Devon Energy posts 2025 results, plans Coterra merger
Devon Energy reported strong fourth-quarter and full-year 2025 results while outlining a transformative all-stock merger with Coterra Energy.
Rhea-AI Filing Summary
Devon Energy reported strong fourth-quarter and full-year 2025 results while outlining a transformative all-stock merger with Coterra Energy. Q4 2025 net earnings were $562 million, or $0.90 per diluted share, with core earnings of $510 million, or $0.82 per diluted share. Operating cash flow in the quarter was $1.5 billion, funding capital investment of $883 million and generating $702 million of free cash flow. Production averaged 851,000 Boe per day, above guidance, with oil at 390,000 barrels per day and production costs of $10.99 per Boe.
For 2025, Devon generated net earnings of $2.681 billion and free cash flow of $3.119 billion, ending the year with $1.434 billion of cash and net debt of $6.955 billion, for a net debt-to-EBITDAX ratio of 0.9x. The company continued returning cash through its $5.0 billion repurchase program, buying back 7.1 million shares for $250 million in Q4 and $4.4 billion since inception, retiring about 14% of shares. A Q1 2026 dividend of $0.24 per share was declared, and Devon plans a 31% dividend increase to $0.315 per share after the Coterra merger closes, subject to board approval.
The merger with Coterra, announced Feb. 2, 2026, is expected to create one of the largest shale operators, targeting $1.0 billion in sustainable annual pre-tax synergies. Devon shareholders are expected to own about 54% of the combined company and Coterra shareholders about 46%. Devon estimates it has already achieved 85% of a separate $1 billion business optimization target, supporting lower per-unit costs and improved margins. Q1 2026 production is forecast at 823,000 to 843,000 Boe per day after adjusting for winter-weather downtime, with capital spending of about $900 million and full-year 2026 standalone capital of $3.5 to $3.7 billion.
Positive
- Transformative all-stock merger with Coterra Energy targeting $1.0 billion in sustainable annual pre-tax synergies and creating one of the largest shale operators, with Devon shareholders expected to own approximately 54% and Coterra shareholders approximately 46% of the combined company.
- Strong 2025 financial and operational performance, including net earnings of $2.681 billion, free cash flow of $3.119 billion, year-end net debt-to-EBITDAX of 0.9x, robust reserve replacement at 193%, and a planned 31% quarterly dividend increase following merger close, subject to board approval.
Negative
- None.
Insights
Devon posts strong 2025 cash generation and sets up a scaled merger with Coterra.
Devon Energy delivered solid 2025 profitability, with full-year net earnings of $2.681B and free cash flow of $3.119B. Q4 2025 free cash flow of $702M came after $883M of capital spending, underscoring the strength of its asset base at $36.60 per Boe realized price for the year.
Leverage appears conservative, with year-end net debt of $6.955B and a net-debt-to-EBITDAX ratio of 0.9%, supported by $1.434B in cash and an undrawn $3B credit facility. Field-level cash margins remained healthy across core basins, aided by production costs, including taxes, of $10.99 per Boe in Q4 2025.
The all-stock merger with Coterra Energy is positioned as transformational, targeting $1.0B of sustainable annual pre-tax synergies and creating a large-scale shale operator anchored in the Delaware Basin. Ownership is expected to be 54% Devon shareholders and 46% Coterra shareholders. Post-close, Devon plans a 31% increase in the quarterly dividend to $0.315 per share and anticipates a new share repurchase authorization above $5B, both subject to board approval.
Operational outperformance and reserve growth underpin Devon’s merger narrative.
Devon’s Q4 2025 production of 851,000 Boe/d exceeded the top end of guidance, driven mainly by Delaware Basin wells. Oil volumes of 390,000 Bbl/d and lower unit costs, with production expenses of $10.99 per Boe, demonstrate operational efficiency and cost discipline.
Proved reserves ended 2025 at 2.4 billion Boe, with 593 million Boe from extensions, discoveries, and positive performance revisions, a 193% replacement rate. Finding and development costs of $6.14 per Boe on $3.6B of capital suggest competitive economics. Devon has already achieved 85% of its $1B business optimization target and remains on track to reach it by year-end 2026, which supports margin resilience heading into the planned Coterra combination.
8-K Event Classification
FAQ
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM
CURRENT REPORT
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Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§ 230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§ 240.12b-2 of this chapter).
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. ☐
| Item 2.02 | Results of Operations and Financial Condition. |
On February 17, 2026, Devon Energy Corporation (the “Company”) announced its financial and operational results for the year and quarter ended December 31, 2025. In connection with this announcement, the Company provided an earnings release and certain supplemental financial information (including guidance and hedging information). Copies of these documents are furnished as Exhibits 99.1 and 99.2, respectively, to this report and, along with certain other materials, will be available on the Company’s website at www.devonenergy.com.
The information contained in this report and the exhibits hereto shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and shall not be incorporated by reference into any filings made by the Company under the Securities Act of 1933, as amended, or the Exchange Act, except as may be expressly set forth by specific reference in such filing.
| Item 9.01 | Financial Statements and Exhibits. |
(d) Exhibits
| Exhibit No. |
Description of Exhibits | |
| 99.1 | Earnings release, dated February 17, 2026. | |
| 99.2 | Supplemental financial information (including guidance and hedging information). | |
| 104 | Cover Page Interactive Data File (embedded within the Inline XBRL document). | |
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 hereunto duly authorized.
| DEVON ENERGY CORPORATION | ||
| By: | /s/ Jeffrey L. Ritenour | |
| Jeffrey L. Ritenour | ||
| Executive Vice President and Chief Financial Officer | ||
Date: February 17, 2026
Exhibit 99.1
|
Devon Energy Corporation 333 West Sheridan Avenue Oklahoma City, OK 73102-5015 |
Devon Energy Reports Fourth-Quarter and Full-Year 2025 Results
and Declares Quarterly Fixed Dividend
OKLAHOMA CITY – Feb. 17, 2026 – Devon Energy Corp. (NYSE: DVN) today reports fourth-quarter and full-year 2025 results and declares a quarterly fixed dividend. Supplemental financial tables and forward-looking guidance are available on the company’s website at www.devonenergy.com.
KEY FINANCIAL & OPERATIONAL HIGHLIGHTS
| • | Transformational Merger: Announced merger with Coterra Energy, creating a premier, large-cap shale operator |
| • | Production Outperformance: Averaged 390,000 barrels of oil production per day in the fourth quarter, exceeding the top-end of guidance |
| • | Disciplined Cost Management: Invested $883 million of capital in the fourth quarter, 4 percent below midpoint guidance, and reduced operating costs 8 percent compared to the first quarter of 2025 |
| • | Business Optimization Success: Achieved 85 percent of the $1 billion business optimization target in 2025 and on track to fully achieve goal by year-end 2026 |
| • | Robust Cash Generation: Operations generated $1.5 billion of operating cash flow and $702 million of free cash flow during fourth quarter |
| • | Accelerated Shareholder Returns: Expect to increase quarterly dividend rate to $0.315 per share and a new $5 billion-plus share repurchase program following merger close, subject to board approval |
CEO COMMENTARY
“Devon’s disciplined execution and operational excellence defined 2025, culminating in outstanding results that exceeded fourth-quarter expectations across all major value drivers,” said Clay Gaspar, president and CEO. “The success we achieved this year was underpinned by the momentum generated through our focused business optimization efforts, resulting in significant free cash flow and meaningful cash returns to shareholders.”
“In addition to our banner year in 2025, we have taken bold, strategic steps to significantly strengthen our portfolio and position ourselves for sustained success through a transformative merger with Coterra Energy,” Gaspar added. “This powerful combination brings together two industry-leading companies with complementary assets and proven track records of value creation, establishing a premier independent shale operator. This advantaged platform will deliver higher free cash flow and enhanced shareholder returns, well beyond what either company could achieve on its own.”
STRATEGIC MERGER WITH COTERRA ENERGY
On Feb. 2, 2026, Devon announced that it had entered into an agreement to combine in an all-stock merger with Coterra Energy.
The combination will create one of the largest shale operators in the world with an asset base anchored by a premier position in the economic core of the Delaware Basin. The go-forward company, to be named Devon Energy, is expected to unlock substantial value for shareholders by leveraging enhanced scale to improve margins, increase free cash flow, and accelerate cash returns through the capture of $1.0 billion in sustainable annual pre-tax synergies.
The transaction is expected to close in the second quarter of 2026. Upon completion of the transaction, Devon shareholders will own approximately 54 percent of the combined company and Coterra shareholders will own approximately 46 percent of the combined company on a fully diluted basis.
FINANCIAL RESULTS
Devon reported net earnings of $562 million, or $0.90 per diluted share, in the fourth quarter of 2025. Adjusting for items analysts typically exclude from estimates, the company’s core earnings were $510 million, or $0.82 per diluted share.
1
Devon’s operating cash flow totaled $1.5 billion in the fourth quarter. The company funded its capital requirements and had $702 million of free cash flow for the quarter.
At the end of the fourth quarter, Devon had a cash balance of $1.4 billion and an undrawn credit facility of $3 billion. Outstanding debt totaled $8.4 billion and the company’s net debt-to-EBITDAX ratio was 0.9 times.
RETURN OF CAPITAL
Consistent with Devon’s strategic priority of delivering value to shareholders through a sustainable, annually growing fixed dividend, Devon plans to increase the quarterly dividend rate by 31 percent to $0.315 per share following merger close, subject to board approval. For the first quarter of 2026, a dividend of $0.24 per share is payable on Mar. 31, 2026, to shareholders of record at the close of business on Mar. 13, 2026.
The company also returned capital to shareholders through the ongoing execution of its $5.0 billion share repurchase program. During the fourth quarter, Devon repurchased 7.1 million of its shares for $250 million. Since inception of the program, the company has returned $4.4 billion to shareholders by retiring approximately 14 percent of its outstanding shares. In connection with the announcement of the merger with Coterra, the company suspended share repurchasing activity, which Devon expects to extend through closing.
Following the close of the merger with Coterra Energy and the associated free cash flow benefits in the upcoming years, the company expects to establish a new share repurchase authorization in excess of $5 billion, subject to Board approval.
OPERATING RESULTS
Devon’s capital activity in the fourth quarter averaged 19 operated drilling rigs and 4 completion crews across its asset portfolio. This level of activity resulted in 95 gross operated wells being placed online, with an average lateral length of 10,200 feet. Capital investment, excluding acquisition capital, was $883 million, or 4 percent below guidance. This positive variance was primarily attributable to effective cost management and timing of facility spend. The company also completed $141 million in leasehold acquisitions across multiple assets in its portfolio, primarily in the Delaware Basin.
Production averaged 851,000 Boe per day in the fourth quarter, exceeding the top-end of guidance. This positive result was driven by better-than-expected well performance, primarily in the Delaware Basin. Oil totaled 390,000 barrels per day in the quarter, which was 46 percent of total volume and above the top-end of the company’s guidance.
Production costs, including taxes, averaged $10.99 per Boe in the fourth quarter, a 4 percent reduction from the third quarter. The largest component of production costs is lease operating expense and gathering, processing and transportation costs, which totaled $8.60 per Boe in the quarter. Effective cost management efforts and less well workovers drove per-unit rates 3 percent below guidance expectations for the quarter.
Underpinning these results is the continued strong progress in advancing the company’s business optimization plan. To date, Devon has already achieved 85 percent of its $1 billion target, demonstrating the effectiveness and urgency of these initiatives. With strong momentum established, the company is on track to fully achieve its $1 billion target by year-end 2026. These actions are strengthening margins and maximizing capital efficiency across Devon’s assets.
Devon exited the year with estimated proved reserves of 2.4 billion Boe. Proved undeveloped reserves accounted for 24 percent of the total. Extensions and discoveries and positive performance revisions from the company’s drilling program added 593 million Boe of reserves in 2025, equating to a replacement rate of 193 percent of production. Capital costs incurred (excluding property acquisition costs) to deliver these additions totaled $3.6 billion, resulting in a finding and development cost of $6.14 per Boe.
Q1 2026 OUTLOOK
Production in the first quarter of 2026 is estimated to be reduced by 1 percent or 10,000 Boe per day (50 percent oil) due to the impact of severe winter weather. Adjusting for this downtime, the company expects production to average 823,000 to 843,000 Boe per day. Capital spending in the first quarter is expected to be approximately $900 million.
2
Looking beyond the first quarter, the company’s full-year 2026 guidance issued today reflects standalone Devon operations. Upon the expected closure of the Devon and Coterra merger in the second quarter of 2026, the company will provide updated full-year guidance for the combined entity.
Additional details of Devon’s forward-looking guidance are available on the company’s website at www.devonenergy.com.
CONFERENCE CALL WEBCAST AND SUPPLEMENTAL EARNINGS MATERIALS
Also provided with today’s release is the company’s earnings presentation that is available on the company’s website at www.devonenergy.com. The company’s fourth-quarter conference call will be held at 10:00 a.m. Central (11:00 a.m. Eastern) on Wednesday, February 18, 2026, and will serve primarily as a forum for analyst and investor questions and answers.
ABOUT DEVON ENERGY
Devon Energy is a leading oil and gas producer in the U.S. with a diversified multi-basin portfolio headlined by a world-class acreage position in the Delaware Basin. Devon’s disciplined cash-return business model is designed to achieve strong returns, generate free cash flow and return capital to shareholders, while focusing on safe and sustainable operations. For more information, please visit www.devonenergy.com.
| Investor Contact | Media Contact | |
| investor.relations@dvn.com | Michelle Hindmarch | |
| 405-228-4450 | 405-552-7460 |
NON-GAAP DISCLOSURES
This press release includes non-GAAP (generally accepted accounting principles) financial measures. Such non-GAAP measures are not alternatives to GAAP measures, and you should not consider these non-GAAP measures in isolation or as a substitute for analysis of results as reported under GAAP. Reconciliations of these non-GAAP measures and other disclosures are provided within the supplemental financial tables that are available on the company’s website and in the related Form 10-K filed with the Securities and Exchange Commission (the “SEC”).
FORWARD LOOKING STATEMENTS
This press release includes “forward-looking statements” within the meaning of the federal securities laws. Such statements include those concerning strategic plans, our expectations and objectives for future operations, as well as other future events or conditions, and are often identified by use of the words and phrases “expects,” “believes,” “will,” “would,” “could,” “continue,” “may,” “aims,” “likely to be,” “intends,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that Devon expects, believes or anticipates will or may occur in the future are forward-looking statements. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Consequently, actual future results could differ materially and adversely from our expectations due to a number of factors, including, but not limited to: the volatility of oil, gas and NGL prices, including from changes in trade relations and policies, such as the imposition of new or increased tariffs or other trade protection measures by the U.S., China or other countries; uncertainties inherent in estimating oil, gas and NGL reserves; the extent to which we are successful in acquiring and discovering additional reserves; the uncertainties, costs and risks involved in our operations; risks related to our hedging activities; our limited control over third parties who operate some of our oil and gas properties and investments; midstream capacity constraints and potential interruptions in production, including from limits to the build out of midstream infrastructure; competition for assets, materials, people and capital, which can be exacerbated by supply chain disruptions, including as a result of tariffs or other changes in trade policy; regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to federal lands, environmental matters, water disposal and tax matters; climate change and risks related to regulatory, social and market efforts to address climate change; risks relating to our sustainability initiatives; claims, audits and other proceedings impacting our business, including with respect to historic and legacy operations; governmental interventions in energy markets; counterparty credit risks; risks relating to our indebtedness; cybersecurity risks; risks associated with artificial intelligence and other emerging technologies; the extent to which insurance covers any losses we may experience; risks related to shareholder activism; our ability to successfully complete mergers, acquisitions and divestitures; our ability to pay dividends and make share repurchases; risks related to the merger with Coterra, including restrictions on our operations during the pendency of the merger, litigation risk, the risk that the merger agreement may be terminated and the risk that we may not realize the anticipated benefits of the merger or successfully integrate the two companies; and any of the other risks and uncertainties discussed in Devon’s 2025 Annual Report on Form 10-K (the “2025 Form 10-K”) or other filings with the SEC.
The forward-looking statements included in this press release speak only as of the date of this press release, represent management’s current reasonable expectations as of the date of this press release and are subject to the risks and uncertainties identified above as well as those described elsewhere in the 2025 Form 10-K and in other documents we file from time to time with the SEC. We cannot guarantee the accuracy of our forward-looking statements, and readers are urged to carefully review and consider the various disclosures made in the 2025 Form 10-K and in other documents we file from time to time with the SEC. All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements above. We do not undertake, and expressly disclaim, any duty to update or revise our forward-looking statements based on new information, future events or otherwise.
3
Exhibit 99.2
Devon Energy Fourth-Quarter 2025
Supplemental Tables
| TABLE OF CONTENTS: | PAGE: | |||
| Consolidated Statements of Earnings |
2 | |||
| Supplemental Information for Consolidated Statements of Earnings |
3 | |||
| Consolidated Balance Sheets |
4 | |||
| Consolidated Statements of Cash Flows |
5 | |||
| Production |
6 | |||
| Capital Expenditures, Costs Incurred and Reserves Reconciliation |
7 | |||
| Supplemental Information for Capital Expenditures |
8 | |||
| Realized Pricing |
9 | |||
| Asset Margins |
10 | |||
| Core Earnings |
11 | |||
| EBITDAX, Net Debt and Net Debt-to-EBITDAX |
12 | |||
| Free Cash Flow and Reinvestment Rate |
13 | |||
1
CONSOLIDATED STATEMENTS OF EARNINGS
| (in millions, except per share amounts) | 2025 | 2024 | ||||||||||||||||||||||
| Full Year | Quarter 4 | Quarter 3 | Quarter 2 | Quarter 1 | Quarter 4 | |||||||||||||||||||
| Oil, gas and NGL sales |
$ | 11,223 | $ | 2,578 | $ | 2,809 | $ | 2,710 | $ | 3,126 | $ | 3,086 | ||||||||||||
| Oil, gas and NGL derivatives (1) |
402 | 184 | 80 | 236 | (98 | ) | (84 | ) | ||||||||||||||||
| Marketing and midstream revenues |
5,563 | 1,359 | 1,442 | 1,338 | 1,424 | 1,401 | ||||||||||||||||||
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| Total revenues |
17,188 | 4,121 | 4,331 | 4,284 | 4,452 | 4,403 | ||||||||||||||||||
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| Production expenses (2) |
3,567 | 861 | 895 | 899 | 912 | 881 | ||||||||||||||||||
| Exploration expenses |
43 | 5 | 8 | 20 | 10 | 12 | ||||||||||||||||||
| Marketing and midstream expenses |
5,635 | 1,389 | 1,453 | 1,357 | 1,436 | 1,402 | ||||||||||||||||||
| Depreciation, depletion and amortization |
3,595 | 890 | 879 | 914 | 912 | 971 | ||||||||||||||||||
| Asset impairments |
254 | — | — | — | 254 | — | ||||||||||||||||||
| Asset dispositions |
(343 | ) | (1 | ) | (37 | ) | (307 | ) | 2 | (5 | ) | |||||||||||||
| General and administrative expenses |
492 | 135 | 114 | 113 | 130 | 155 | ||||||||||||||||||
| Financing costs, net (3) |
455 | 107 | 109 | 116 | 123 | 123 | ||||||||||||||||||
| Other, net |
24 | (12 | ) | (2 | ) | 11 | 27 | 24 | ||||||||||||||||
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| Total expenses |
13,722 | 3,374 | 3,419 | 3,123 | 3,806 | 3,563 | ||||||||||||||||||
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| Earnings before income taxes |
3,466 | 747 | 912 | 1,161 | 646 | 840 | ||||||||||||||||||
| Income tax expense (4) |
785 | 185 | 219 | 244 | 137 | 187 | ||||||||||||||||||
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| Net earnings |
2,681 | 562 | 693 | 917 | 509 | 653 | ||||||||||||||||||
| Net earnings attributable to noncontrolling interests |
39 | — | 6 | 18 | 15 | 14 | ||||||||||||||||||
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| Net earnings attributable to Devon |
$ | 2,642 | $ | 562 | $ | 687 | $ | 899 | $ | 494 | $ | 639 | ||||||||||||
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| Net earnings per share: |
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| Basic net earnings per share |
$ | 4.18 | $ | 0.91 | $ | 1.09 | $ | 1.42 | $ | 0.77 | $ | 0.98 | ||||||||||||
| Diluted net earnings per share |
$ | 4.17 | $ | 0.90 | $ | 1.09 | $ | 1.41 | $ | 0.77 | $ | 0.98 | ||||||||||||
| Weighted average common shares outstanding: |
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| Basic |
632 | 621 | 628 | 635 | 643 | 650 | ||||||||||||||||||
| Diluted |
633 | 622 | 629 | 636 | 645 | 651 | ||||||||||||||||||
2
SUPPLEMENTAL INFORMATION FOR CONSOLIDATED STATEMENTS OF EARNINGS
| (1) OIL, GAS AND NGL DERIVATIVES | ||||||||||||||||||||||||
| (in millions) | 2025 | 2024 | ||||||||||||||||||||||
| Full Year | Quarter 4 | Quarter 3 | Quarter 2 | Quarter 1 | Quarter 4 | |||||||||||||||||||
| Derivative cash settlements |
$ | 232 | $ | 125 | $ | 50 | $ | 67 | $ | (10 | ) | $ | 58 | |||||||||||
| Derivative valuation changes |
170 | 59 | 30 | 169 | (88 | ) | (142 | ) | ||||||||||||||||
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| Oil, gas and NGL derivatives |
$ | 402 | $ | 184 | $ | 80 | $ | 236 | $ | (98 | ) | $ | (84 | ) | ||||||||||
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| (2) PRODUCTION EXPENSES | ||||||||||||||||||||||||
| (in millions) | 2025 | 2024 | ||||||||||||||||||||||
| Full Year | Quarter 4 | Quarter 3 | Quarter 2 | Quarter 1 | Quarter 4 | |||||||||||||||||||
| Lease operating expense |
$ | 1,922 | $ | 479 | $ | 481 | $ | 483 | $ | 479 | $ | 445 | ||||||||||||
| Gathering, processing & transportation |
831 | 195 | 213 | 219 | 204 | 213 | ||||||||||||||||||
| Production taxes |
748 | 172 | 184 | 180 | 212 | 206 | ||||||||||||||||||
| Property taxes |
66 | 15 | 17 | 17 | 17 | 17 | ||||||||||||||||||
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| Production expenses |
$ | 3,567 | $ | 861 | $ | 895 | $ | 899 | $ | 912 | $ | 881 | ||||||||||||
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| (3) FINANCING COSTS, NET | ||||||||||||||||||||||||
| (in millions) | 2025 | 2024 | ||||||||||||||||||||||
| Full Year | Quarter 4 | Quarter 3 | Quarter 2 | Quarter 1 | Quarter 4 | |||||||||||||||||||
| Interest based on debt outstanding |
$ | 497 | $ | 119 | $ | 125 | $ | 126 | $ | 127 | $ | 128 | ||||||||||||
| Interest income |
(56 | ) | (14 | ) | (18 | ) | (14 | ) | (10 | ) | (16 | ) | ||||||||||||
| Other |
14 | 2 | 2 | 4 | 6 | 11 | ||||||||||||||||||
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| Financing costs, net |
$ | 455 | $ | 107 | $ | 109 | $ | 116 | $ | 123 | $ | 123 | ||||||||||||
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| (4) INCOME TAX EXPENSE | ||||||||||||||||||||||||
| (in millions) | 2025 | 2024 | ||||||||||||||||||||||
| Full Year | Quarter 4 | Quarter 3 | Quarter 2 | Quarter 1 | Quarter 4 | |||||||||||||||||||
| Current expense (benefit) |
$ | 301 | $ | 23 | $ | (44 | ) | $ | 226 | $ | 96 | $ | 119 | |||||||||||
| Deferred expense |
484 | 162 | 263 | 18 | 41 | 68 | ||||||||||||||||||
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| Income tax expense |
$ | 785 | $ | 185 | $ | 219 | $ | 244 | $ | 137 | $ | 187 | ||||||||||||
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3
CONSOLIDATED BALANCE SHEETS
| (in millions) | 2025 | 2024 | ||||||||||||||||||
| Quarter 4 | Quarter 3 | Quarter 2 | Quarter 1 | Quarter 4 | ||||||||||||||||
| Current assets: |
||||||||||||||||||||
| Cash, cash equivalents and restricted cash |
$ | 1,434 | $ | 1,278 | $ | 1,759 | $ | 1,234 | $ | 846 | ||||||||||
| Accounts receivable |
1,792 | 1,835 | 1,853 | 2,036 | 1,972 | |||||||||||||||
| Inventory |
336 | 361 | 327 | 332 | 294 | |||||||||||||||
| Other current assets |
444 | 393 | 384 | 303 | 315 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total current assets |
4,006 | 3,867 | 4,323 | 3,905 | 3,427 | |||||||||||||||
| Oil and gas property and equipment, based on successful efforts accounting, net |
23,731 | 23,591 | 23,428 | 23,429 | 23,198 | |||||||||||||||
| Other property and equipment, net |
1,688 | 1,698 | 1,687 | 1,653 | 1,813 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total property and equipment, net |
25,419 | 25,289 | 25,115 | 25,082 | 25,011 | |||||||||||||||
| Goodwill |
753 | 753 | 753 | 753 | 753 | |||||||||||||||
| Right-of-use assets |
299 | 247 | 185 | 127 | 303 | |||||||||||||||
| Investments |
727 | 679 | 640 | 713 | 727 | |||||||||||||||
| Other long-term assets |
395 | 386 | 374 | 348 | 268 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total assets |
$ | 31,599 | $ | 31,221 | $ | 31,390 | $ | 30,928 | $ | 30,489 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Current liabilities: |
||||||||||||||||||||
| Accounts payable |
$ | 790 | $ | 934 | $ | 885 | $ | 923 | $ | 806 | ||||||||||
| Revenues and royalties payable |
1,491 | 1,464 | 1,440 | 1,588 | 1,432 | |||||||||||||||
| Short-term debt |
998 | 998 | 485 | 485 | 485 | |||||||||||||||
| Other current liabilities |
807 | 646 | 727 | 622 | 586 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total current liabilities |
4,086 | 4,042 | 3,537 | 3,618 | 3,309 | |||||||||||||||
| Long-term debt |
7,391 | 7,393 | 8,393 | 8,395 | 8,398 | |||||||||||||||
| Lease liabilities |
197 | 158 | 113 | 77 | 320 | |||||||||||||||
| Asset retirement obligations |
863 | 850 | 839 | 835 | 770 | |||||||||||||||
| Other long-term liabilities |
907 | 962 | 1,008 | 1,041 | 840 | |||||||||||||||
| Deferred income taxes |
2,627 | 2,466 | 2,208 | 2,189 | 2,148 | |||||||||||||||
| Stockholders’ equity: |
||||||||||||||||||||
| Common stock |
62 | 63 | 64 | 64 | 65 | |||||||||||||||
| Additional paid-in capital |
5,388 | 5,618 | 5,864 | 6,096 | 6,387 | |||||||||||||||
| Retained earnings |
10,200 | 9,788 | 9,252 | 8,506 | 8,166 | |||||||||||||||
| Accumulated other comprehensive loss |
(122 | ) | (119 | ) | (120 | ) | (121 | ) | (122 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total stockholders’ equity attributable to Devon |
15,528 | 15,350 | 15,060 | 14,545 | 14,496 | |||||||||||||||
| Noncontrolling interests |
— | — | 232 | 228 | 208 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total equity |
15,528 | 15,350 | 15,292 | 14,773 | 14,704 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total liabilities and equity |
$ | 31,599 | $ | 31,221 | $ | 31,390 | $ | 30,928 | $ | 30,489 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
4
CONSOLIDATED STATEMENTS OF CASH FLOWS
| (in millions) | 2025 | 2024 | ||||||||||||||||||||||
| Full Year | Quarter 4 | Quarter 3 | Quarter 2 | Quarter 1 | Quarter 4 | |||||||||||||||||||
| Cash flows from operating activities: |
||||||||||||||||||||||||
| Net earnings |
$ | 2,681 | $ | 562 | $ | 693 | $ | 917 | $ | 509 | $ | 653 | ||||||||||||
| Adjustments to reconcile net earnings to net cash from operating activities: |
||||||||||||||||||||||||
| Depreciation, depletion and amortization |
3,595 | 890 | 879 | 914 | 912 | 971 | ||||||||||||||||||
| Asset impairments |
254 | — | — | — | 254 | — | ||||||||||||||||||
| Leasehold impairments |
11 | (2 | ) | 1 | 7 | 5 | 3 | |||||||||||||||||
| Accretion of liabilities |
16 | 3 | 4 | 3 | 6 | 6 | ||||||||||||||||||
| Total (gains) losses on commodity derivatives |
(402 | ) | (184 | ) | (80 | ) | (236 | ) | 98 | 84 | ||||||||||||||
| Cash settlements on commodity derivatives |
232 | 125 | 50 | 67 | (10 | ) | 58 | |||||||||||||||||
| (Gains) losses on asset dispositions |
(343 | ) | (1 | ) | (37 | ) | (307 | ) | 2 | (5 | ) | |||||||||||||
| Deferred income tax expense |
484 | 162 | 263 | 18 | 41 | 68 | ||||||||||||||||||
| Share-based compensation |
99 | 22 | 24 | 23 | 30 | 24 | ||||||||||||||||||
| Other |
(67 | ) | (5 | ) | (45 | ) | 5 | (22 | ) | 4 | ||||||||||||||
| Changes in assets and liabilities, net |
151 | (38 | ) | (62 | ) | 134 | 117 | (202 | ) | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Net cash from operating activities |
6,711 | 1,534 | 1,690 | 1,545 | 1,942 | 1,664 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Cash flows from investing activities: |
||||||||||||||||||||||||
| Capital expenditures |
(3,592 | ) | (832 | ) | (870 | ) | (956 | ) | (934 | ) | (926 | ) | ||||||||||||
| Acquisitions of property and equipment |
(322 | ) | (101 | ) | (197 | ) | (16 | ) | (8 | ) | (116 | ) | ||||||||||||
| Divestitures of property and equipment and investments |
545 | 2 | 38 | 372 | 133 | 6 | ||||||||||||||||||
| Distributions from investments |
38 | 11 | 7 | 11 | 9 | 33 | ||||||||||||||||||
| Contributions to investments and other |
(62 | ) | (50 | ) | (2 | ) | (8 | ) | (2 | ) | (40 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Net cash from investing activities |
(3,393 | ) | (970 | ) | (1,024 | ) | (597 | ) | (802 | ) | (1,043 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Cash flows from financing activities: |
||||||||||||||||||||||||
| Repayments of long-term debt |
(485 | ) | — | (485 | ) | — | — | — | ||||||||||||||||
| Repurchases of common stock |
(1,050 | ) | (250 | ) | (250 | ) | (249 | ) | (301 | ) | (301 | ) | ||||||||||||
| Dividends paid on common stock |
(619 | ) | (149 | ) | (151 | ) | (156 | ) | (163 | ) | (143 | ) | ||||||||||||
| Contributions from noncontrolling interests |
14 | — | — | — | 14 | 8 | ||||||||||||||||||
| Distributions to noncontrolling interests |
(23 | ) | — | — | (14 | ) | (9 | ) | (15 | ) | ||||||||||||||
| Acquisition of noncontrolling interests |
(260 | ) | — | (260 | ) | — | — | — | ||||||||||||||||
| Repayment of finance leases |
(282 | ) | (8 | ) | — | — | (274 | ) | — | |||||||||||||||
| Shares exchanged for tax withholdings and other |
(25 | ) | — | (1 | ) | (5 | ) | (19 | ) | 1 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Net cash from financing activities |
(2,730 | ) | (407 | ) | (1,147 | ) | (424 | ) | (752 | ) | (450 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Effect of exchange rate changes on cash |
— | (1 | ) | — | 1 | — | (1 | ) | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Net change in cash, cash equivalents and restricted cash |
588 | 156 | (481 | ) | 525 | 388 | 170 | |||||||||||||||||
| Cash, cash equivalents and restricted cash at beginning of period |
846 | 1,278 | 1,759 | 1,234 | 846 | 676 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Cash, cash equivalents and restricted cash at end of period |
$ | 1,434 | $ | 1,434 | $ | 1,278 | $ | 1,759 | $ | 1,234 | $ | 846 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Reconciliation of cash, cash equivalents and restricted cash: |
||||||||||||||||||||||||
| Cash and cash equivalents |
$ | 1,384 | $ | 1,384 | $ | 1,229 | $ | 1,713 | $ | 1,198 | $ | 811 | ||||||||||||
| Restricted cash |
50 | 50 | 49 | 46 | 36 | 35 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total cash, cash equivalents and restricted cash |
$ | 1,434 | $ | 1,434 | $ | 1,278 | $ | 1,759 | $ | 1,234 | $ | 846 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
5
PRODUCTION
| 2025 | 2024 | |||||||||||||||||||||||
| Full Year | Quarter 4 | Quarter 3 | Quarter 2 | Quarter 1 | Quarter 4 | |||||||||||||||||||
| Oil (MBbls/d) |
||||||||||||||||||||||||
| Delaware Basin |
225 | 234 | 223 | 228 | 216 | 221 | ||||||||||||||||||
| Rockies |
107 | 102 | 111 | 104 | 112 | 110 | ||||||||||||||||||
| Eagle Ford |
41 | 39 | 41 | 39 | 45 | 49 | ||||||||||||||||||
| Anadarko Basin |
12 | 12 | 12 | 13 | 11 | 14 | ||||||||||||||||||
| Other |
4 | 3 | 3 | 3 | 4 | 4 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total |
389 | 390 | 390 | 387 | 388 | 398 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Natural gas liquids (MBbls/d) |
||||||||||||||||||||||||
| Delaware Basin |
133 | 146 | 134 | 133 | 118 | 127 | ||||||||||||||||||
| Rockies |
49 | 51 | 53 | 47 | 44 | 43 | ||||||||||||||||||
| Eagle Ford |
11 | 10 | 11 | 11 | 15 | 21 | ||||||||||||||||||
| Anadarko Basin |
28 | 24 | 30 | 31 | 26 | 30 | ||||||||||||||||||
| Other |
— | — | — | — | — | — | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total |
221 | 231 | 228 | 222 | 203 | 221 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Gas (MMcf/d) |
||||||||||||||||||||||||
| Delaware Basin |
812 | 848 | 834 | 823 | 744 | 755 | ||||||||||||||||||
| Rockies |
235 | 234 | 245 | 228 | 233 | 230 | ||||||||||||||||||
| Eagle Ford |
76 | 56 | 70 | 62 | 117 | 130 | ||||||||||||||||||
| Anadarko Basin |
258 | 246 | 261 | 274 | 252 | 255 | ||||||||||||||||||
| Other |
1 | 1 | — | 1 | — | 1 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total |
1,382 | 1,385 | 1,410 | 1,388 | 1,346 | 1,371 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total oil equivalent (MBoe/d) |
||||||||||||||||||||||||
| Delaware Basin |
493 | 521 | 496 | 498 | 458 | 474 | ||||||||||||||||||
| Rockies |
195 | 192 | 205 | 189 | 195 | 191 | ||||||||||||||||||
| Eagle Ford |
65 | 57 | 63 | 60 | 79 | 92 | ||||||||||||||||||
| Anadarko Basin |
83 | 77 | 85 | 90 | 79 | 87 | ||||||||||||||||||
| Other |
4 | 4 | 4 | 4 | 4 | 4 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total |
840 | 851 | 853 | 841 | 815 | 848 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
6
CAPITAL EXPENDITURES
| (in millions) | 2025 | 2024 | ||||||||||||||||||||||
| Full Year | Quarter 4 | Quarter 3 | Quarter 2 | Quarter 1 | Quarter 4 | |||||||||||||||||||
| Delaware Basin |
$ | 1,868 | $ | 446 | $ | 457 | $ | 472 | $ | 493 | $ | 448 | ||||||||||||
| Rockies |
856 | 228 | 189 | 224 | 215 | 268 | ||||||||||||||||||
| Eagle Ford |
544 | 137 | 138 | 118 | 151 | 107 | ||||||||||||||||||
| Anadarko Basin |
147 | 32 | 25 | 44 | 46 | 44 | ||||||||||||||||||
| Other |
7 | 1 | 1 | 2 | 3 | 5 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total upstream capital |
$ | 3,422 | $ | 844 | $ | 810 | $ | 860 | $ | 908 | $ | 872 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Carbon capital |
101 | 21 | 28 | 30 | 22 | 12 | ||||||||||||||||||
| Midstream and Corporate |
115 | 18 | 21 | 42 | 34 | 42 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Capital expenditures |
$ | 3,638 | $ | 883 | $ | 859 | $ | 932 | $ | 964 | $ | 926 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Acquisitions |
362 | 141 | 197 | 16 | 8 | 116 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
| Total capital |
$ | 4,000 | $ | 1,024 | $ | 1,056 | $ | 948 | $ | 972 | $ | 1,042 | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
COSTS INCURRED AND RESERVES RECONCILIATION
| COSTS INCURRED |
Year Ended December 31, | |||||||
| (in millions) | 2025 | 2024 | ||||||
| Property acquisition costs: |
||||||||
| Proved properties |
138 | $ | 3,058 | |||||
| Unproved properties |
224 | 1,949 | ||||||
| Exploration costs |
581 | 690 | ||||||
| Development costs |
3,057 | 2,856 | ||||||
|
|
|
|
|
|||||
| Costs incurred |
4,000 | $ | 8,553 | |||||
|
|
|
|
|
|||||
RESERVES RECONCILIATION
| Oil (MMBbls) |
Gas (Bcf) |
NGL (MMBbls) |
Total (MMBoe) |
|||||||||||||
| As of December 31, 2024: |
||||||||||||||||
| Proved developed |
706 | 3,057 | 500 | 1,715 | ||||||||||||
| Proved undeveloped |
196 | 719 | 124 | 440 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total Proved |
902 | 3,776 | 624 | 2,155 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Revisions due to prices |
(25 | ) | 91 | (6 | ) | (16 | ) | |||||||||
| Revisions other than price |
36 | 353 | 55 | 150 | ||||||||||||
| Extensions and discoveries |
185 | 778 | 129 | 443 | ||||||||||||
| Purchase of reserves |
23 | 59 | 10 | 43 | ||||||||||||
| Production |
(142 | ) | (505 | ) | (81 | ) | (307 | ) | ||||||||
| Sale of reserves |
(18 | ) | (70 | ) | (11 | ) | (40 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| As of December 31, 2025: |
||||||||||||||||
| Proved developed |
714 | 3,476 | 551 | 1,844 | ||||||||||||
| Proved undeveloped |
247 | 1,006 | 169 | 584 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total Proved |
961 | 4,482 | 720 | 2,428 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
7
SUPPLEMENTAL INFORMATION FOR CAPITAL EXPENDITURES
| GROSS OPERATED SPUDS | ||||||||||||||||||||
| 2025 | 2024 | |||||||||||||||||||
| Quarter 4 | Quarter 3 | Quarter 2 | Quarter 1 | Quarter 4 | ||||||||||||||||
| Delaware Basin |
48 | 60 | 57 | 73 | 67 | |||||||||||||||
| Rockies |
26 | 21 | 23 | 24 | 24 | |||||||||||||||
| Eagle Ford |
18 | 24 | 22 | 30 | 12 | |||||||||||||||
| Anadarko Basin |
8 | 10 | 11 | 5 | 2 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
100 | 115 | 113 | 132 | 105 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| GROSS OPERATED WELLS TIED-IN | ||||||||||||||||||||
| 2025 | 2024 | |||||||||||||||||||
| Quarter 4 | Quarter 3 | Quarter 2 | Quarter 1 | Quarter 4 | ||||||||||||||||
| Delaware Basin |
45 | 61 | 57 | 79 | 55 | |||||||||||||||
| Rockies |
17 | 22 | 30 | 16 | 30 | |||||||||||||||
| Eagle Ford |
23 | 10 | 10 | 35 | 23 | |||||||||||||||
| Anadarko Basin |
10 | 9 | 13 | 6 | 20 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
95 | 102 | 110 | 136 | 128 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| NET OPERATED WELLS TIED-IN | ||||||||||||||||||||
| 2025 | 2024 | |||||||||||||||||||
| Quarter 4 | Quarter 3 | Quarter 2 | Quarter 1 | Quarter 4 | ||||||||||||||||
| Delaware Basin |
35 | 40 | 46 | 54 | 50 | |||||||||||||||
| Rockies |
14 | 18 | 27 | 13 | 27 | |||||||||||||||
| Eagle Ford |
19 | 10 | 7 | 26 | 13 | |||||||||||||||
| Anadarko Basin |
4 | 5 | 5 | 2 | 8 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
72 | 73 | 85 | 95 | 98 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| AVERAGE LATERAL LENGTH | ||||||||||||||||||||
| (based on wells tied-in) | 2025 | 2024 | ||||||||||||||||||
| Quarter 4 | Quarter 3 | Quarter 2 | Quarter 1 | Quarter 4 | ||||||||||||||||
| Delaware Basin |
11,800’ | 11,100’ | 10,500’ | 10,300’ | 11,500’ | |||||||||||||||
| Rockies |
11,600’ | 13,000’ | 12,300’ | 12,200’ | 10,150’ | |||||||||||||||
| Eagle Ford |
5,900’ | 7,200’ | 8,200’ | 7,800’ | 7,700’ | |||||||||||||||
| Anadarko Basin |
10,100’ | 10,000’ | 10,000’ | 12,500’ | 10,000’ | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
10,200’ | 10,300’ | 10,300’ | 10,700’ | 9,900’ | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
8
REALIZED PRICING
| BENCHMARK PRICES | 2025 | 2024 | ||||||||||||||||||||||
| (average prices) | Full Year | Quarter 4 | Quarter 3 | Quarter 2 | Quarter 1 | Quarter 4 | ||||||||||||||||||
| Oil ($/Bbl) - West Texas Intermediate (Cushing) |
$ | 64.87 | $ | 59.09 | $ | 64.92 | $ | 63.95 | $ | 71.50 | $ | 70.32 | ||||||||||||
| Natural Gas ($/Mcf) - Henry Hub |
$ | 3.43 | $ | 3.55 | $ | 3.07 | $ | 3.44 | $ | 3.65 | $ | 2.79 | ||||||||||||
| NGL ($/Bbl) - Mont Belvieu Blended |
$ | 25.79 | $ | 23.67 | $ | 24.25 | $ | 25.58 | $ | 29.65 | $ | 27.80 | ||||||||||||
| REALIZED PRICES | 2025 | 2024 | ||||||||||||||||||||||
| Full Year | Quarter 4 | Quarter 3 | Quarter 2 | Quarter 1 | Quarter 4 | |||||||||||||||||||
| Oil (Per Bbl) |
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| Delaware Basin |
$ | 63.52 | $ | 57.94 | $ | 63.89 | $ | 62.60 | $ | 70.28 | $ | 69.06 | ||||||||||||
| Rockies |
60.52 | 54.99 | 61.14 | 59.05 | 66.40 | 65.67 | ||||||||||||||||||
| Eagle Ford |
64.20 | 58.18 | 64.87 | 63.14 | 69.85 | 69.25 | ||||||||||||||||||
| Anadarko Basin |
63.47 | 57.46 | 63.68 | 62.09 | 71.15 | 67.46 | ||||||||||||||||||
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| Realized price without hedges |
62.77 | 57.19 | 63.21 | 61.70 | 69.13 | 68.11 | ||||||||||||||||||
| Cash settlements |
1.14 | 2.47 | 0.78 | 1.27 | 0.02 | 1.08 | ||||||||||||||||||
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| Realized price, including cash settlements |
$ | 63.91 | $ | 59.66 | $ | 63.99 | $ | 62.97 | $ | 69.15 | $ | 69.19 | ||||||||||||
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| Natural gas liquids (Per Bbl) |
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| Delaware Basin |
$ | 19.50 | $ | 18.42 | $ | 18.25 | $ | 19.10 | $ | 22.76 | $ | 21.79 | ||||||||||||
| Rockies |
10.69 | 9.02 | 10.26 | 9.27 | 14.72 | 12.88 | ||||||||||||||||||
| Eagle Ford |
24.65 | 22.28 | 22.85 | 23.03 | 28.65 | 26.40 | ||||||||||||||||||
| Anadarko Basin |
22.84 | 21.50 | 20.94 | 22.41 | 26.91 | 25.45 | ||||||||||||||||||
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| Realized price without hedges |
18.28 | 16.86 | 17.01 | 17.71 | 22.03 | 21.07 | ||||||||||||||||||
| Cash settlements |
0.11 | 0.23 | 0.17 | 0.11 | (0.10 | ) | (0.06 | ) | ||||||||||||||||
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| Realized price, including cash settlements |
$ | 18.39 | $ | 17.09 | $ | 17.18 | $ | 17.82 | $ | 21.93 | $ | 21.01 | ||||||||||||
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| Gas (Per Mcf) |
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| Delaware Basin |
$ | 1.54 | $ | 0.96 | $ | 1.50 | $ | 1.34 | $ | 2.47 | $ | 1.01 | ||||||||||||
| Rockies |
0.22 | 0.33 | (0.42 | ) | (0.50 | ) | 1.48 | 0.59 | ||||||||||||||||
| Eagle Ford |
3.11 | 3.14 | 2.78 | 3.01 | 3.36 | 2.31 | ||||||||||||||||||
| Anadarko Basin |
2.98 | 3.13 | 2.57 | 2.86 | 3.42 | 2.27 | ||||||||||||||||||
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| Realized price without hedges |
1.67 | 1.33 | 1.43 | 1.41 | 2.55 | 1.30 | ||||||||||||||||||
| Cash settlements |
0.12 | 0.25 | 0.15 | 0.15 | (0.07 | ) | 0.16 | |||||||||||||||||
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| Realized price, including cash settlements |
$ | 1.79 | $ | 1.58 | $ | 1.58 | $ | 1.56 | $ | 2.48 | $ | 1.46 | ||||||||||||
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| Total oil equivalent (Per Boe) |
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| Delaware Basin |
$ | 36.75 | $ | 32.72 | $ | 36.18 | $ | 35.92 | $ | 43.00 | $ | 39.66 | ||||||||||||
| Rockies |
36.22 | 32.04 | 35.33 | 34.29 | 43.29 | 41.37 | ||||||||||||||||||
| Eagle Ford |
48.32 | 45.82 | 48.85 | 48.32 | 49.75 | 46.46 | ||||||||||||||||||
| Anadarko Basin |
26.12 | 25.62 | 23.97 | 25.28 | 29.96 | 26.54 | ||||||||||||||||||
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| Realized price without hedges |
36.60 | 32.92 | 35.82 | 35.43 | 42.58 | 39.57 | ||||||||||||||||||
| Cash settlements |
0.76 | 1.60 | 0.64 | 0.87 | (0.13 | ) | 0.75 | |||||||||||||||||
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| Realized price, including cash settlements |
$ | 37.36 | $ | 34.52 | $ | 36.46 | $ | 36.30 | $ | 42.45 | $ | 40.32 | ||||||||||||
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9
ASSET MARGINS
| BENCHMARK PRICES | 2025 | 2024 | ||||||||||||||||||||||
| (average prices) | Full Year | Quarter 4 | Quarter 3 | Quarter 2 | Quarter 1 | Quarter 4 | ||||||||||||||||||
| Oil ($/Bbl) - West Texas Intermediate (Cushing) |
$ | 64.87 | $ | 59.09 | $ | 64.92 | $ | 63.95 | $ | 71.50 | $ | 70.32 | ||||||||||||
| Natural Gas ($/Mcf) - Henry Hub |
$ | 3.43 | $ | 3.55 | $ | 3.07 | $ | 3.44 | $ | 3.65 | $ | 2.79 | ||||||||||||
| NGL ($/Bbl) - Mont Belvieu Blended |
$ | 25.79 | $ | 23.67 | $ | 24.25 | $ | 25.58 | $ | 29.65 | $ | 27.80 | ||||||||||||
| PER-UNIT CASH MARGIN BY ASSET (per Boe) | 2025 | 2024 | ||||||||||||||||||||||
| Full Year | Quarter 4 | Quarter 3 | Quarter 2 | Quarter 1 | Quarter 4 | |||||||||||||||||||
| Delaware Basin |
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| Realized price |
$ | 36.75 | $ | 32.72 | $ | 36.18 | $ | 35.92 | $ | 43.00 | $ | 39.66 | ||||||||||||
| Lease operating expenses |
(5.43 | ) | (5.11 | ) | (5.38 | ) | (5.54 | ) | (5.74 | ) | (4.93 | ) | ||||||||||||
| Gathering, processing & transportation |
(2.91 | ) | (2.57 | ) | (2.94 | ) | (3.17 | ) | (3.00 | ) | (2.92 | ) | ||||||||||||
| Production & property taxes |
(2.67 | ) | (2.44 | ) | (2.52 | ) | (2.63 | ) | (3.13 | ) | (2.91 | ) | ||||||||||||
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| Field-level cash margin |
$ | 25.74 | $ | 22.60 | $ | 25.34 | $ | 24.58 | $ | 31.13 | $ | 28.90 | ||||||||||||
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| Rockies |
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| Realized price |
$ | 36.22 | $ | 32.04 | $ | 35.33 | $ | 34.29 | $ | 43.29 | $ | 41.37 | ||||||||||||
| Lease operating expenses |
(8.93 | ) | (9.05 | ) | (8.27 | ) | (9.13 | ) | (9.31 | ) | (8.63 | ) | ||||||||||||
| Gathering, processing & transportation |
(1.01 | ) | (1.03 | ) | (0.99 | ) | (0.86 | ) | (1.14 | ) | (1.22 | ) | ||||||||||||
| Production & property taxes |
(3.08 | ) | (2.64 | ) | (3.04 | ) | (2.85 | ) | (3.83 | ) | (3.66 | ) | ||||||||||||
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| Field-level cash margin |
$ | 23.20 | $ | 19.32 | $ | 23.03 | $ | 21.45 | $ | 29.01 | $ | 27.86 | ||||||||||||
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| Eagle Ford |
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| Realized price |
$ | 48.32 | $ | 45.82 | $ | 48.85 | $ | 48.32 | $ | 49.75 | $ | 46.46 | ||||||||||||
| Lease operating expenses |
(7.42 | ) | (7.90 | ) | (7.83 | ) | (7.52 | ) | (6.65 | ) | (5.59 | ) | ||||||||||||
| Gathering, processing & transportation |
(2.19 | ) | (1.98 | ) | (2.27 | ) | (1.94 | ) | (2.47 | ) | (2.21 | ) | ||||||||||||
| Production & property taxes |
(2.75 | ) | (2.43 | ) | (2.89 | ) | (3.02 | ) | (2.65 | ) | (2.41 | ) | ||||||||||||
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| Field-level cash margin |
$ | 35.96 | $ | 33.51 | $ | 35.86 | $ | 35.84 | $ | 37.98 | $ | 36.25 | ||||||||||||
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| Anadarko Basin |
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| Realized price |
$ | 26.12 | $ | 25.62 | $ | 23.97 | $ | 25.28 | $ | 29.96 | $ | 26.54 | ||||||||||||
| Lease operating expenses |
(3.15 | ) | (3.19 | ) | (3.25 | ) | (2.98 | ) | (3.20 | ) | (2.72 | ) | ||||||||||||
| Gathering, processing & transportation |
(6.08 | ) | (6.19 | ) | (5.98 | ) | (6.13 | ) | (6.01 | ) | (5.74 | ) | ||||||||||||
| Production & property taxes |
(1.35 | ) | (1.22 | ) | (1.30 | ) | (1.32 | ) | (1.62 | ) | (1.20 | ) | ||||||||||||
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| Field-level cash margin |
$ | 15.54 | $ | 15.02 | $ | 13.44 | $ | 14.85 | $ | 19.13 | $ | 16.88 | ||||||||||||
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| Devon - Total |
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| Realized price |
$ | 36.60 | $ | 32.92 | $ | 35.82 | $ | 35.43 | $ | 42.58 | $ | 39.57 | ||||||||||||
| Lease operating expenses |
(6.27 | ) | (6.11 | ) | (6.14 | ) | (6.31 | ) | (6.53 | ) | (5.70 | ) | ||||||||||||
| Gathering, processing & transportation |
(2.71 | ) | (2.49 | ) | (2.71 | ) | (2.86 | ) | (2.78 | ) | (2.74 | ) | ||||||||||||
| Production & property taxes |
(2.65 | ) | (2.39 | ) | (2.56 | ) | (2.58 | ) | (3.11 | ) | (2.86 | ) | ||||||||||||
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| Field-level cash margin |
$ | 24.97 | $ | 21.93 | $ | 24.41 | $ | 23.68 | $ | 30.16 | $ | 28.27 | ||||||||||||
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10
NON-GAAP MEASURES
(all monetary values in millions, except per share amounts)
Devon’s earnings materials include non-GAAP financial measures. These non-GAAP measures are not alternatives to GAAP measures, and you should not consider these non-GAAP measures in isolation or as a substitute for analysis of our results as reported under GAAP. Below is additional disclosure regarding each of the non-GAAP measures used in the earnings materials, including reconciliations to their most directly comparable GAAP measure.
The earnings materials may include forward-looking non-GAAP measures. The company is unable to provide reconciliations of these forward-looking non-GAAP measures, because components of the calculations are inherently unpredictable, such as changes to current assets and liabilities, the timing of changes in capital accruals, unknown future events and estimating certain future GAAP measures. The inability to reliably quantify certain components of the calculation would significantly affect the usefulness and accuracy of a reconciliation.
CORE EARNINGS
Devon’s reported net earnings include items of income and expense that are typically excluded by securities analysts in their published estimates of the company’s financial results. Accordingly, the company also uses the measures of core earnings and core earnings per share attributable to Devon. Devon believes these non-GAAP measures facilitate comparisons of its performance to earnings estimates published by securities analysts. Devon also believes these non-GAAP measures can facilitate comparisons of its performance between periods and to the performance of its peers. The following table summarizes the effects of these items on full-year and fourth-quarter 2025 earnings.
| Year Ended December 31, 2025 | ||||||||||||||||
| Before-tax | After-tax | After NCI | Per Diluted Share |
|||||||||||||
| Total |
||||||||||||||||
| Earnings (GAAP) |
$ | 3,466 | $ | 2,681 | $ | 2,642 | $ | 4.17 | ||||||||
| Adjustments: |
||||||||||||||||
| Asset dispositions |
(343 | ) | (266 | ) | (266 | ) | (0.42 | ) | ||||||||
| Asset and exploration impairments |
265 | 206 | 206 | 0.33 | ||||||||||||
| Change in tax legislation |
— | 5 | 5 | 0.01 | ||||||||||||
| Fair value changes in financial instruments |
(172 | ) | (134 | ) | (134 | ) | (0.21 | ) | ||||||||
| Restructuring and transaction costs |
36 | 28 | 28 | 0.04 | ||||||||||||
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| Core earnings (Non-GAAP) |
$ | 3,252 | $ | 2,520 | $ | 2,481 | $ | 3.92 | ||||||||
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| Quarter Ended December 31, 2025 | ||||||||||||||||
| Before-tax | After-tax | After NCI | Per Diluted Share |
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| Total |
||||||||||||||||
| Earnings (GAAP) |
$ | 747 | $ | 562 | $ | 562 | $ | 0.90 | ||||||||
| Adjustments: |
||||||||||||||||
| Asset dispositions |
(1 | ) | — | — | — | |||||||||||
| Asset and exploration impairments |
1 | 1 | 1 | — | ||||||||||||
| Change in tax legislation |
— | (6 | ) | (6 | ) | (0.01 | ) | |||||||||
| Fair value changes in financial instruments |
(59 | ) | (47 | ) | (47 | ) | (0.07 | ) | ||||||||
| Restructuring and transaction costs |
— | — | — | — | ||||||||||||
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| Core earnings (Non-GAAP) |
$ | 688 | $ | 510 | $ | 510 | $ | 0.82 | ||||||||
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11
EBITDAX
Devon believes EBITDAX provides information useful in assessing operating and financial performance across periods. Devon computes EBITDAX as net earnings before financing costs, net; income tax expense; exploration expenses; depreciation, depletion and amortization; asset impairments; asset disposition gains and losses; non-cash share-based compensation; non-cash valuation changes for derivatives and financial instruments; accretion on discounted liabilities; and other items not related to core operations. EBITDAX as defined by Devon may not be comparable to similarly titled measures used by other companies.
| Q4 ‘25 | Q3 ‘25 | Q2 ‘25 | Q1 ‘25 | TTM | Q4 ‘24 | |||||||||||||||||||
| Net earnings (GAAP) |
$ | 562 | $ | 693 | $ | 917 | $ | 509 | $ | 2,681 | $ | 653 | ||||||||||||
| Financing costs, net |
107 | 109 | 116 | 123 | 455 | 123 | ||||||||||||||||||
| Income tax expense |
185 | 219 | 244 | 137 | 785 | 187 | ||||||||||||||||||
| Exploration expenses |
5 | 8 | 20 | 10 | 43 | 12 | ||||||||||||||||||
| Depreciation, depletion and amortization |
890 | 879 | 914 | 912 | 3,595 | 971 | ||||||||||||||||||
| Asset impairments |
— | — | — | 254 | 254 | — | ||||||||||||||||||
| Asset dispositions |
(1 | ) | (37 | ) | (307 | ) | 2 | (343 | ) | (5 | ) | |||||||||||||
| Share-based compensation |
22 | 21 | 22 | 24 | 89 | 24 | ||||||||||||||||||
| Derivative & financial instrument non-cash val. changes |
(59 | ) | (30 | ) | (169 | ) | 88 | (170 | ) | 142 | ||||||||||||||
| Accretion on discounted liabilities and other |
(12 | ) | (2 | ) | 11 | 27 | 24 | 24 | ||||||||||||||||
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| EBITDAX (Non-GAAP) |
$ | 1,699 | $ | 1,860 | $ | 1,768 | $ | 2,086 | $ | 7,413 | $ | 2,131 | ||||||||||||
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NET DEBT
Devon defines net debt as debt (includes short-term and long-term debt) less cash, cash equivalents and restricted cash. Devon believes that netting these sources of cash against debt provides a clearer picture of the future demands on cash from Devon to repay debt.
| 2025 | 2024 | |||||||||||||||||||
| Quarter 4 | Quarter 3 | Quarter 2 | Quarter 1 | Quarter 4 | ||||||||||||||||
| Total debt (GAAP) |
$ | 8,389 | $ | 8,391 | $ | 8,878 | $ | 8,880 | $ | 8,883 | ||||||||||
| Less: |
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| Cash, cash equivalents and restricted cash |
(1,434 | ) | (1,278 | ) | (1,759 | ) | (1,234 | ) | (846 | ) | ||||||||||
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| Net debt (Non-GAAP) |
$ | 6,955 | $ | 7,113 | $ | 7,119 | $ | 7,646 | $ | 8,037 | ||||||||||
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NET DEBT-TO-EBITDAX
Devon defines net debt-to-EBITDAX as net debt divided by an annualized EBITDAX measure. Devon believes this ratio provides information useful to investors in assessing the company’s credit position and debt leverage.
| 2025 | 2024 | |||||||||||||||||||
| Quarter 4 | Quarter 3 | Quarter 2 | Quarter 1 | Quarter 4 | ||||||||||||||||
| Net debt (Non-GAAP) |
$ | 6,955 | $ | 7,113 | $ | 7,119 | $ | 7,646 | $ | 8,037 | ||||||||||
| EBITDAX (Non-GAAP) (1) |
$ | 7,413 | $ | 7,845 | $ | 7,838 | $ | 8,034 | $ | 7,739 | ||||||||||
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| Net debt-to-EBITDAX (Non-GAAP) |
0.9 | 0.9 | 0.9 | 1.0 | 1.0 | |||||||||||||||
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| (1) | EBITDAX is an annualized measure using a trailing twelve-month calculation. |
12
FREE CASH FLOW
Devon defines free cash flow as total operating cash flow less capital expenditures. Devon believes free cash flow provides a useful measure of available cash generated by operating activities for other investing and financing activities.
| 2025 | 2024 | |||||||||||||||||||||||
| Full Year | Quarter 4 | Quarter 3 | Quarter 2 | Quarter 1 | Quarter 4 | |||||||||||||||||||
| Total operating cash flow (GAAP) |
$ | 6,711 | $ | 1,534 | $ | 1,690 | $ | 1,545 | $ | 1,942 | $ | 1,664 | ||||||||||||
| Less capital expenditures (Excluding acquisitions): |
(3,592 | ) | (832 | ) | (870 | ) | (956 | ) | (934 | ) | (926 | ) | ||||||||||||
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| Free cash flow (Non-GAAP) |
$ | 3,119 | $ | 702 | $ | 820 | $ | 589 | $ | 1,008 | $ | 738 | ||||||||||||
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REINVESTMENT RATE
Devon defines reinvestment rate as accrued capital expenditures divided by operating cash flow. Devon believes this measure provides useful information to our investors as an indicator of the capital demands of our business relative to the cash flow generated from normal business operations.
| 2025 | 2024 | |||||||||||||||||||||||
| Full Year | Quarter 4 | Quarter 3 | Quarter 2 | Quarter 1 | Quarter 4 | |||||||||||||||||||
| Capital expenditures (Accrued) |
$ | 4,000 | $ | 1,024 | $ | 1,056 | $ | 948 | $ | 972 | $ | 1,042 | ||||||||||||
| Operating cash flow |
$ | 6,711 | $ | 1,534 | $ | 1,690 | $ | 1,545 | $ | 1,942 | $ | 1,664 | ||||||||||||
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| Reinvestment rate (Non-GAAP) |
60 | % | 67 | % | 63 | % | 61 | % | 50 | % | 63 | % | ||||||||||||
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13
| FIRST-QUARTER AND FULL-YEAR 2026 GUIDANCE |
| |||
Note: Devon’s full-year 2026 guidance reflects standalone Devon operations. Upon the expected closure of the Devon and Coterra merger in the second quarter of 2026, the company will provide updated full-year guidance for the combined entity at close.
| PRODUCTION GUIDANCE | ||||||||||||||||
| Quarter 1 (1) | Full Year | |||||||||||||||
| Low | High | Low | High | |||||||||||||
| Oil (MBbls/d) |
381 | 387 | 385 | 391 | ||||||||||||
| Natural gas liquids (MBbls/d) |
217 | 223 | 223 | 229 | ||||||||||||
| Gas (MMcf/d) |
1,350 | 1,400 | 1,360 | 1,410 | ||||||||||||
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| Total oil equivalent (MBoe/d) |
823 | 843 | 835 | 855 | ||||||||||||
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| (1) | Production in the first quarter of 2026 is estimated to be reduced by 1 percent or 10,000 Boe per day (50% oil) due to the impact of severe winter weather. |
| CAPITAL EXPENDITURES GUIDANCE | ||||||||||||||||
| Quarter 1 | Full Year | |||||||||||||||
| (in millions) | Low | High | Low | High | ||||||||||||
| Upstream capital |
$ | 850 | $ | 900 | $ | 3,425 | $ | 3,575 | ||||||||
| Midstream and other capital |
20 | 30 | 75 | 125 | ||||||||||||
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| Total capital |
$ | 870 | $ | 930 | $ | 3,500 | $ | 3,700 | ||||||||
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| PRICE REALIZATIONS GUIDANCE | ||||||||||||||||
| Quarter 1 | Full Year | |||||||||||||||
| Low | High | Low | High | |||||||||||||
| Oil - % of WTI |
95 | % | 99 | % | 95 | % | 99 | % | ||||||||
| NGL - % of WTI |
28 | % | 32 | % | 28 | % | 32 | % | ||||||||
| Natural gas - % of Henry Hub |
40 | % | 50 | % | 40 | % | 50 | % | ||||||||
| OTHER GUIDANCE ITEMS | ||||||||||||||||
| Quarter 1 | Full Year | |||||||||||||||
| ($ millions, except Boe and %) | Low | High | Low | High | ||||||||||||
| Marketing and midstream operating profit |
$ | (50 | ) | $ | (40 | ) | $ | (100 | ) | $ | (80 | ) | ||||
| LOE and GP&T per BOE |
$ | 8.80 | $ | 9.10 | $ | 8.50 | $ | 8.70 | ||||||||
| Production and property taxes as % of upstream sales |
7.0 | % | 7.5 | % | 7.0 | % | 7.5 | % | ||||||||
| Exploration expenses |
$ | 15 | $ | 25 | $ | 30 | $ | 40 | ||||||||
| Depreciation, depletion and amortization |
$ | 900 | $ | 940 | $ | 3,725 | $ | 3,825 | ||||||||
| General and administrative expenses |
$ | 115 | $ | 125 | $ | 460 | $ | 500 | ||||||||
| Financing costs, net |
$ | 100 | $ | 110 | $ | 400 | $ | 420 | ||||||||
| Other expenses |
$ | — | $ | 10 | $ | 15 | $ | 25 | ||||||||
| INCOME TAX GUIDANCE | ||||||||||||||||
| Quarter 1 | Full Year | |||||||||||||||
| (% of pre-tax earnings) | Low | High | Low | High | ||||||||||||
| Current income tax rate |
0 | % | 2 | % | 0 | % | 2 | % | ||||||||
| Deferred income tax rate |
20 | % | 22 | % | 20 | % | 22 | % | ||||||||
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| Total income tax rate |
~22% | ~22% | ||||||||||||||
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| 2026 & 2027 HEDGING POSITIONS |
|
| Oil Commodity Hedges | ||||||||||||||||
| Three Way Collars | ||||||||||||||||
| Period |
Volume (Bbls/d) | Weighted Average Floor Sold Price ($/Bbl) |
Weighted Average Floor Purchased Price ($/Bbl) |
Weighted Average Ceiling Price ($/Bbl) |
||||||||||||
| Q1-Q2 2026 |
100,000 | $ | 49.86 | $ | 60.11 | $ | 72.07 | |||||||||
| Q3-Q4 2026 |
107,000 | $ | 49.61 | $ | 59.61 | $ | 71.06 | |||||||||
| Q1-Q4 2027 |
6,942 | $ | 47.64 | $ | 57.64 | $ | 65.84 | |||||||||
| Oil Basis Swaps | ||||||||||
| Period |
Index | Volume (Bbls/d) | Weighted Average Differential to WTI ($/Bbl) |
|||||||
| Q1-Q4 2026 |
Midland Sweet | 46,000 | $ | 1.10 | ||||||
| Q1-Q2 2026 |
NYMEX Roll | 48,000 | $ | 0.10 | ||||||
| Q1-Q4 2027 |
Midland Sweet | 16,000 | $ | 1.04 | ||||||
| Natural Gas Commodity Hedges - Henry Hub | ||||||||||||||||||||
| Price Swaps | Price Collars | |||||||||||||||||||
| Period |
Volume (MMBtu/d) | Weighted Average Price ($/MMBtu) |
Volume (MMBtu/d) |
Weighted Average Floor Price ($/MMBtu) |
Weighted Average Ceiling Price ($/ MMBtu) |
|||||||||||||||
| Q1 2026-Q4 2026 |
247,500 | $ | 3.80 | 220,000 | $ | 3.24 | $ | 4.92 | ||||||||||||
| Natural Gas Basis Swaps | ||||||||||
| Period |
Index | Volume (MMBtu/d) | Weighted Average Differential to Henry Hub ($/MMBtu) |
|||||||
| Q1–Q4 2026 |
Houston Ship Channel | 50,000 | $ | (0.29 | ) | |||||
| Q1–Q4 2026 |
WAHA | 150,000 | $ | (1.79 | ) | |||||
Devon’s oil derivatives settle against the average of the prompt month NYMEX West Texas Intermediate futures price. Devon’s natural gas derivatives settle against the Inside FERC first of the month Henry Hub index. Devon’s NGL derivatives settle against the average of the prompt month OPIS Mont Belvieu, Texas index. Commodity hedge positions are shown as of December 31, 2025.
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