricted stock units granted and vested in periods from 2016 through 2021 were issued upon the retirement of certain non-employee directors following the Company’s 2025 annual meeting of stockholders. The weighted average grant date value was $ per unit for all awards issued in 2025.

Performance Share Awards

Total Shareholder Return (“TSR”) Performance Share Awards. During the six months ended June 30, 2025, the Company granted TSR Performance Share Awards, which are earned or not earned, based on the comparative performance of the Company’s common stock measured against a predetermined group of companies in the Company’s peer group and certain industry-related indices over a performance period, which commenced on February 1, 2025 and ends on January 31, 2028.

These awards have both an equity and liability component, with the right to receive up to the first percent of the award in shares of common stock and the right to receive up to an additional percent of the value of the award in excess of the equity component in cash. These awards also include a feature that will reduce the potential cash component of the award if the actual performance is negative over the period and the base calculation indicates an above-target payout. The equity portion of these awards is valued on the grant date and is not marked-to-market, while the liability portion of the awards

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percent annual forfeiture rate for purposes of recognizing stock-based compensation expense for these awards based on the Company’s actual forfeiture history and expectations for this type of award.

$ - $

Assumptions: Stock price volatility %

% - %

Risk-free rate of return %

% - %

The stock price volatility was calculated using historical closing stock price data for the Company for the period associated with the expected term through the grant date of each award. The risk-free rate of return percentages are based on the continuously compounded equivalent of the U.S. Treasury within the expected term as measured on the grant date.

In January 2025, the performance period ended for the TSR Performance Share Awards that were granted in 2022, and shares with a grant date fair value of $ million vested based on the Company’s ranking relative to a predetermined peer group. Cash payments associated with these awards of approximately $ million were also made in February 2025. The calculation of the award payout was certified by the Compensation Committee of the Board of Directors on February 10, 2025.

13.

$ $ $ Less: dividends attributable to participating securities () ()Net income available to common stockholders$ $ $ $ Shares (Denominator)Weighted average shares - Basic Dilution effect of stock awards at end of period Weighted average shares - Diluted Earnings per shareBasic$ $ $ $ Diluted$ $ $ $

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14.

$ Reductions related to severance payments()()Balance at end of period$ $

15.

$ Joint interest accounts Other accounts Allowance for credit losses()()$ $ Inventories Tubular goods and well equipment $ $ Commodity inventory $ $ Other current assets Prepaid balances$ $ Derivative instruments Other accounts $ $ Other assets Deferred compensation plan $ $ Debt issuance costs Operating lease right-of-use assets Derivative instruments Other accounts $ $

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$ Royalty and other owners Accrued gathering, processing and transportation Accrued capital costs Taxes other than income Accrued lease operating costs Other accounts $ $ Accrued liabilitiesEmployee benefits $ $ Taxes other than income Restructuring liabilities Derivative instruments Operating lease liabilities Financing lease liabilities Other accounts $ $ Other liabilitiesDeferred compensation plan $ $ Postretirement benefits Derivative instruments Operating lease liabilities Other accounts $ $

16.

$ $ $ Debt (premium) discount amortization, net()()()()Debt issuance cost amortization Other $ $ $ $

17.

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ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following review of operations of Coterra Energy Inc. (“Coterra,” the “Company,” “our,” “we” and “us”) for the three and six month periods ended June 30, 2025 and 2024 should be read in conjunction with our Condensed Consolidated Financial Statements and the Notes included in this Quarterly Report on Form 10-Q (this “Form 10-Q”) and with the Consolidated Financial Statements, Notes and Management’s Discussion and Analysis included in our Annual Report on Form 10-K for the year ended December 31, 2024 filed on February 25, 2025 (our “Form 10-K”).

For the abbreviations and definitions of certain terms commonly used in the oil and gas industry, please see the “Glossary of Certain Oil and Gas Terms” included within our Form 10-K.

OVERVIEW

Financial and Operating Overview

Financial and operating results for the six months ended June 30, 2025 compared to the six months ended June 30, 2024 reflect the following:

•Net income increased $455 million from $572 million, or $0.77 per share, in 2024 to $1.0 billion, or $1.35 per share, in 2025.

•Net cash provided by operating activities increased $666 million, from $1.4 billion in 2024 to $2.1 billion in 2025.

•Equivalent production increased 15.2 MMBoe from 123.3 MMBoe, or 677.7 MBoe per day, in 2024 to 138.5 MMBoe, or 765.4 MBoe per day, in 2025.

◦Oil production increased 7.8 MMBbl from 19.1 MMBbl, or 104.9 MBbl per day, in 2024 to 26.9 MMBbl, or 148.4 MBbl per day, in 2025.

◦Natural gas production increased 24.5 Bcf from 522.3 Bcf, or 2,869.9 MMcf per day, in 2024 to 546.8 Bcf, or 3,021.1 MMcf per day, in 2025.

◦NGL volumes increased 3.4 MMBbl from 17.2 MMBbl, or 94.5 MBbl per day, in 2024 to 20.6 MMBbl, or 113.6 MBbl per day, in 2025.

•Average realized prices (including impact of derivatives):

◦Oil was $66.52 per Bbl in 2025, 14 percent lower than the $77.25 per Bbl realized in 2024.

◦Natural gas was $2.74 per Mcf in 2025, 56 percent higher than the $1.76 per Mcf realized in 2024.

◦NGL price was $20.66 per Bbl in 2025, two percent higher than the $20.28 per Bbl realized in 2024.

•Total capital expenditures for drilling, completion and other fixed assets were $1.1 billion in 2025 compared to $927 million in the corresponding period of the prior year.

Other financial highlights for the six months ended June 30, 2025 include the following:

•Closed two acquisitions in January 2025 in the Delaware Basin in New Mexico for total consideration of $3.3 billion in cash and the issuance of 28,190,682 shares of our common stock valued at $785 million based on the closing price of our common stock on the closing date of the transactions.

•Increased our quarterly base dividend from $0.21 per share to $0.22 per share in February 2025.

•Repaid $350 million of the Tranche A Term Loan.

•Repurchased 2 million shares for $47 million.

Market Conditions and Commodity Prices

Our financial results depend on many factors, particularly commodity prices and our ability to find and develop oil and gas reserves and market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which can be impacted by pipeline capacity constraints, inventory storage levels, basis differentials, weather conditions, and geopolitical, economic and other factors.

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While oil prices were relatively steady throughout 2024, prices have declined in the first half of 2025, with the largest decline occurring in April 2025 in both spot and forward pricing. Global oil demand continues to be projected by some, including the International Energy Agency, to be adversely impacted by escalating trade tensions as a result of U.S. economic policy, including tariffs and retaliatory tariffs. However, these forecasts are subject to volatile market conditions, including ongoing shifts in U.S. and international trade policy, as well as geopolitical risk and uncertainty, including political and military disputes. OPEC+ previously announced both production cuts and increased production quotas. The impacts of these changes remain to be seen.

Natural gas prices, which rose in early 2025, have continued to trend downward through the second quarter, driven in part by warmer-than-expected temperatures and record high domestic production. Additionally, shifting U.S. and international trade policy and related uncertainty, including potential retaliatory tariffs on U.S. exports of LNG, have contributed to ongoing volatility in natural gas pricing. Meanwhile, basis differentials have persisted in the U.S., with prices at the Waha Hub in the Permian Basin particularly depressed due to oversupply. Prices turned negative in March 2025 before rebounding in April 2025, but remained volatile through the second quarter. Despite these headwinds, we continue to expect natural gas prices overall to be stronger in 2025 compared to 2024.

In recent months, the potential for increasing tariffs has remained a contributing factor to increased volatility in commodity markets and uncertainty in the general economic outlook. Higher tariffs could result in increased costs of materials used in our operations, less ready access to capital markets or less favorable general economic conditions. The uncertainty surrounding tariff policies has led to fluctuations in commodity prices which could impact our ability to forecast future results. We are continuing to monitor developments related to tariff policies.

Although the current outlook on oil and natural gas prices is generally favorable, and our operations have not been significantly impacted in the short-term, in the event further disruptions occur or the current market volatility and U.S. and international economic policy uncertainty continues for an extended period of time, our operations could be adversely impacted, commodity prices could decline and our costs may increase. We expect commodity price volatility to continue, including as a result of U.S. and international economic policy (such as tariffs or retaliatory tariffs), actions of OPEC+ (including the ability of OPEC+ to successfully coordinate production quotas) and potentially swift near- and medium-term fluctuations in supply and demand, such as potential changes to drilling and capital programs in the short term by U.S. producers. While we are unable to predict future commodity prices, at current oil, natural gas and NGL price levels, we do not believe that an impairment of our oil and gas properties is reasonably likely to occur in the near future. However, in the event that commodity prices significantly decline or costs significantly increase from current levels, our management would evaluate the recoverability of the carrying value of our oil and gas properties.

In addition, some governments, companies, communities and other stakeholders are supporting efforts to address climate change. As a result, such efforts have resulted in both existing and pending legislation and regulatory measures (including at the state, national and international level). Significant uncertainty remains as to the proposed changes in these laws or regulations, which, if adopted, may result in delays or restrictions in permitting and the development of our projects, increases to our costs, impair our ability to move forward with our construction, completions, drilling, water management, waste handling, storage, transport and remediation activities, or more competitive renewable energy alternatives that are able to more effectively compete with traditional oil and natural gas-derived products (including government subsidies and incentives for electric vehicles), any of which could have an adverse effect on our financial results.

For information about the impact of realized commodity prices on our revenues, refer to “Results of Operations” below.

Recent U.S. Tax Legislation

On July 4, 2025, the U.S. enacted significant tax legislation under H.R. 1, the One Big Beautiful Bill Act (“OBBB”). As this legislation was enacted after June 30, 2025, its effects are not reflected in our provision for income taxes as of that date. We are currently evaluating the impact of the new legislation. While the enactment of the OBBB is not expected to result in a material change to our total income tax expense, it is expected to have a material impact on the allocation between current and deferred taxes. Specifically, the reinstatement of 100 percent bonus depreciation and immediate expensing of domestic research and development costs are expected to significantly reduce current tax expense, with a corresponding increase in deferred tax expense, beginning in future reporting periods.

Outlook

Our 2025 full-year capital program is expected to be near the high end of the $2.1 billion to $2.3 billion range. We expect to fund these capital expenditures with our operating cash flow. We expect to turn-in-line 175 to 205 total net wells in 2025 across our three operating regions. We expect to invest approximately 66 percent of our capital expenditures in the Permian

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Basin, 15 percent in the Marcellus Shale, 10 percent in the Anadarko Basin and the remaining nine percent for gathering systems infrastructure, saltwater disposal and other capital expenditures.

In 2024, we drilled 313 gross wells (159.4 net) and turned-in-line 294 gross wells (153.0 net). For the six months ended June 30, 2025, our capital program focused on the Permian Basin, Marcellus Shale and Anadarko Basin, where we drilled 99.0 net wells and turned in line 98.8 net wells. Our capital program for the remainder of 2025 will focus on execution of our 2025 plan presented in our annual guidance. In the normal course of our business, we will continue to assess the oil and natural gas price macro environments and may adjust our capital allocation accordingly.

FINANCIAL CONDITION

Liquidity and Capital Resources

We strive to maintain an adequate liquidity level to address commodity price volatility and risk. Our liquidity requirements consist primarily of our planned capital expenditures (including acquisitions), payment of contractual obligations (including debt maturities and interest payments), working capital requirements, dividend payments and share repurchases. Although we have no obligation to do so, we may also from time-to-time refinance or retire our outstanding debt through privately negotiated transactions, open market repurchases, redemptions, exchanges, tender offers or otherwise.

Our primary sources of liquidity are cash on hand, net cash provided by operating activities and available borrowing capacity under our revolving credit agreement. Our liquidity requirements are generally funded with cash flows provided by operating activities, together with cash on hand. However, from time-to-time, our investments may be funded by bank borrowings (including draws on our revolving credit agreement), sales of assets, and private or public financing based on our monitoring of capital markets and our balance sheet. While there are no “rating triggers” in any of our debt agreements that would accelerate the scheduled maturities should our credit rating fall below a certain level, a change in our credit rating could adversely impact our interest rate on any borrowings under our revolving credit agreement and our ability to economically access debt markets and could trigger the requirement to post credit support under various agreements, which could reduce the borrowing capacity under our revolving credit agreement. As of the date hereof, our debt is currently rated as investment grade by the three leading ratings agencies. For more on the impact of credit ratings on our interest rates and fees for unused commitments under our revolving credit agreement, see Note 4 of the Notes to the Consolidated Financial Statements in our Form 10-K. We believe that, with operating cash flow, cash on hand and availability under our revolving credit agreement, we have the ability to finance our spending plans over the next 12 months and, based on current expectations, for the longer term.

Our working capital is substantially influenced by the variables discussed above and fluctuates based on the timing and amount of borrowings and repayments under our revolving credit agreement, borrowings and repayments of debt, the timing of cash collections and payments on our trade accounts receivable and payable, respectively, payment of dividends, repurchases of our securities and changes in the fair value of our commodity derivative activity. From time-to-time, our working capital will reflect a deficit, while at other times it will reflect a surplus. This fluctuation is not unusual. As of June 30, 2025, our working capital surplus of $170 million was lower than prior year, primarily due to a lower cash position as a result of funding the purchase price of the FME and Avant acquisitions that closed in January 2025 and the partial repayment of our term loan in the first half of 2025. As of December 31, 2024, we had a working capital surplus of $2.2 billion. We believe we have adequate liquidity and availability under our revolving credit agreement as outlined above to meet our working capital requirements over the next 12 months.

As of June 30, 2025, we had no borrowings outstanding under our revolving credit agreement, our unused commitments were $2.0 billion, and we had unrestricted cash on hand of $192 million.

Our revolving credit agreement and term loan include a covenant potentially limiting our borrowing capacity as determined by our leverage ratio. As of June 30, 2025, we were in compliance with all financial covenants applicable to our revolving credit agreement, term loan and private placement senior notes. Refer to Note 4 of the Notes to the Condensed Consolidated Financial Statements in this report and Note 4 of the Notes to the Consolidated Financial Statements in our Form 10-K for further details.

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Cash Flows

Our cash flows from operating activities, investing activities and financing activities were as follows:


	Six Months Ended June 30,				Variance
(In millions)	2025		2024		Amount		Percent
Cash flows provided by operating activities	$	2,080	$	1,414	$	666	47	%
Cash flows used in investing activities	(4,370)		(1,188)		(3,182)		268	%
Cash flows provided by (used in) financing activities	229		(112)		341		304	%
Net (decrease) increase in cash, cash equivalents and restricted cash	$	(2,061)	$	114	$	(2,175)	(1,908)	%

Operating Activities. Operating cash flow fluctuations are substantially driven by changes in commodity prices, production volumes and operating expenses. As discussed above, commodity prices have historically been volatile. Fluctuations in cash flow may result in an increase or decrease in our planned capital expenditures.

Net cash provided by operating activities for the six months ended June 30, 2025 increased by $666 million compared to the same period in 2024. This increase was primarily due to higher oil, natural gas and NGL revenues driven by significantly higher natural gas prices and by higher production from our FME and Avant acquisitions that closed in January 2025 and our legacy properties in the Permian and Anadarko Basins. These increases were partially offset by an increase in operating costs largely due to our FME and Avant acquisitions and a decrease in cash received on derivative settlements during the first six months of 2025 compared to 2024.

Refer to “Results of Operations” below for additional information relative to commodity prices, production and operating expense fluctuations. We are unable to predict future commodity prices and, as a result, cannot provide any assurance about future levels of net cash provided by operating activities.

Investing Activities. Cash flows used in investing activities increased by $3.2 billion for the six months ended June 30, 2025 compared to the six months ended June 30, 2024. This increase was primarily due to $3.2 billion of cash consideration paid for business combinations and $210 million higher cash paid for capital expenditures, partially offset by a decrease of $250 million of purchases of short-term investments in 2025 compared to 2024.

Financing Activities. Cash flows provided by financing activities increased by $341 million for the six months ended June 30, 2025 compared to the six months ended June 30, 2024. The increase was due to $851 million higher proceeds from issuance of debt due to the funding of our term loan in 2025 and borrowings under our revolver, and $243 million lower common stock repurchases. These increases were partially offset by $700 million higher debt repayments related to the $350 million repayment of our term loan and the $350 million repayment of borrowings under our revolver during 2025, $32 million of higher dividend payments, and $24 million of higher tax withholding on vesting of stock awards in 2025 compared to 2024.

Capitalization

Information about our capitalization is as follows:


(Dollars in millions)	June 30, 2025			December 31, 2024
Long-term debt (1)	$	4,175		$	3,535
Stockholders’ equity	14,556			13,122
Total capitalization	$	18,731		$	16,657
Debt to total capitalization	22		%	21		%
Cash and cash equivalents	$	192		$	2,038

318

Capital and Exploration Expenditures

On an annual basis, we generally fund most of our capital expenditures, excluding any significant property acquisitions, with cash flow provided by operating activities, and, if required, borrowings under our revolving credit agreement. We budget these expenditures based on our projected cash flows for the year.

The following table presents major components of our capital and exploration expenditures:


	Six Months Ended June 30,
(In millions)	2025		2024
Acquisitions
Proved oil and gas properties	$	2,473	$	—
Unproved oil and gas properties	1,286		—
Gathering and pipeline systems	333		—
	$	4,092	$	—

Capital expenditures:
Drilling and facilities	$	1,044	$	864

Pipeline and gathering	63		54
Other	14		9

Capital expenditures for drilling, completion and other fixed asset additions	1,121		927
Capital expenditures for leasehold and property acquisitions	57		3
Exploration expenditures (1)	14		10
	$	1,192	$	940

________________________________________________________

(1)There were no exploratory dry hole costs for the six months ended June 30, 2025 and 2024.

For the six months ended June 30, 2025, our capital program focused on the Permian Basin, Marcellus Shale and Anadarko Basin, where we drilled 99.0 net wells and turned-in-line 98.8 net wells. We expect that our full-year 2025 capital program will be near the high end of the $2.1 billion to $2.3 billion range. Refer to “Outlook” above for additional information regarding the current year drilling program. We will continue to assess the commodity price environment and may adjust our capital expenditures accordingly.

Contractual Obligations

We have various contractual obligations in the normal course of our operations. There have been no material changes to our contractual obligations described under “Gathering, Processing and Transportation Agreements” and “Lease Commitments” as disclosed in Note 8 of the Notes to the Consolidated Financial Statements and the obligations described under “Contractual

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Obligations” in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Form 10-K.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based on our Condensed Consolidated Financial Statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Refer to our Form 10-K for further discussion of our critical accounting policies.

Purchase Accounting

From time-to-time, we may acquire assets and assume liabilities in transactions accounted for as business combinations, such as the FME and Avant acquisitions. In connection with the FME and Avant acquisitions, we allocated the purchase price consideration to the assets acquired and liabilities assumed based on estimated fair values as of the closing dates of the respective acquisition.

We made a number of assumptions in estimating the fair value of assets acquired and liabilities assumed in the FME and Avant acquisitions. The most significant assumptions related to the fair value estimates of proved and unproved oil and gas properties, which were recorded at a total fair value of $3.8 billion. Since sufficient market data was not available regarding the fair values of the acquired proved and unproved oil and gas properties, we prepared our estimates using discounted cash flows and engaged third-party valuation experts. Significant judgments and assumptions are inherent in these estimates and include, among other things, estimates of reserve quantities and production volumes, future commodity prices and price differentials, expected development costs, lease operating costs, reserve risk adjustment factors and an estimate of an applicable market participant discount rate that reflects the risk of the underlying cash flow estimates.

Estimated fair values assigned to assets acquired can have a significant impact on future results of operations, as presented in our financial statements. Fair values are based on estimates of future commodity prices and price differentials, reserve quantities and production volumes, development costs and lease operating costs. In the event that future commodity prices or reserve quantities or production volumes are significantly lower than those used in the determination of fair value as of the closing dates of the acquisitions, the likelihood increases that certain costs may be determined to be unrecoverable.

In addition to the fair value of proved and unproved oil and gas properties, other significant fair value assessments for the assets acquired and liabilities assumed in the FME and Avant acquisitions relate to gathering and pipeline systems. We prepared estimates and engaged third-party valuation experts to assist in the valuation of certain other assets, which required significant judgments and assumptions inherent in the estimates and included projected cash flows and comparable companies’ cash flow multiples.

RESULTS OF OPERATIONS

Second Quarters of 2025 and 2024 Compared

Operating Revenues


	Three Months Ended June 30,				Variance
(In millions)	2025		2024		Amount		Percent
Operating Revenues
Oil	$	888	$	774	$	114	15	%
Natural gas	601		319		282		88	%
NGL	219		176		43		24	%
Gain (loss) on derivative instruments	232		(16)		248		1,550	%
Other	25		18		7		39	%
	$	1,965	$	1,271	$	694	55	%

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Production Revenues

Our production revenues are derived from sales of our oil, natural gas and NGL production. Increases or decreases in our revenues, profitability and future production growth are highly dependent on the commodity prices we receive, which, as discussed above, fluctuate due to a variety of factors, including supply and demand, the availability of transportation, seasonality and geopolitical, economic and other factors.

Production and Sales Price

The following table presents our total and average daily production volumes for oil, natural gas and NGLs, and our average oil, natural gas and NGL sales prices for the periods indicated.


	Three Months Ended June 30,				Variance
	2025		2024		Amount		Percent
Production Volumes
Oil (MMBbl)	14.1		9.8		4.3		44	%
Natural gas (Bcf)	272.9		253.0		19.9		8	%
NGL (MMBbl)	11.7		9.0		2.7		30	%
Equivalents (MMBoe)	71.3		60.9		10.4		17	%

Average Daily Production Volumes
Oil (MBbl)	155.4		107.2		48.2		45	%
Natural gas (MMcf)	2,998.6		2,779.8		218.8		8	%
NGL (MBbl)	128.7		98.8		29.9		30	%
Equivalents (MBoe)	783.9		669.2		114.7		17	%

Average Sales Price
Excluding Derivative Settlements
Oil ($/Bbl)	$	62.80	$	79.37	$	(16.57)	(21)	%
Natural gas ($/Mcf)	$	2.20	$	1.26	$	0.94	75	%
NGL ($/Bbl)	$	18.72	$	19.53	$	(0.81)	(4)	%
Including Derivative Settlements
Oil ($/Bbl)	$	64.01	$	79.39	$	(15.38)	(19)	%
Natural gas ($/Mcf)	$	2.27	$	1.40	$	0.87	62	%
NGL ($/Bbl)	$	18.72	$	19.53	$	(0.81)	(4)	%

Oil Revenues


	Three Months Ended June 30,				Variance				Increase (Decrease) (In millions)
	2025		2024		Amount		Percent
Volume (MMBbl)	14.1		9.8		4.3		44	%	$	348
Price ($/Bbl)	$	62.80	$	79.37	$	(16.57)	(21)	%	(234)
									$	114

Oil revenues increased $114 million due to higher production in the Permian Basin, partially offset by lower oil prices. Production increased due to the FME and Avant acquisitions in the Permian Basin that closed in January 2025 and higher production from our legacy properties.

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Natural Gas Revenues


	Three Months Ended June 30,				Variance				Increase (Decrease) (In millions)
	2025		2024		Amount		Percent
Volume (Bcf)	272.9		253.0		19.9		8	%	$	25
Price ($/Mcf)	$	2.20	$	1.26	$	0.94	75	%	257
									$	282

Natural gas revenues increased $282 million primarily due to significantly higher natural gas prices and higher production in the Permian and Anadarko Basins, partially offset by lower production in the Marcellus Shale. Production increased due to the FME and Avant acquisitions in the Permian Basin that closed in January 2025 and higher production from our legacy properties in the Permian and Anadarko Basins. The decrease in production in the Marcellus Shale was due to a decrease in drilling and completion activity in 2024, which resulted in a decline in production.

NGL Revenues


	Three Months Ended June 30,				Variance				Increase (Decrease) (In millions)
	2025		2024		Amount		Percent
Volume (MMBbl)	11.7		9.0		2.7		30	%	$	53
Price ($/Bbl)	$	18.72	$	19.53	$	(0.81)	(4)	%	(10)
									$	43

NGL revenues increased $43 million primarily due to higher NGL volumes in the Permian and Anadarko Basins, partially offset by lower prices.

Gain (loss) on Derivative Instruments

Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity index prices as compared to the contracted prices and the monthly cash settlements (if any) of the derivative instruments. We have elected not to designate our derivatives as hedging instruments for accounting purposes and, therefore, we do not apply hedge accounting treatment to our derivative instruments. Consequently, changes in the fair value of our derivative instruments and cash settlements are included as a component of operating revenues as either a net gain or loss on derivative instruments. Cash settlements of our contracts are included in cash flows from operating activities in our statement of cash flows.

The following table presents the components of “Gain (loss) on derivative instruments” for the periods indicated:


	Three Months Ended June 30,
(In millions)	2025		2024
Cash received on settlement of derivative instruments
Oil contracts	$	17	$	—
Gas contracts	18		36
Non-cash gain (loss) on derivative instruments
Oil contracts	83		(2)
Gas contracts	114		(50)
	$	232	$	(16)

Operating Costs and Expenses

Costs associated with producing oil and natural gas are substantial. Among other factors, some of these costs vary with commodity prices, some trend with the volume and commodity mix, some are a function of the number of wells we own and operate, some depend on the prices charged by service companies, and some fluctuate based on a combination of the foregoing. Our costs for services, labor and supplies had stabilized in 2024 despite on-going demand and latent effects of inflation and supply chain disruptions. In January 2025 with the completion of the FME and Avant acquisitions, we expanded our operations in the Permian Basin.

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The table below reflects our operating costs and expenses for the periods indicated, and a discussion of the operating costs and expenses follows.


	Three Months Ended June 30,				Variance				Per BOE
(In millions, except per BOE)	2025		2024		Amount		Percent		2025		2024
Operating Expenses
Direct operations	$	236	$	160	$	76	48	%	$	3.32	$	2.62
Gathering, processing and transportation	271		242		29		12	%	3.81		3.99
Taxes other than income	87		54		33		61	%	1.21		0.89
Exploration	4		5		(1)		(20)	%	0.07		0.09
Depreciation, depletion and amortization	579		447		132		30	%	8.11		7.34

General and administrative	84		68		16		24	%	1.18		1.12
	$	1,261	$	976	$	285	29	%	$	17.70	$	16.05

Direct Operations

Direct operations generally consist of costs for labor, equipment, maintenance, saltwater disposal, compression, power, treating and miscellaneous other costs (collectively, “lease operating expense”). Direct operations also include well workover activity necessary to maintain production from existing wells.

Direct operations expense consisted of lease operating expense and workover expense as follows:


	Three Months Ended June 30,						Per BOE
(In millions, except per BOE)	2025		2024		Variance		2025		2024
Direct Operations Expense
Lease operating expense	$	194	$	134	$	60	$	2.73	$	2.19
Workover expense	42		26		16		0.59		0.43
	$	236	$	160	$	76	$	3.32	$	2.62

Lease operating expense increased primarily due to higher production levels and higher costs in the Permian Basin driven in part by the FME and Avant acquisitions, which have higher lifting costs than our legacy wells.

Workover expense increased $16 million primarily due to increased expenses related to the FME and Avant acquisitions and higher workover activity in the Permian Basin, partially offset by a decrease in workover activity in the Marcellus Shale due to reduced activity in the basin.

Gathering, Processing and Transportation

Gathering, processing and transportation costs principally consist of expenditures to prepare and transport production downstream from the wellhead, including gathering, fuel, and compression, along with processing costs, which are incurred to extract NGLs from the raw natural gas stream. Gathering costs also include costs associated with operating our gas gathering infrastructure, including operating and maintenance expenses. Costs vary by operating area and will fluctuate with increases or decreases in production volumes, contractual fees, and changes in fuel and compression costs.

Gathering, processing and transportation costs increased $29 million primarily due to higher production due to the FME and Avant acquisitions in the Permian Basin that closed in January 2025 and higher production from our legacy properties in the Permian and Anadarko Basins.

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Taxes Other Than Income

Taxes other than income consist of production (or severance) taxes, drilling impact fees, ad valorem taxes and other taxes. State and local taxing authorities assess these taxes, with production taxes being based on the volume or value of production, drilling impact fees being based on drilling activities and prevailing natural gas prices and ad valorem taxes being based on the value of properties.

The following table presents taxes other than income for the periods indicated:


	Three Months Ended June 30,
(In millions)	2025			2024			Variance
Taxes Other than Income
Production	$	68		$	52		$	16
Drilling impact fees	6			2			4
Ad valorem	12			(1)			13
Other	1			1			—
	$	87		$	54		$	33
Production taxes as percentage of revenue (Permian and Anadarko Basins)	5.6		%	5.6		%

Taxes other than income increased primarily due to an increase in our production and ad valorem taxes. Production taxes increased primarily due to higher production due to the FME and Avant acquisitions in the Permian Basin that closed in January 2025 and higher production from our legacy properties in the Permian and Anadarko Basins. Ad valorem taxes increased due to a reduction in 2024 ad valorem tax expense related to an adjustment for estimated tax accruals that related to the full-year 2023.

Depreciation, Depletion and Amortization (“DD&A”)

DD&A expense consisted of the following for the periods indicated:


	Three Months Ended June 30,						Per BOE
(In millions, except per BOE)	2025		2024		Variance		2025		2024
DD&A Expense
Depletion	$	536	$	414	$	122	$	7.52	$	6.80
Depreciation	24		18		6		0.32		0.29
Amortization of unproved properties	15		12		3		0.22		0.20
Accretion of ARO	4		3		1		0.05		0.05
	$	579	$	447	$	132	$	8.11	$	7.34

Depletion of our producing properties is computed on a field basis using the units-of-production method under the successful efforts method of accounting. The economic life of each producing property depends upon the estimated proved reserves for that property, which in turn depend upon the assumed realized sales price for future production. Therefore, fluctuations in oil and natural gas prices will impact the level of proved developed and proved reserves used in the calculation. Higher prices generally have the effect of increasing reserves, which reduces depletion expense. Conversely, lower prices generally have the effect of decreasing reserves, which increases depletion expense. The cost of replacing production also impacts our depletion expense. In addition, changes in estimates of reserve quantities, estimates of operating and future development costs, reclassifications of properties from unproved to proved and impairments of oil and gas properties will impact depletion expense. Our depletion expense increased $122 million primarily due to a higher depletion rate and an increase in production. Our depletion rate increased primarily due to the increase in value of our oil and gas properties related to assets acquired from FME and Avant, which were recorded at fair value. The depletion rate also increased due to a shift in our production mix to fields with higher depletion rates and changes in our year-end reserves estimates

Fixed assets consist primarily of gas gathering facilities, water infrastructure, buildings, vehicles, aircraft, furniture and fixtures and computer equipment and software. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets, which range from three to 30 years. Also included in our depreciation expense is the depreciation of the right-of-use asset associated with our finance lease gathering system.

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Unproved properties are amortized based on our drilling experience and our expectation of converting our unproved leaseholds to proved properties. The rate of amortization depends on the timing and success of our exploration and development program. If development of unproved properties is deemed unsuccessful, and the properties are abandoned or surrendered, the capitalized costs are expensed in the period the determination is made.

General and Administrative (“G&A”)

G&A expense consists primarily of salaries and related benefits, stock-based compensation, office rent, legal and consulting fees, systems costs and other administrative costs incurred.

The table below reflects our G&A expense for the periods indicated:


		Three Months Ended June 30,
(In millions)		2025		2024		Variance
G&A Expense
General and administrative expense		$	70	$	52	$	18
Stock-based compensation expense		14		16		(2)

%	21.6	%

Income tax expense increased $86 million for the three months ended June 30, 2025 compared to the three months ended June 30, 2024 primarily due to higher pre-tax income and a higher effective tax rate. The effective tax rate increased due to differences in permanent book-to-tax adjustments and non-recurring discrete items recorded during the three months ended June 30, 2025 and 2024.

First Six Months of 2025 and 2024 Compared

Operating Revenues


	Six Months Ended June 30,				Variance
(In millions)	2025		2024		Amount		Percent
Oil	$	1,774	$	1,475	$	299	20	%
Natural gas	1,499		857		642		75	%
NGL	425		349		76		22	%
Gain (loss) on derivative instruments	120		(16)		136		850	%
Other	51		39		12		31	%
	$	3,869	$	2,704	$	1,165	43	%

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Production Revenues

Production and Sales Price

The following table presents our total and average daily production volumes for oil, natural gas and NGLs, and our average oil, natural gas and NGL sales prices for the periods indicated.


	Six Months Ended June 30,				Variance
	2025		2024		Amount		Percent
Production Volumes
Oil (MMBbl)	26.9		19.1		7.8		41	%
Natural gas (Bcf)	546.8		522.3		24.5		5	%
NGL (MMBbl)	20.6		17.2		3.4		20	%
Equivalents (MMBoe)	138.5		123.3		15.2		12	%

Average Daily Production Volumes
Oil (MBbl)	148.4		104.9		43.5		41	%
Natural gas (MMcf)	3,021.1		2,869.9		151.2		5	%
NGL (MBbl)	113.6		94.5		19.1		20	%
Equivalents (MBoe)	765.4		677.7		87.7		13	%

Average Sales Price
Excluding Derivative Settlements
Oil ($/Bbl)	$	66.08	$	77.31	$	(11.23)	(15)	%
Natural gas ($/Mcf)	$	2.74	$	1.64	$	1.10	67	%
NGL ($/Bbl)	$	20.66	$	20.28	$	0.38	2	%
Including Derivative Settlements
Oil ($/Bbl)	$	66.52	$	77.25	$	(10.73)	(14)	%
Natural gas ($/Mcf)	$	2.74	$	1.76	$	0.98	56	%
NGL ($/Bbl)	$	20.66	$	20.28	$	0.38	2	%

Oil Revenues


	Six Months Ended June 30,				Variance				Increase (Decrease) (In millions)
	2025		2024		Amount		Percent
Volume (MMBbl)	26.9		19.1		7.8		41	%	$	601
Price ($/Bbl)	$	66.08	$	77.31	$	(11.23)	(15)	%	(302)
									$	299

Oil revenues increased $299 million primarily due to higher production in the Permian and Anadarko Basins, partially offset by lower oil prices. Production increased due to the FME and Avant acquisitions in the Permian Basin that closed in January 2025 and higher production from our legacy properties.

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Natural Gas Revenues


	Six Months Ended June 30,				Variance				Increase (Decrease) (In millions)
	2025		2024		Amount		Percent
Volume (Bcf)	546.8		522.3		24.5		5	%	40
Price ($/Mcf)	$	2.74	$	1.64	$	1.10	67	%	602
									$	642

Natural gas revenues increased $642 million primarily due to significantly higher natural gas prices and higher production in the Permian and Anadarko Basins, partially offset by lower production in the Marcellus Shale. Production increased due to the FME and Avant acquisitions in the Permian Basin that closed in January 2025 and higher production from our legacy properties in the Permian and Anadarko Basins. The decrease in production in the Marcellus Shale was due to a decrease in drilling and completion activity in 2024 which resulted in a decline in production.

NGL Revenues


	Six Months Ended June 30,				Variance				Increase (Decrease) (In millions)
	2025		2024		Amount		Percent
Volume (MMBbl)	20.6		17.2		3.4		20	%	$	68
Price ($/Bbl)	$	20.66	$	20.28	$	0.38	2	%	8
									$	76

NGL revenues increased $76 million primarily due to higher volumes in the Permian and Anadarko Basins and slightly higher NGL prices.

Gain (loss) on Derivative Instruments

The following table presents the components of “Gain (loss) on derivative instruments” for the periods indicated:


	Six Months Ended June 30,
(In millions)	2025		2024
Cash received (paid) on settlement of derivative instruments
Oil contracts	$	12	$	(1)
Gas contracts	1		63
Non-cash gain (loss) on derivative instruments
Oil contracts	88		(35)
Gas contracts	19		(43)
	$	120	$	(16)

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Operating Costs and Expenses

The table below reflects our operating costs and expenses for the periods indicated, and a discussion of the operating costs and expenses follows:


	Six Months Ended June 30,				Variance				Per Boe
(In millions, except per Boe)	2025		2024		Amount		Percent		2025		2024
Operating Expenses
Direct operations	$	452	$	316	$	136	43	%	$	3.26	$	2.56
Gathering, processing and transportation	553		492		61		12	%	4.00		3.99
Taxes other than income	183		128		55		43	%	1.32		1.04
Exploration	14		10		4		40	%	0.10		0.08
Depreciation, depletion and amortization	1,085		879		206		23	%	7.83		7.12

General and administrative	176		143		33		23	%	1.27		1.16
	$	2,463	$	1,968	$	495	25	%	$	17.78	$	15.95

Direct Operations

Direct operations expense consisted of lease operating expense and workover expense as follows:


	Six Months Ended June 30,						Per Boe
(In millions, except per Boe)	2025		2024		Variance		2025		2024
Direct Operations
Lease operating expense	$	383	$	264	$	119	$	2.76	$	2.14
Workover expense	69		52		17		0.50		0.42
	$	452	$	316	$	136	$	3.26	$	2.56

Workover expense increased by $17 million primarily due to higher expense related to the FME and Avant acquisitions and higher workover activity in the Permian Basin, partially offset by lower activity in the Marcellus Shale due to reduced activity in the basin.

Gathering, Processing and Transportation

Gathering, processing and transportation costs increased $61 million, primarily due to higher production due to the FME and Avant acquisitions in the Permian Basin that closed in January 2025 and higher production from our legacy properties in the Permian and Anadarko Basins.

Taxes Other Than Income

The following table presents taxes other than income for the periods indicated:


	Six Months Ended June 30,
(In millions)	2025			2024			Variance
Taxes Other than Income
Production	$	147		$	106		$	41
Drilling impact fees	11			7			4
Ad valorem	24			16			8
Other	1			(1)			2
	$	183		$	128		$	55
Production taxes as percentage of revenue (Permian and Anadarko Basins)	5.9		%	5.6		%

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Taxes other than income increased $55 million primarily due to an increase in our production and ad valorem taxes. Production taxes increased primarily due to higher production due to the FME and Avant acquisitions in the Permian Basin that closed in January 2025 and higher production from our legacy properties in the Permian and Anadarko Basins. Ad valorem taxes increased due to a reduction in 2024 ad valorem tax expense related to an adjustment for estimated tax accruals related to the full-year 2023.

Depreciation, Depletion and Amortization (“DD&A”)

DD&A expense consisted of the following for the periods indicated:


	Six Months Ended June 30,						Per BOE
(In millions, except per Boe)	2025		2024		Variance		2025		2024
DD&A Expense
Depletion	$	1,003	$	813	$	190	$	7.24	$	6.59
Depreciation	47		36		11		0.35		0.29
Amortization of unproved properties	28		24		4		0.20		0.19
Accretion of ARO	7		6		1		0.04		0.05
	$	1,085	$	879	$	206	$	7.83	$	7.12

Our depletion expense increased $190 million primarily due to a higher depletion rate and an increase in production. Our depletion rate increased primarily due to the increase in value of our oil and gas properties related to assets acquired from FME and Avant, which were recorded at fair value. The depletion rate also increased due to a shift in our production mix to fields with higher depletion rates and changes in our year-end reserves estimates.

General and Administrative (“G&A”)

The table below reflects our G&A expense for the periods indicated:


	Six Months Ended June 30,
(In millions)	2025		2024		Variance
G&A Expense
General and administrative expense	$	146	$	114	$	32
Stock-based compensation expense	30		29		1

	$	176	$	143	$	33

G&A expense, excluding stock-based compensation expense, increased $32 million primarily due to acquisition and transition costs associated with the FME and Avant acquisitions completed in January 2025, increased employee-related costs and higher legal and professional fees, partially offset by the recognition of certain long-term commitments for community outreach and charitable contributions that were accrued in 2024.

Stock-based compensation expense will fluctuate based on the grant date fair value of awards, the number of awards, the requisite service period of the awards, estimated employee forfeitures, and the timing of the awards.

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Interest Expense

The table below reflects our interest expense for the periods indicated:


	Six Months Ended June 30,
(In millions)	2025		2024		Variance
Interest Expense
Interest expense	$	109	$	49	$	60
Debt premium and discount amortization, net	(11)		(11)		—
Debt issuance cost amortization	3		2		1
Other	5		13		(8)
	$	106	$	53	$	53

																	2026	Fair Value Asset (Liability) (In millions)	Fourth Quarter	First Quarter	Second Quarter	Third Quarter	Fourth Quarter




(23)
	87,400,000			81,000,000			54,600,000			55,200,000			55,200,000
3.08		$	3.08		$	3.06		$	3.21		$	3.21		$	3.21
4.88		$	5.66		$	6.39		$	5.76		$	5.76		$	5.76


	18,400,000			—			—			—			—
(0.70)		$	(0.70)		—			—			—			—


	18,400,000			—			—			—			—
(0.49)		$	(0.49)		—			—			—			—

Waha gas basis swaps
	13,800,000			13,500,000			13,650,000			13,800,000			13,800,000			(3)
(2.05)		$	(2.05)		$	(1.86)		$	(1.86)		$	(1.86)		$	(1.86)

A significant portion of our expected oil and natural gas production for the remainder of 2025 and beyond is currently unhedged and directly exposed to the volatility in oil and natural gas prices, whether favorable or unfavorable.

During the six months ended June 30, 2025, oil collars with floor prices ranging from $55.00 to $65.00 per Bbl and ceiling prices ranging from $69.55 to $86.02 per Bbl covered 10.1 MMBbls, or 38 percent, of our oil production at a weighted-average price of $66.95 per Bbl. Oil swaps covered 3.4 MMBbls, or 13 percent, of our oil production at a weighted-average price of $69.18 per Bbl. Oil basis swaps covered 12.7 MMBbls, or 47 percent, of our oil production at a weighted-average differential of $1.07 per Bbl.

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During the six months ended June 30, 2025, natural gas collars with floor prices ranging from $2.75 to $3.50 per MMBtu and ceiling prices ranging from $3.40 to $7.00 per MMBtu covered 135.1 Mcf, or 25 percent of our natural gas production at a weighted-average price of $3.55 per MMBtu. Gas basis swaps covered 73.5 Bcf, or 13 percent of natural gas production at a weighted-average differential of $(0.76) per MMBtu.

We are exposed to market risk on financial commodity derivative instruments to the extent of changes in market prices of the related commodity. However, the market risk exposure on these derivative contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity. Although notional contract amounts are used to express the volume of oil and natural gas agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. Our counterparties are primarily commercial banks and financial service institutions that our management believes present minimal credit risk, and our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. We perform both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. We have not incurred any losses related to non-performance risk of our counterparties, and we do not anticipate any material impact on our financial results due to non-performance by third parties. However, we cannot be certain that we will not experience such losses in the future.

Interest Rate Risk

As of June 30, 2025, we had total long-term debt of $4.2 billion. Our portfolio of long-term debt includes floating rate debt and fixed-rate instruments. Our revolving credit agreement and term loan borrowings are floating rate debt instruments, which exposes us to the risk of earnings or cash flow losses as the result of potential increases in market interest rates.

There are no “rating triggers” in any of our debt agreements that would accelerate the scheduled maturities. Should our credit rating fall below a certain level, a change in our credit rating could adversely impact our interest rate on any borrowings under our revolving credit agreement and term loan. As of the date hereof, our debt is currently rated as investment grade by the three leading ratings agencies. For more on the impact of credit ratings on our interest rates, see Note 4 of the Notes to the Consolidated Financial Statements in our Form 10-K.

As of June 30, 2025, we had no outstanding balance under our revolving credit agreement and $650 million outstanding borrowings under our term loan. Assuming no change in the amount of floating rate debt outstanding, a hypothetical 100 basis point increase in the average interest rate under our term loan borrowings would have increased our annual interest expense by approximately $3 million. Actual results may vary due to changes in the amount of floating rate debt outstanding.

As of June 30, 2025, we had $3.5 billion outstanding borrowings under fixed-rate debt instruments, which do not carry significant exposure to movements in market interest rates.

Fair Value of Other Financial Instruments

The estimated fair value of other financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Condensed Consolidated Balance Sheet for cash, cash equivalents and restricted cash approximate fair value due to the short-term maturities of these instruments.

The fair value of our senior notes is based on quoted market prices. The fair value of our private placement senior notes is based on third-party quotes which are derived from credit spreads for the difference between the issue rate and the period end market rate and other unobservable inputs. The fair value of the borrowing under our term loan approximates the carrying value as the interest rates are variable and reflective of market rates.

The carrying amount and estimated fair value of debt are as follows:


	June 30, 2025				December 31, 2024
(In millions)	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Long-term debt	$	4,175	$	4,057	$	3,535	$	3,395

ITEM 4. Controls and Procedures

As of June 30, 2025, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective to provide

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reasonable assurance with respect to the recording, processing, summarizing and reporting, within the time periods specified in the SEC’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.

During the quarter ended June 30, 2025, the Company integrated the controls and related procedures of the FME and Avant acquisitions into its internal control over financial reporting and they are now included in the Company’s assessment of the effectiveness of the Company’s internal control over financial reporting.

Other than incorporating the controls and related procedures of the acquired businesses, there were no changes in the Company’s internal control over financial reporting that occurred during the second quarter of 2025 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings

Legal Matters

The information set forth under the heading “Legal Matters” in Note 8 of the Notes to Condensed Consolidated Financial Statements included in this Form 10-Q is incorporated by reference in response to this item.

Governmental Proceedings

From time-to-time, we receive notices of violation from governmental and regulatory authorities, including notices relating to alleged violations of environmental statutes or the rules and regulations promulgated thereunder. While we cannot predict with certainty whether these notices of violation will result in fines, penalties or both, if fines or penalties are imposed, they may result in monetary sanctions, individually or in the aggregate, in excess of $300,000.

In June 2023, we received a Notice of Violation and Opportunity to Confer (“NOVOC”) from the U.S. Environmental Protection Agency (“EPA”) alleging violations of the Clean Air Act, the Texas State Implementation Plan, the New Mexico State Implementation Plan (“NMSIP”) and certain other state and federal regulations pertaining to Company facilities in Texas and New Mexico. Separately, in July 2023, we received a letter from the U.S. Department of Justice that the EPA has referred this NOVOC for civil enforcement proceedings. In August 2023, we received a second NOVOC from the EPA alleging violations of the Clean Air Act, the NMSIP, and certain other state and federal regulations pertaining to Company facilities in New Mexico. We have exchanged information with the EPA and continue to engage in discussions aimed at resolving the allegations. At this time we are unable to predict with certainty the financial impact of these NOVOCs or the timing of any resolution. However, any enforcement action related to these NOVOCs will likely result in fines or penalties, or both, and corrective actions, which may increase our development costs and operating costs. We believe that any fines, penalties, or corrective actions that may result from these matters will not have a material effect on our financial position, results of operations, or cash flows.

ITEM 1A. Risk Factors

For additional information about the risk factors that affect us, see Item 1A of Part I of our Form 10-K.

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

Share repurchase activity during the quarter ended June 30, 2025 was as follows:


Period	Total Number of Shares Purchased (In thousands)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (In thousands) (1)	Maximum Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs (In millions)
April 2025	524	$	24.67	524	$	1,088
May 2025	405	$	24.66	405	$	1,078
June 2025	—	$	—	—	$	1,078
	929			929

_______________________________________________________________________________

(1) All purchases during the covered periods were made under the share repurchase program, which was approved by our Board of Directors in February 2023 and which authorized the repurchase of up to $2.0 billion of our common stock. The share repurchase program does not have an expiration date. Purchases were made under terms intended to qualify for exemption under Rules 10b-18 and 10b5-1.

ITEM 5. Other Information

Amended and Restated Bylaws

On July 30, 2025, the Board of Directors of the Company amended and restated the Company’s Amended and Restated Bylaws (as so amended and restated, the “Amended and Restated Bylaws”), which became effective immediately. The Amended and Restated Bylaws enhance clarity and effect technical and administrative changes to conform to decisions by the

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Delaware Supreme Court and Delaware Court of Chancery since the prior amendment and restatement of the Company’s bylaws. The amendments effected by the Amended and Restated Bylaws, among other things:

•modify the disclosure requirements set forth in the advance notice bylaw provisions, including, without limitation, those relating to information, representations and disclosures from proposing stockholders, proposed nominees and other persons related to a stockholder’s solicitation of proxies, in each case to conform to recent decisions by the Delaware Supreme Court and Delaware Court of Chancery;

•modify certain provisions, including, without limitation, those relating to conduct at stockholders’ meetings and the appointment of a chair to preside thereat;

•provide that, at any meeting of the Board of Directors, a quorum shall consist of a majority of the directors then in office;

•provide that, with respect to committees, a majority of the members of each such committee then in office shall constitute a quorum for the transaction of business; and

•incorporate certain ministerial and conforming changes to provide clarification and consistency.

The foregoing summary of the Amended and Restated Bylaws does not purport to be a complete description and is qualified in its entirety by reference to the full text of the Amended and Restated Bylaws, a copy of which is filed as Exhibit 3.2 to this filing and incorporated herein by reference.

Amendment to Amended and Restated Letter Agreement with Thomas E. Jorden

On July 31, 2025, at the recommendation of the Compensation Committee of the Board of Directors, the Company and Thomas E. Jorden entered into an Amendment to Amended and Restated Letter Agreement to extend the term of Mr. Jorden’s employment from October 1, 2026 to the date of the Company’s 2027 annual meeting of stockholders.

The foregoing summary of the Amendment to Amended and Restated Letter Agreement does not purport to be a complete description and is qualified in its entirety by reference to the full text of the Amendment to Amended and Restated Letter Agreement, a copy of which is filed as Exhibit 10.2 to this filing and incorporated herein by reference.

Trading Plan Arrangements

During the three months ended June 30, 2025, no director or officer of the Company or 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.

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ITEM 6. Exhibits

Index to Exhibits


Exhibit Number						Description

3.1						Amended and Restated Certificate of Incorporation of Coterra Energy Inc. (incorporated herein by reference to Exhibit 3.1 of Coterra ’s Current Report on Form 8-K filed with the SEC on May 2, 2024).

**3.2						Amended and Restated Bylaws of Coterra Energy Inc.

4.1						Certificate of Designations to 8 1⁄8% Series A Cumulative Perpetual Convertible Preferred Stock of Cimarex Energy Co. (incorporated herein by reference to Exhibit 4.3 of Coterra’s Annual Report on Form 10-K filed with the SEC on March 1, 2022).

4.2						Amendment to Certificate of Designations to 8 1/8% Series A Cumulative Perpetual Convertible Preferred Stock of Cimarex Energy Co. (incorporated herein by reference to Exhibit 4.4 of Coterra’s Annual Report on Form 10-K filed with the SEC on March 1, 2022).

4.3						Amendment to Certificate of Designations to 8 1/8% Series A Cumulative Perpetual Convertible Preferred Stock of Cimarex Energy Co. (incorporated herein by reference to Exhibit 4.3 of Coterra’s Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2022).

**10.1						A mendment to Amended and Restated Letter Agreement dated as of July 31, 2025 between Coterra Energy Inc. and T homas E. Jorden.*

**31.1						302 Certification — Chairman, President and Chief Executive Officer.

**31.2						302 Certification — Executive Vice President and Chief Financial Officer.

**32.1						906 Certification.

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.

101.SCH						Inline XBRL Taxonomy Extension Schema Document.

101.CAL						Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF						Inline XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB						Inline XBRL Taxonomy Extension Label Linkbase Document.

101.PRE						Inline XBRL Taxonomy Extension Presentation Linkbase Document.

104						Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

* Compensatory plan, contract or arrangement.

** Filed herewith.

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SIGNATURES

Pursuant to the requirements 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.


	COTERRA ENERGY INC.
	(Registrant)

August 5, 2025	By:	/s/ THOMAS E. JORDEN
		Thomas E. Jorden
		Chairman, Chief Executive Officer and President
		(Principal Executive Officer)

August 5, 2025	By:	/s/ SHANNON E. YOUNG III
		Shannon E. Young III
		Executive Vice President and Chief Financial Officer
		(Principal Financial Officer)

August 5, 2025	By:	/s/ TODD M. ROEMER
		Todd M. Roemer
		Vice President and Chief Accounting Officer
		(Principal Accounting Officer)

Coterra Energy Inc. - Quarter Report: 2025 June (Form 10-Q)

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