Coterra Energy Reports 2025 Results, Provides 2026 Guidance, and Announces Quarterly Dividend
Tom Jorden, Chairman, CEO and President of Coterra, noted, “Coterra's strong fourth-quarter and full-year 2025 results were driven by efficient capital allocation and strong execution, and are a testament to the quality of our assets and the dedication and professionalism of our employees. Prioritizing safety, financial strength, and shareholder value creation, Coterra is well positioned for a highly capital efficient 2026.
We are excited about the announced merger with Devon Energy and the opportunities created by the combined company. We remain focused on operational excellence and are preparing to integrate the two companies to unlock the value potential of the combined portfolio. This powerful combination builds directly on the foundation we have established, bringing together complementary assets and shared values, including rigorous economic evaluation, disciplined execution, and a common commitment to shareholder value creation. The combined company will have an advantaged platform as a
Key Takeaways & Updates
Fourth quarter 2025: Efficient Execution and Strong Well Results Drove Production Beat
- Total barrels of oil equivalent (BOE) and natural gas production beat the high-end of guidance, while oil production beat the midpoint of guidance.
-
Generated
$970 million $507 million -
Returned
$263 million $170 million $93 million $24.37 -
Repaid
$100 million $300 million -
Total shareholder returns, including declared dividends, share repurchases, and debt redemption, represented
72% of Free Cash Flow (non-GAAP).
Full-year 2025: Highly Capital Efficient Program, Strong Sequential Oil Volume Growth, and Successful Integration of
-
Total BOE and natural gas production exceeded the high-end of our original February 2025 guidance and exceeded the mid-point by
6% and7% , respectively, while oil production came in at the mid-point of guidance. -
Completed the integration of
Delaware Basin acquisitions (closed in January 2025). Continue to see strong operational execution and upside from the development of new landing zones, lower operating costs, and optimization of midstream commitments. -
Generated
$4.0 billion $2.0 billion 44% and67% , respectively, from 2024 levels. -
Annual reinvestment rate was
54% .
2026 Guidance: Disciplined Capital Investment; Consistent with Outlook Provided in November 2025
- 2026 guidance presented reflects Coterra standalone operations. Following the closing of the Devon and Coterra merger, expected in the second quarter of 2026, full-year guidance for the combined entity will be provided. For more details on annual 2026 guidance, see 2026 Guidance Section in the tables below.
- Expect annual total production of 750 to 810 MBoepd (thousand barrels of oil equivalent per day), natural gas production of 2,775 to 2,975 MMcfpd (million cubic feet per day), and oil production of 162 to 172 MBopd (thousand barrels of oil per day), in-line with our 2026 outlook provided in November 2025. Our full-year guidance includes the first-quarter impact of winter storm Fern, which is estimated to have had a negative 1.6 MBoepd and 0.7 MBopd annual impact. We anticipate that, including the impact of winter storm Fern, the first quarter will be below the annual average daily production.
-
Full-year 2026 capital expenditures of
$2.25 billion $2.17 5$2.32 5 billion -
Based on recent strip prices and mid-point of capital expenditures, expect reinvestment rate of approximately
50% and Free Cash Flow (non-GAAP) of$2.35 billion
Transformative Merger with Devon Energy
On February 2, 2026, we announced that we had entered into an agreement with Devon Energy (NYSE: DVN) ("Devon") to combine via an all-stock merger, creating an industry-leading shale operator with a flagship
The combined entity is expected to unlock substantial value for shareholders, including enhanced Free Cash Flow supported by a balanced commodity mix and diversified assets, unleashing complementary AI capabilities across the enterprise, exceptional synergy potential, and maintaining a strong balance sheet.
Transition planning efforts are underway, led by a team comprised of senior leaders from both companies. In addition to their integration responsibilities, the integration team will also be heavily focused on organization structure and fit, targeting pre-tax synergy capture of
The combined company proposes a compelling investment opportunity, offering scale, quality, and an industry-leading balance sheet.
Under the terms of the agreement, Coterra shareholders will receive a fixed exchange ratio of 0.70 share of Devon common stock for each share of Coterra common stock. Upon completion, Devon shareholders will own approximately
The transaction is expected to close in the second quarter of 2026 and has been unanimously approved by the boards of directors of both companies. The closing of the transaction is subject to customary closing conditions, including approvals from Devon and Coterra shareholders.
Shareholder Return Highlights
-
Common Dividend: On February 26, 2026, Coterra's Board of Directors approved a quarterly dividend of
$0.22 2.9% annualized yield, based on the Company's$29.90 -
Share Repurchases: During the quarter, the Company repurchased 4 million shares for
$93 million $24.37 $140 million $24.92 -
Debt Retirement: During the quarter, the Company paid off
$100 million $1.0 billion $700 million $1.0 billion $300 million -
Total Shareholder Return: During the quarter, shareholder returns amounted to
$263 million $170 million $93 million $820 million $680 million $140 million 75% of Free Cash Flow (non-GAAP).
Strong Financial Position
The Company ended the year with a cash balance of
See “Supplemental Non-GAAP Financial Measures” below for descriptions of the above non-GAAP measures as well as reconciliations of these measures to the associated GAAP measures.
2025 Proved Reserves
At December 31, 2025, Coterra's proved reserves totaled 2,565 million barrels of oil equivalent (MMBoe), up approximately
The Company had positive net revisions of prior estimates of 162 MMBoe. This positive revision included a positive 96 MMBoe performance revision and 66 MMBoe due to positive price revisions. The Company also added 167 MMBoe related to acquisitions.
Proved developed producing reserves were up
SEC realized commodity prices used to calculate our proved reserves in 2025 for oil, natural gas liquids and natural gas, adjusted for basis and quality differentials, are
For a summary of Coterra's estimated proved reserves at December 31, 2025, see the "Year-End Proved Reserves" table below and in our annual report on Form 10-K for the fiscal year ended December 31, 2025.
Committed to Sustainability and ESG Leadership
Coterra is committed to environmental stewardship, sustainable practices, and strong corporate governance. The Company's sustainability report can be found under "Sustainability" on www.coterra.com.
Conference Call
Due to the pending merger with Devon, Coterra will not host a conference call or webcast to discuss its 2025 results.
The related earnings presentation can be accessed on the "Events & Presentations" page under the "Investors" section of the Company's website at www.coterra.com.
About Coterra Energy
Coterra is a premier exploration and production company based in
Additional Information and Where to Find It
In connection with the proposed merger (the “Proposed Transaction”) of Devon Energy Corporation (“Devon”) and Coterra, Devon will file with the Securities and Exchange Commission (the “SEC”) a registration statement on Form S-4 to register the shares of Devon’s common stock to be issued in connection with the Proposed Transaction. The registration statement will include a document that serves as a prospectus of Devon and a joint proxy statement of each of Devon and Coterra (the “joint proxy statement/prospectus”), and each party will file other documents regarding the Proposed Transaction with the SEC. INVESTORS AND SECURITY HOLDERS OF DEVON AND COTERRA ARE URGED TO READ THE REGISTRATION STATEMENT, THE JOINT PROXY STATEMENT/PROSPECTUS, INCLUDING ANY AMENDMENTS OR SUPPLEMENTS TO THOSE DOCUMENTS, AND ANY OTHER RELEVANT DOCUMENTS THAT WILL BE FILED WITH THE SEC CAREFULLY AND IN THEIR ENTIRETY WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT DEVON, COTERRA, THE PROPOSED TRANSACTION AND RELATED MATTERS. A definitive joint proxy statement/prospectus will be sent to stockholders of each of Devon and Coterra when it becomes available. Investors and security holders will be able to obtain copies of the registration statement and the joint proxy statement/prospectus and other documents containing important information about Devon and Coterra free of charge from the SEC’s website when it becomes available. The documents filed by Devon with the SEC may be obtained free of charge at Devon’s website at investors.devonenergy.com or at the SEC’s website at www.sec.gov. These documents may also be obtained free of charge from Devon by requesting them by mail at Devon, Attn. Investor Relations, 333 West Sheridan Ave,
Participants in the Solicitation
Devon, Coterra and certain of their respective directors, executive officers and other members of management and employees may be deemed to be participants in the solicitation of proxies from Devon’s and Coterra’s stockholders with respect to the Proposed Transaction. Information about Devon’s directors and executive officers is available in Devon’s Annual Report on Form 10-K for the 2025 fiscal year filed with the SEC on February 18, 2026 (and which is available at https://www.sec.gov/ix?doc=/Archives/edgar/data/0001090012/000119312526056485/dvn-20251231.htm), and its definitive proxy statement for the 2025 annual meeting of shareholders filed with the SEC on April 23, 2025 (and which is available at https://www.sec.gov/ix?doc=/Archives/edgar/data/0001090012/000110465925037545/tm252204-6_def14a.htm). Information about Coterra’s directors and executive officers is available in Coterra’s Annual Report on Form 10-K for the 2024 fiscal year filed with the SEC on February 25, 2025 (and which is available at https://www.sec.gov/ix?doc=/Archives/edgar/data/0000858470/000085847025000075/cog-20241231.htm), and its definitive proxy statement for the 2025 annual meeting of shareholders filed with the SEC on March 20, 2025 (and which is available at https://www.sec.gov/ix?doc=/Archives/edgar/data/0000858470/000110465925026126/tm2429648-2_def14a.htm). Other information regarding the participants in the proxy solicitation and a description of their direct and indirect interests, by security holdings or otherwise, will be contained in the registration statement, the joint proxy statement/prospectus and other relevant materials to be filed with the SEC regarding the Proposed Transaction when they become available. Stockholders, potential investors and other readers should read the joint proxy statement/prospectus carefully when it becomes available before making any voting or investment decisions.
No Offer or Solicitation
This communication is not intended to and shall not constitute an offer to sell or the solicitation of an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote of approval, nor shall there be any sale of securities in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended.
Cautionary Statement Regarding Forward-Looking Information
This press release contains certain forward-looking statements within the meaning of federal securities laws. Forward-looking statements are not statements of historical fact and reflect Coterra's current views about future events. Such forward-looking statements include, but are not limited to, statements about the Proposed Transaction, returns to shareholders (including anticipated future dividend increases), enhanced shareholder value, reserves estimates, future financial and operating performance, and goals and commitment to sustainability and ESG leadership, strategic pursuits and goals, including with respect to the publication of Coterra’s Sustainability Report, and other statements that are not historical facts contained in this press release. The words "expect," "project," "estimate," "believe," "anticipate," "intend," "budget," "plan," "predict," "potential," "possible," "may," "should," "could," "would," "will," "strategy," "outlook", "guide" and similar expressions are also intended to identify forward-looking statements. We can provide no assurance that the forward-looking statements contained in this press release will occur as projected and actual results may differ materially from those projected. Forward-looking statements are based on current expectations, estimates and assumptions that involve a number of risks and uncertainties that could cause actual results to differ materially from those projected. These risks and uncertainties include, without limitation, the risk that Devon or Coterra may be unable to obtain regulatory and shareholder approvals required for the Proposed Transaction or that required governmental and regulatory approvals may delay the Proposed Transaction or result in the imposition of conditions that could reduce the anticipated benefits from the Proposed Transaction or cause the parties to abandon the Proposed Transaction; the risk that other conditions to closing of the Proposed Transaction may not be satisfied; the length of time necessary to consummate the Proposed Transaction, which may be longer than anticipated for various reasons; the risk that the businesses will not be integrated successfully; the risk that the cost savings, synergies and growth from the Proposed Transaction may not be fully realized or may take longer to realize than expected; the diversion of management time on transaction-related issues; the effect of future regulatory or legislative actions on the companies or the industries in which they operate; the risk that the credit ratings of the combined company or its subsidiaries may be different from what the companies expect; potential liability resulting from pending or future litigation; the potential impact of the announcement or consummation of the Proposed Transaction on relationships with customers, suppliers, competitors, business partners, management and other employees; reliance on and integration of information technology systems; the risks associated with assumptions the parties make in connection with the parties’ critical accounting estimates and legal proceedings; the volatility in commodity prices for crude oil and natural gas; cost increases; the effect of future regulatory or legislative actions; the impact of public health crises, including pandemics (such as the coronavirus pandemic) and epidemics and any related governmental policies or actions on Coterra’s business, financial condition and results of operations; actions by, or disputes among or between, the Organization of Petroleum Exporting Countries and other producer countries; market factors; market prices (including geographic basis differentials) of oil and natural gas; impacts of inflation; labor shortages and economic disruption (including as a result of geopolitical disruptions such as the war in
Forward-looking statements are based on the estimates and opinions of management at the time the statements are made. Except to the extent required by applicable law, Coterra does not undertake any obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. Readers are cautioned not to place undue reliance on these forward-looking statements that speak only as of the date hereof.
Operational Data
The tables below provide a summary of production volumes, price realizations and operational activity by region and units costs for the Company for the periods indicated:
|
Quarter Ended December 31, |
|
Twelve Months Ended December 31, |
|||||||||
|
2025 |
|
2024 |
|
2025 |
|
2024 |
|||||
PRODUCTION VOLUMES |
|
|
|
|
|
|
|
|||||
Marcellus Shale |
|
|
|
|
|
|
|
|||||
Natural gas (Mmcf/day) |
|
1,946.1 |
|
|
|
2,042.8 |
|
|
2,053.4 |
|
|
2,098.5 |
Daily equivalent production (MBoepd) |
|
324.4 |
|
|
|
340.5 |
|
|
342.2 |
|
|
349.7 |
|
|
|
|
|
|
|
|
|||||
Permian Basin |
|
|
|
|
|
|
|
|||||
Natural gas (Mmcf/day) |
|
738.7 |
|
|
|
517.5 |
|
|
653.5 |
|
|
505.1 |
Oil (MBbl/day) |
|
165.1 |
|
|
|
103.8 |
|
|
151.7 |
|
|
100.8 |
NGL (MBbl/day) |
|
110.8 |
|
|
|
78.3 |
|
|
96.7 |
|
|
77.3 |
Daily equivalent production (MBoepd) |
|
399.0 |
|
|
|
268.3 |
|
|
357.4 |
|
|
262.2 |
|
|
|
|
|
|
|
|
|||||
|
|
|
|
|
|
|
|
|||||
Natural gas (Mmcf/day) |
|
277.3 |
|
|
|
217.2 |
|
|
266.5 |
|
|
194.3 |
Oil (MBbl/day) |
|
10.7 |
|
|
|
9.1 |
|
|
8.1 |
|
|
7.9 |
NGL (MBbl/day) |
|
32.6 |
|
|
|
27.1 |
|
|
29.9 |
|
|
23.7 |
Daily equivalent production (MBoepd) |
|
89.5 |
|
|
|
72.4 |
|
|
82.4 |
|
|
64.0 |
|
|
|
|
|
|
|
|
|||||
Total Company |
|
|
|
|
|
|
|
|||||
Natural gas (Mmcf/day) |
|
2,963.5 |
|
|
|
2,778.9 |
|
|
2,974.7 |
|
|
2,799.8 |
Oil (MBbl/day) |
|
175.8 |
|
|
|
113.0 |
|
|
159.9 |
|
|
108.8 |
NGL (MBbl/day) |
|
143.4 |
|
|
|
105.4 |
|
|
126.7 |
|
|
101.1 |
Daily equivalent production (MBoepd) |
|
813.1 |
|
|
|
681.5 |
|
|
782.4 |
|
|
676.5 |
|
|
|
|
|
|
|
|
|||||
AVERAGE SALES PRICE (excluding hedges) |
|
|
|
|
|
|
||||||
Marcellus Shale |
|
|
|
|
|
|
|
|||||
Natural gas ($/Mcf) |
$ |
3.18 |
|
|
$ |
2.27 |
|
$ |
2.93 |
|
$ |
1.98 |
|
|
|
|
|
|
|
|
|||||
Permian Basin |
|
|
|
|
|
|
|
|||||
Natural gas ($/Mcf) |
$ |
(0.52 |
) |
|
$ |
0.79 |
|
$ |
0.60 |
|
$ |
0.16 |
Oil ($/Bbl) |
$ |
58.17 |
|
|
$ |
68.55 |
|
$ |
63.36 |
|
$ |
74.18 |
NGL ($/Bbl) |
$ |
14.76 |
|
|
$ |
20.00 |
|
$ |
17.33 |
|
$ |
19.13 |
|
|
|
|
|
|
|
|
|||||
|
|
|
|
|
|
|
|
|||||
Natural gas ($/Mcf) |
$ |
3.14 |
|
|
$ |
2.51 |
|
$ |
2.97 |
|
$ |
1.92 |
Oil ($/Bbl) |
$ |
58.00 |
|
|
$ |
68.80 |
|
$ |
63.52 |
|
$ |
74.16 |
NGL ($/Bbl) |
$ |
18.56 |
|
|
$ |
23.66 |
|
$ |
21.21 |
|
$ |
22.62 |
|
|
|
|
|
|
|
|
|||||
Total Company |
|
|
|
|
|
|
|
|||||
Natural gas ($/Mcf) |
$ |
2.26 |
|
|
$ |
2.02 |
|
$ |
2.43 |
|
$ |
1.65 |
Oil ($/Bbl) |
$ |
58.16 |
|
|
$ |
68.57 |
|
$ |
63.36 |
|
$ |
74.18 |
NGL ($/Bbl) |
$ |
15.63 |
|
|
$ |
20.94 |
|
$ |
18.24 |
|
$ |
19.95 |
|
Quarter Ended December 31, |
|
Twelve Months Ended December 31, |
||||||||
|
2025 |
|
2024 |
|
2025 |
|
2024 |
||||
AVERAGE SALES PRICE (including hedges) |
|
|
|
|
|
|
|
||||
Total Company |
|
|
|
|
|
|
|
||||
Natural gas ($/Mcf) |
$ |
2.33 |
|
$ |
2.04 |
|
$ |
2.47 |
|
$ |
1.75 |
Oil ($/Bbl) |
$ |
60.34 |
|
$ |
68.70 |
|
$ |
64.35 |
|
$ |
74.22 |
NGL ($/Bbl) |
$ |
15.63 |
|
$ |
20.94 |
|
$ |
18.24 |
|
$ |
19.95 |
|
Quarter Ended December 31, |
|
Twelve Months Ended December 31, |
||||
|
2025 |
|
2024 |
|
2025 |
|
2024 |
WELLS DRILLED(1)(2) |
|
|
|
|
|
|
|
Gross wells |
|
|
|
|
|
|
|
Marcellus Shale |
9 |
|
— |
|
37 |
|
26 |
Permian Basin |
67 |
|
56 |
|
312 |
|
230 |
|
9 |
|
18 |
|
34 |
|
57 |
|
85 |
|
74 |
|
383 |
|
313 |
|
|
|
|
|
|
|
|
Net wells |
|
|
|
|
|
|
|
Marcellus Shale |
9.0 |
|
— |
|
28.4 |
|
25.0 |
Permian Basin |
35.1 |
|
35.3 |
|
156.3 |
|
111.3 |
|
2.6 |
|
3.2 |
|
16.6 |
|
23.1 |
|
46.7 |
|
38.5 |
|
201.3 |
|
159.4 |
|
|
|
|
|
|
|
|
TURN IN LINES(2) |
|
|
|
|
|
|
|
Gross wells |
|
|
|
|
|
|
|
Marcellus Shale |
15 |
|
11 |
|
27 |
|
41 |
Permian Basin |
84 |
|
36 |
|
329 |
|
195 |
|
12 |
|
17 |
|
48 |
|
58 |
|
111 |
|
64 |
|
404 |
|
294 |
|
|
|
|
|
|
|
|
Net wells |
|
|
|
|
|
|
|
Marcellus Shale |
6.4 |
|
11.0 |
|
13.4 |
|
41.0 |
Permian Basin |
42.5 |
|
18.1 |
|
167.0 |
|
86.5 |
|
4.4 |
|
5.6 |
|
19.3 |
|
25.5 |
|
53.3 |
|
34.7 |
|
199.7 |
|
153.0 |
|
|
|
|
|
|
|
|
AVERAGE OPERATED RIG COUNTS |
|
|
|
|
|
|
|
Marcellus Shale |
1.3 |
|
— |
|
1.3 |
|
0.9 |
Permian Basin |
9.0 |
|
8.7 |
|
9.7 |
|
8.2 |
|
1.0 |
|
1.0 |
|
1.7 |
|
1.3 |
| ______________________________ | |
| (1) | Wells drilled represents wells drilled to total depth during the period. |
| (2) | Wells drilled and turn in lines include both operated and non-operated wells. |
|
Quarter Ended December 31, |
|
Twelve Months Ended December 31, |
||||||||
|
2025 |
|
2024 |
|
2025 |
|
2024 |
||||
AVERAGE UNIT COSTS ($/Boe)(1) |
|
|
|
|
|
|
|
||||
Direct operations |
$ |
3.96 |
|
$ |
2.83 |
|
$ |
3.58 |
|
$ |
2.66 |
Gathering, processing and transportation |
|
3.55 |
|
|
3.82 |
|
|
3.81 |
|
|
3.94 |
Taxes other than income |
|
1.21 |
|
|
1.22 |
|
|
1.28 |
|
|
1.09 |
General and administrative (excluding stock-based compensation) |
|
0.57 |
|
|
1.02 |
|
|
0.91 |
|
|
0.97 |
Unit Operating Cost |
$ |
9.29 |
|
$ |
8.89 |
|
$ |
9.58 |
|
$ |
8.66 |
Depreciation, depletion and amortization |
|
8.90 |
|
|
7.75 |
|
|
8.30 |
|
|
7.43 |
Exploration |
|
0.08 |
|
|
0.09 |
|
|
0.09 |
|
|
0.10 |
Stock-based compensation |
|
0.28 |
|
|
0.29 |
|
|
0.22 |
|
|
0.25 |
Interest expense, net |
|
0.62 |
|
|
0.29 |
|
|
0.67 |
|
|
0.18 |
|
$ |
19.17 |
|
$ |
17.31 |
|
$ |
18.86 |
|
$ |
16.62 |
| ______________________________ | |
(1) |
Total unit costs may differ from the sum of the individual costs due to rounding. |
Derivatives Information
As of December 31, 2025, the Company had the following outstanding financial commodity derivatives:
|
|
2026 |
||||||||||
Oil |
|
First Quarter |
|
Second Quarter |
|
Third Quarter |
|
Fourth Quarter |
||||
WTI oil collars |
|
|
|
|
|
|
|
|
||||
Volume (MBbl) |
|
|
3,600 |
|
|
3,640 |
|
|
3,680 |
|
|
3,680 |
Weighted average floor ($/Bbl) |
|
$ |
56.25 |
|
$ |
56.25 |
|
$ |
56.25 |
|
$ |
56.25 |
Weighted average ceiling ($/Bbl) |
|
$ |
70.81 |
|
$ |
70.81 |
|
$ |
70.81 |
|
$ |
70.81 |
|
|
|
|
|
|
|
|
|
||||
WTI NYMEX oil swaps |
|
|
|
|
|
|
|
|
||||
Volume (MBbl) |
|
|
900 |
|
|
910 |
|
|
920 |
|
|
920 |
Weighted average price ($/Bbl) |
|
$ |
66.14 |
|
$ |
66.14 |
|
$ |
66.14 |
|
$ |
66.14 |
|
|
|
|
|
|
|
|
|
||||
WTI Midland oil basis swaps |
|
|
|
|
|
|
|
|
||||
Volume (MBbl) |
|
|
4,500 |
|
|
4,550 |
|
|
4,600 |
|
|
4,600 |
Weighted average differential ($/Bbl) |
|
$ |
0.97 |
|
$ |
0.97 |
|
$ |
0.97 |
|
$ |
0.97 |
|
|
2026 |
||||||||||||||
Natural Gas |
|
First Quarter |
|
Second Quarter |
|
Third Quarter |
|
Fourth Quarter |
||||||||
NYMEX gas collars |
|
|
|
|
|
|
|
|
||||||||
Volume (MMBtu) |
|
|
108,000,000 |
|
|
|
81,900,000 |
|
|
|
82,800,000 |
|
|
|
82,800,000 |
|
Weighted average floor ($/MMBtu) |
|
$ |
3.23 |
|
|
$ |
3.39 |
|
|
$ |
3.39 |
|
|
$ |
3.39 |
|
Weighted average ceiling ($/MMBtu) |
|
$ |
6.12 |
|
|
$ |
5.61 |
|
|
$ |
5.61 |
|
|
$ |
5.61 |
|
|
|
|
|
|
|
|
|
|
||||||||
Transco Leidy gas basis swaps |
|
|
|
|
|
|
|
|
||||||||
Volume (MMBtu) |
|
|
13,500,000 |
|
|
|
13,650,000 |
|
|
|
13,800,000 |
|
|
|
13,800,000 |
|
Weighted average differential ($/MMBtu) |
|
$ |
(0.78 |
) |
|
$ |
(0.78 |
) |
|
$ |
(0.78 |
) |
|
$ |
(0.78 |
) |
|
|
|
|
|
|
|
|
|
||||||||
Transco Zone 6 Non-NY gas basis swaps |
|
|
|
|
|
|
|
|
||||||||
Volume (MMBtu) |
|
|
22,500,000 |
|
|
|
22,750,000 |
|
|
|
23,000,000 |
|
|
|
23,000,000 |
|
Weighted average differential ($/MMBtu) |
|
$ |
(0.16 |
) |
|
$ |
(0.16 |
) |
|
$ |
(0.16 |
) |
|
$ |
(0.16 |
) |
|
|
|
|
|
|
|
|
|
||||||||
Waha gas basis swaps |
|
|
|
|
|
|
|
|
||||||||
Volume (MMBtu) |
|
|
18,000,000 |
|
|
|
18,200,000 |
|
|
|
18,400,000 |
|
|
|
18,400,000 |
|
Weighted average differential ($/MMBtu) |
|
$ |
(1.92 |
) |
|
$ |
(1.92 |
) |
|
$ |
(1.92 |
) |
|
$ |
(1.92 |
) |
|
|
2027 |
||||||||||
Natural Gas |
|
First Quarter |
|
Second Quarter |
|
Third Quarter |
|
Fourth Quarter |
||||
NYMEX gas collars |
|
|
|
|
|
|
|
|
||||
Volume (MMBtu) |
|
|
7,200,000 |
|
|
7,280,000 |
|
|
7,360,000 |
|
|
7,360,000 |
Weighted average floor ($/MMBtu) |
|
$ |
3.40 |
|
$ |
3.40 |
|
$ |
3.40 |
|
$ |
3.40 |
Weighted average ceiling ($/MMBtu) |
|
$ |
5.17 |
|
$ |
5.17 |
|
$ |
5.17 |
|
$ |
5.17 |
In January 2026, the Company entered into the following financial commodity derivatives:
|
|
2026 |
||||||||||
Oil |
|
First Quarter |
|
Second Quarter |
|
Third Quarter |
|
Fourth Quarter |
||||
WTI oil collars |
|
|
|
|
|
|
|
|
||||
Volume (MBbl) |
|
|
590 |
|
|
910 |
|
|
920 |
|
|
920 |
Weighted average floor ($/Bbl) |
|
$ |
55.00 |
|
$ |
55.00 |
|
$ |
50.00 |
|
$ |
50.00 |
Weighted average ceiling ($/Bbl) |
|
$ |
67.40 |
|
$ |
67.40 |
|
$ |
69.25 |
|
$ |
69.25 |
|
|
2026 |
||||||||||||||
Natural Gas |
|
First Quarter |
|
Second Quarter |
|
Third Quarter |
|
Fourth Quarter |
||||||||
Transco Leidy gas basis swaps |
|
|
|
|
|
|
|
|
||||||||
Volume (MMBtu) |
|
|
5,900,000 |
|
|
|
9,100,000 |
|
|
|
9,200,000 |
|
|
|
9,200,000 |
|
Weighted average differential ($/MMBtu) |
|
$ |
(0.79 |
) |
|
$ |
(0.79 |
) |
|
$ |
(0.79 |
) |
|
$ |
(0.79 |
) |
Year-End Proved Reserves
The tables below provide a summary of changes in proved reserves for the year ended December 31, 2025.
|
Oil
|
|
Natural Gas
|
|
NGL
|
|
Total
|
||||
PROVED RESERVES |
|
|
|
|
|
|
|
||||
December 31, 2024 |
269,995 |
|
|
9,834 |
|
|
361,777 |
|
|
2,270,721 |
|
Revision of previous estimates |
5,114 |
|
|
816 |
|
|
21,253 |
|
|
162,258 |
|
Extensions and discoveries |
61,439 |
|
|
759 |
|
|
62,841 |
|
|
250,774 |
|
Purchases of reserves in place |
107,310 |
|
|
188 |
|
|
28,416 |
|
|
167,143 |
|
Production |
(58,370 |
) |
|
(1,086 |
) |
|
(46,247 |
) |
|
(285,576 |
) |
Sales of reserves |
(5 |
) |
|
— |
|
|
(12 |
) |
|
(38 |
) |
December 31, 2025 |
385,483 |
|
|
10,511 |
|
|
428,028 |
|
|
2,565,282 |
|
|
|
|
|
|
|
|
|
||||
PROVED DEVELOPED RESERVES |
|
|
|
|
|
|
|
||||
December 31, 2024 |
189,275 |
|
|
8,420 |
|
|
271,030 |
|
|
1,863,583 |
|
December 31, 2025 |
283,671 |
|
|
9,051 |
|
|
335,012 |
|
|
2,127,175 |
|
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited) |
|||||||||||||||
|
Quarter Ended December 31, |
|
Twelve Months Ended December 31, |
||||||||||||
(In millions, except per share amounts) |
2025 |
|
2024 |
|
2025 |
|
2024 |
||||||||
OPERATING REVENUES |
|
|
|
|
|
|
|
||||||||
Oil |
$ |
941 |
|
|
$ |
713 |
|
|
$ |
3,699 |
|
|
$ |
2,953 |
|
Natural gas |
|
615 |
|
|
|
516 |
|
|
|
2,633 |
|
|
|
1,693 |
|
NGL |
|
206 |
|
|
|
203 |
|
|
|
844 |
|
|
|
738 |
|
Gain (loss) on derivative instruments, net |
|
169 |
|
|
|
(51 |
) |
|
|
351 |
|
|
|
(3 |
) |
Other |
|
28 |
|
|
|
14 |
|
|
|
118 |
|
|
|
77 |
|
|
|
1,959 |
|
|
|
1,395 |
|
|
|
7,645 |
|
|
|
5,458 |
|
OPERATING EXPENSES |
|
|
|
|
|
|
|
||||||||
Direct operations |
|
296 |
|
|
|
177 |
|
|
|
1,023 |
|
|
|
658 |
|
Gathering, processing and transportation |
|
266 |
|
|
|
239 |
|
|
|
1,089 |
|
|
|
976 |
|
Taxes other than income |
|
90 |
|
|
|
77 |
|
|
|
366 |
|
|
|
271 |
|
Exploration |
|
6 |
|
|
|
6 |
|
|
|
27 |
|
|
|
25 |
|
Depreciation, depletion and amortization |
|
666 |
|
|
|
486 |
|
|
|
2,370 |
|
|
|
1,840 |
|
General and administrative (excluding stock-based compensation) |
|
44 |
|
|
|
65 |
|
|
|
260 |
|
|
|
240 |
|
Stock-based compensation(1) |
|
20 |
|
|
|
19 |
|
|
|
63 |
|
|
|
62 |
|
|
|
1,388 |
|
|
|
1,069 |
|
|
|
5,198 |
|
|
|
4,072 |
|
Gain on sale of assets |
|
— |
|
|
|
— |
|
|
|
5 |
|
|
|
3 |
|
INCOME FROM OPERATIONS |
|
571 |
|
|
|
326 |
|
|
|
2,452 |
|
|
|
1,389 |
|
Interest expense |
|
49 |
|
|
|
29 |
|
|
|
205 |
|
|
|
106 |
|
Interest income |
|
(2 |
) |
|
|
(11 |
) |
|
|
(14 |
) |
|
|
(62 |
) |
Other income |
|
(1 |
) |
|
|
— |
|
|
|
(2 |
) |
|
|
— |
|
Income before income taxes |
|
525 |
|
|
|
308 |
|
|
|
2,263 |
|
|
|
1,345 |
|
Income tax provision (benefit) |
|
|
|
|
|
|
|
||||||||
Current |
|
18 |
|
|
|
96 |
|
|
|
122 |
|
|
|
369 |
|
Deferred |
|
139 |
|
|
|
(85 |
) |
|
|
424 |
|
|
|
(145 |
) |
Total income tax provision |
|
157 |
|
|
|
11 |
|
|
|
546 |
|
|
|
224 |
|
NET INCOME |
$ |
368 |
|
|
$ |
297 |
|
|
$ |
1,717 |
|
|
$ |
1,121 |
|
Earnings per share - Basic |
$ |
0.51 |
|
|
$ |
0.40 |
|
|
$ |
2.25 |
|
|
$ |
1.51 |
|
Weighted-average common shares outstanding |
|
762 |
|
|
|
736 |
|
|
|
761 |
|
|
|
742 |
|
| ______________________________ | |
(1) |
Includes the impact of our performance share awards and restricted stock. |
CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited) |
|||||
(In millions) |
December 31,
|
|
December 31,
|
||
ASSETS |
|
|
|
||
|
|
|
|
||
Cash and cash equivalents |
$ |
114 |
|
$ |
2,038 |
Restricted cash |
|
5 |
|
|
239 |
Other current assets |
|
1,730 |
|
|
1,044 |
Properties and equipment, net (successful efforts method) |
|
22,058 |
|
|
17,890 |
Other assets |
|
334 |
|
|
414 |
|
$ |
24,241 |
|
$ |
21,625 |
|
|
|
|
||
LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY |
|
|
|
||
Current liabilities |
$ |
1,307 |
|
$ |
1,136 |
Current portion of long-term debt |
|
250 |
|
|
— |
Long-term debt, net (excluding current maturities) |
|
3,568 |
|
|
3,535 |
Deferred income taxes |
|
3,703 |
|
|
3,274 |
Other long term liabilities |
|
567 |
|
|
550 |
Redeemable preferred stock |
|
8 |
|
|
8 |
Stockholders’ equity |
|
14,838 |
|
|
13,122 |
|
$ |
24,241 |
|
$ |
21,625 |
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited) |
|||||||||||||||
|
Quarter Ended December 31, |
|
Twelve Months Ended December 31, |
||||||||||||
(In millions) |
2025 |
|
2024 |
|
2025 |
|
2024 |
||||||||
CASH FLOWS FROM OPERATING ACTIVITIES |
|
|
|
|
|
|
|
||||||||
Net income |
$ |
368 |
|
|
$ |
297 |
|
|
$ |
1,717 |
|
|
$ |
1,121 |
|
Depreciation, depletion and amortization |
|
666 |
|
|
|
486 |
|
|
|
2,370 |
|
|
|
1,840 |
|
Deferred income tax expense (benefit) |
|
150 |
|
|
|
(85 |
) |
|
|
435 |
|
|
|
(145 |
) |
Gain on sale of assets |
|
— |
|
|
|
— |
|
|
|
(5 |
) |
|
|
(3 |
) |
Exploratory dry hole cost |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
5 |
|
(Gain) loss on derivative instruments |
|
(169 |
) |
|
|
51 |
|
|
|
(351 |
) |
|
|
3 |
|
Net cash received in settlement of derivative instruments |
|
57 |
|
|
|
8 |
|
|
|
106 |
|
|
|
98 |
|
Stock-based compensation and other |
|
19 |
|
|
|
18 |
|
|
|
62 |
|
|
|
61 |
|
Income charges not requiring cash |
|
(3 |
) |
|
|
1 |
|
|
|
(15 |
) |
|
|
(12 |
) |
Changes in assets and liabilities |
|
(118 |
) |
|
|
(150 |
) |
|
|
(298 |
) |
|
|
(173 |
) |
Net cash provided by operating activities |
|
970 |
|
|
|
626 |
|
|
|
4,021 |
|
|
|
2,795 |
|
|
|
|
|
|
|
|
|
||||||||
CASH FLOWS FROM INVESTING ACTIVITIES |
|
|
|
|
|
|
|
||||||||
Capital expenditures for drilling, completion and other fixed asset additions |
|
(581 |
) |
|
|
(425 |
) |
|
|
(2,288 |
) |
|
|
(1,754 |
) |
Capital expenditures for leasehold and property acquisitions |
|
(13 |
) |
|
|
(11 |
) |
|
|
(99 |
) |
|
|
(17 |
) |
Cash consideration paid for business combinations, net of cash received |
|
— |
|
|
|
— |
|
|
|
(3,238 |
) |
|
|
— |
|
Proceeds from sale of short-term investments |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
250 |
|
Purchase of short-term investments |
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
(250 |
) |
Other |
|
(1 |
) |
|
|
1 |
|
|
|
(3 |
) |
|
|
9 |
|
Net cash used in investing activities |
|
(595 |
) |
|
|
(435 |
) |
|
|
(5,628 |
) |
|
|
(1,762 |
) |
|
|
|
|
|
|
|
|
||||||||
CASH FLOWS FROM FINANCING ACTIVITIES |
|
|
|
|
|
|
|
||||||||
Proceeds from issuance of debt |
|
300 |
|
|
|
1,491 |
|
|
|
1,746 |
|
|
|
1,990 |
|
Repayments of debt |
|
(400 |
) |
|
|
— |
|
|
|
(1,446 |
) |
|
|
(575 |
) |
Common stock repurchases |
|
(90 |
) |
|
|
(54 |
) |
|
|
(141 |
) |
|
|
(455 |
) |
Dividends paid |
|
(168 |
) |
|
|
(155 |
) |
|
|
(682 |
) |
|
|
(625 |
) |
Other |
|
(1 |
) |
|
|
(44 |
) |
|
|
(28 |
) |
|
|
(56 |
) |
Net cash (used in) provided by financing activities |
|
(359 |
) |
|
|
1,238 |
|
|
|
(551 |
) |
|
|
279 |
|
Net increase (decrease) in cash, cash equivalents and restricted cash |
$ |
16 |
|
|
$ |
1,429 |
|
|
$ |
(2,158 |
) |
|
$ |
1,312 |
|
Supplemental Non-GAAP Financial Measures (Unaudited)
We report our financial results in accordance with accounting principles generally accepted in
We have also included herein certain forward-looking non-GAAP financial measures, including, among others, the reinvestment rate, which is defined as capital expenditures (non-GAAP) as a percentage of Discretionary Cash Flow (non-GAAP). We believe the reinvestment rate provides investors with useful information on management's projected use and reinvestment of its future cash flows back into Coterra's operations. Due to the forward-looking nature of these non-GAAP financial measures, we cannot reliably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as changes in assets and liabilities (including future impairments) and cash paid for certain capital expenditures. Accordingly, we are unable to present a quantitative reconciliation of such forward-looking non-GAAP financial measures to their most directly comparable forward-looking GAAP financial measures. Reconciling items in future periods could be significant.
Reconciliation of Net Income to Adjusted Net Income and Adjusted Earnings Per Share
Adjusted Net Income and Adjusted Earnings per Share are presented based on our management's belief that these non-GAAP measures enable a user of financial information to understand the impact of identified adjustments on reported results. Adjusted Net Income is defined as net income plus gain and loss on sale of assets, non-cash gain and loss on derivative instruments, stock-based compensation expense, acquisition-related expenses and tax effect on selected items. Adjusted Earnings per Share is defined as Adjusted Net Income divided by weighted-average common shares outstanding. Additionally, we believe these measures provide beneficial comparisons to similarly adjusted measurements of prior periods and use these measures for that purpose. Adjusted Net Income and Adjusted Earnings per Share are not measures of financial performance under GAAP and should not be considered as alternatives to net income and earnings per share, as defined by GAAP.
|
Quarter Ended December 31, |
|
Twelve Months Ended December 31, |
||||||||||||
(In millions, except per share amounts) |
2025 |
|
2024 |
|
2025 |
|
2024 |
||||||||
As reported - net income |
$ |
368 |
|
|
$ |
297 |
|
|
$ |
1,717 |
|
|
$ |
1,121 |
|
Reversal of selected items: |
|
|
|
|
|
|
|
||||||||
Gain on sale of assets |
|
— |
|
|
|
— |
|
|
|
(5 |
) |
|
|
(3 |
) |
(Gain) loss on derivative instruments(1) |
|
(112 |
) |
|
|
59 |
|
|
|
(245 |
) |
|
|
101 |
|
Stock-based compensation expense |
|
20 |
|
|
|
19 |
|
|
|
63 |
|
|
|
62 |
|
Acquisition-related expense |
|
— |
|
|
|
— |
|
|
|
15 |
|
|
|
— |
|
Tax effect on selected items |
|
18 |
|
|
|
(17 |
) |
|
|
39 |
|
|
|
(36 |
) |
Adjusted net income |
$ |
294 |
|
|
$ |
358 |
|
|
$ |
1,584 |
|
|
$ |
1,245 |
|
As reported - earnings per share |
$ |
0.51 |
|
|
$ |
0.40 |
|
|
$ |
2.25 |
|
|
$ |
1.51 |
|
Per share impact of selected items |
|
(0.12 |
) |
|
|
0.09 |
|
|
|
(0.17 |
) |
|
|
0.17 |
|
Adjusted earnings per share |
$ |
0.39 |
|
|
$ |
0.49 |
|
|
$ |
2.08 |
|
|
$ |
1.68 |
|
Weighted-average common shares outstanding |
|
762 |
|
|
|
736 |
|
|
|
761 |
|
|
|
742 |
|
| ______________________________ | |
(1) |
This amount represents the non-cash mark-to-market changes of our commodity derivative instruments recorded in Gain (loss) on derivative instruments in the Condensed Consolidated Statement of Operations. |
Reconciliation of Discretionary Cash Flow and Free Cash Flow
Discretionary Cash Flow is defined as cash flow from operating activities excluding changes in assets and liabilities. Discretionary Cash Flow is widely accepted as a financial indicator of an oil and gas company’s ability to generate available cash to internally fund exploration and development activities, return capital to shareholders through dividends and share repurchases, and service debt and is used by our management for that purpose. Discretionary Cash Flow is presented based on our management’s belief that this non-GAAP measure is useful information to investors when comparing our cash flows with the cash flows of other companies that use the full cost method of accounting for oil and gas producing activities or have different financing and capital structures or tax rates. Discretionary Cash Flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities or net income, as defined by GAAP, or as a measure of liquidity.
Free Cash Flow is defined as Discretionary Cash Flow less cash paid for capital expenditures. Free Cash Flow is an indicator of a company’s ability to generate cash flow after spending the money required to maintain or expand its asset base, and is used by our management for that purpose. Free Cash Flow is presented based on our management’s belief that this non-GAAP measure is useful information to investors when comparing our cash flows with the cash flows of other companies. Free Cash Flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities or net income, as defined by GAAP, or as a measure of liquidity.
|
|
Quarter Ended December 31, |
|
Twelve Months Ended December 31, |
||||||||||||
(In millions) |
|
2025 |
|
2024 |
|
2025 |
|
2024 |
||||||||
Cash flow from operating activities (GAAP) |
|
$ |
970 |
|
|
$ |
626 |
|
|
$ |
4,021 |
|
|
$ |
2,795 |
|
Changes in assets and liabilities |
|
|
118 |
|
|
|
150 |
|
|
|
298 |
|
|
|
173 |
|
Discretionary cash flow (non-GAAP) |
|
|
1,088 |
|
|
|
776 |
|
|
|
4,319 |
|
|
|
2,968 |
|
Cash paid for capital expenditures for drilling, completion and other fixed asset additions (GAAP) |
|
|
(581 |
) |
|
|
(425 |
) |
|
|
(2,288 |
) |
|
|
(1,754 |
) |
Free cash flow (non-GAAP) |
|
$ |
507 |
|
|
$ |
351 |
|
|
$ |
2,031 |
|
|
$ |
1,214 |
|
Reconciliation of Capital Expenditures
Capital expenditures is defined as cash paid for capital expenditures for drilling, completion and other fixed asset additions less changes in accrued capital costs plus exploratory dry-hole cost.
|
|
Quarter Ended December 31, |
|
Twelve Months Ended December 31, |
||||||||||
(In millions) |
|
2025 |
|
2024 |
|
2025 |
|
2024 |
||||||
Cash paid for capital expenditures for drilling, completion and other fixed asset additions (GAAP) |
|
$ |
581 |
|
|
$ |
425 |
|
|
$ |
2,288 |
|
$ |
1,754 |
Change in accrued capital costs |
|
|
(42 |
) |
|
|
(8 |
) |
|
|
30 |
|
|
3 |
Exploratory dry-hole cost |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
5 |
Capital expenditures for drilling, completion and other fixed asset additions (non-GAAP) |
|
$ |
539 |
|
|
$ |
417 |
|
|
$ |
2,318 |
|
$ |
1,762 |
Reconciliation of Reinvestment Rate
The reinvestment rate is defined as capital expenditures for drilling, completion and other fixed asset additions divided by discretionary cash flow. The reinvestment rate is a non-GAAP measure which our management believes is useful to investors when assessing our performance and liquidity.
|
|
Quarter Ended December 31, |
|
Twelve Months Ended December 31, |
||||||||||||
(In millions) |
|
2025 |
|
2024 |
|
2025 |
|
2024 |
||||||||
Cash paid for capital expenditures for drilling, completion and other fixed asset additions (GAAP) |
|
$ |
581 |
|
|
$ |
425 |
|
|
$ |
2,288 |
|
|
$ |
1,754 |
|
Change in accrued capital costs |
|
|
(42 |
) |
|
|
(8 |
) |
|
|
30 |
|
|
|
3 |
|
Exploratory dry-hole cost |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
5 |
|
Capital expenditures for drilling, completion and other fixed asset additions (non-GAAP) |
|
$ |
539 |
|
|
$ |
417 |
|
|
$ |
2,318 |
|
|
$ |
1,762 |
|
Discretionary cash flow (non-GAAP) |
|
$ |
1,088 |
|
|
$ |
776 |
|
|
$ |
4,319 |
|
|
$ |
2,968 |
|
Reinvestment rate (non-GAAP) |
|
|
50 |
% |
|
|
54 |
% |
|
|
54 |
% |
|
|
59 |
% |
Reconciliation of Adjusted EBITDAX
Adjusted EBITDAX is defined as net income plus interest expense, interest income, income tax expense, depreciation, depletion, and amortization (including impairments), exploration expense, gain and loss on sale of assets, non-cash gain and loss on derivative instruments, stock-based compensation expense, and acquisition-related expenses. Adjusted EBITDAX is presented on our management’s belief that this non-GAAP measure is useful information to investors when evaluating our ability to internally fund exploration and development activities and to service or incur debt without regard to financial or capital structure. Our management uses Adjusted EBITDAX for that purpose. Adjusted EBITDAX is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities or net income, as defined by GAAP, or as a measure of liquidity.
|
Quarter Ended December 31, |
|
Twelve Months Ended December 31, |
||||||||||||
(In millions) |
2025 |
|
2024 |
|
2025 |
|
2024 |
||||||||
Net income |
$ |
368 |
|
|
$ |
297 |
|
|
$ |
1,717 |
|
|
$ |
1,121 |
|
Plus (less): |
|
|
|
|
|
|
|
||||||||
Interest expense |
|
49 |
|
|
|
29 |
|
|
|
205 |
|
|
|
106 |
|
Interest income |
|
(2 |
) |
|
|
(11 |
) |
|
|
(14 |
) |
|
|
(62 |
) |
Other income |
|
(1 |
) |
|
|
— |
|
|
|
(2 |
) |
|
|
— |
|
Income tax expense |
|
157 |
|
|
|
11 |
|
|
|
546 |
|
|
|
224 |
|
Depreciation, depletion and amortization |
|
666 |
|
|
|
486 |
|
|
|
2,370 |
|
|
|
1,840 |
|
Exploration |
|
6 |
|
|
|
6 |
|
|
|
27 |
|
|
|
25 |
|
Gain on sale of assets |
|
— |
|
|
|
— |
|
|
|
(5 |
) |
|
|
(3 |
) |
Non-cash (gain) loss on derivative instruments |
|
(112 |
) |
|
|
59 |
|
|
|
(245 |
) |
|
|
101 |
|
Stock-based compensation |
|
20 |
|
|
|
19 |
|
|
|
63 |
|
|
|
62 |
|
Acquisition-related expense |
|
— |
|
|
|
— |
|
|
|
15 |
|
|
|
— |
|
Adjusted EBITDAX |
$ |
1,151 |
|
|
$ |
896 |
|
|
$ |
4,677 |
|
|
$ |
3,414 |
|
Reconciliation of Net Debt
The total debt to total capitalization ratio is calculated by dividing total debt by the sum of total debt and total stockholders’ equity. This ratio is a measurement which is presented in our annual and interim filings and our management believes this ratio is useful to investors in assessing our leverage. Net Debt is calculated by subtracting cash and cash equivalents and short-term investments from total debt. The Net Debt to Adjusted Capitalization ratio is calculated by dividing Net Debt by the sum of Net Debt and total stockholders’ equity. Net Debt and the Net Debt to Adjusted Capitalization ratio are non-GAAP measures which our management believes are also useful to investors when assessing our leverage since we have the ability to and may decide to use a portion of our cash and cash equivalents and short-term investments to retire debt. Our management uses these measures for that purpose. Additionally, as our planned expenditures are not expected to result in additional debt, our management believes it is appropriate to apply cash and cash equivalents and short-term investments to reduce debt in calculating the Net Debt to Adjusted Capitalization ratio.
(In millions) |
December 31,
|
|
December 31,
|
||||
Current portion of long-term debt |
$ |
250 |
|
|
$ |
— |
|
Long-term debt, net |
|
3,568 |
|
|
|
3,535 |
|
Total debt |
$ |
3,818 |
|
|
$ |
3,535 |
|
Stockholders’ equity |
|
14,838 |
|
|
|
13,122 |
|
Total capitalization |
$ |
18,656 |
|
|
$ |
16,657 |
|
|
|
|
|
||||
Total debt |
$ |
3,818 |
|
|
$ |
3,535 |
|
Less: Cash and cash equivalents |
|
(114 |
) |
|
|
(2,038 |
) |
Net debt |
$ |
3,704 |
|
|
$ |
1,497 |
|
|
|
|
|
||||
Net debt |
$ |
3,704 |
|
|
$ |
1,497 |
|
Stockholders’ equity |
|
14,838 |
|
|
|
13,122 |
|
Total adjusted capitalization |
$ |
18,542 |
|
|
$ |
14,619 |
|
|
|
|
|
||||
Total debt to total capitalization ratio |
|
20.5 |
% |
|
|
21.2 |
% |
Less: Impact of cash and cash equivalents |
|
0.5 |
% |
|
|
11.0 |
% |
Net debt to adjusted capitalization ratio |
|
20.0 |
% |
|
|
10.2 |
% |
Reconciliation of Net Debt to Adjusted EBITDAX
Total debt to net income is defined as total debt divided by net income. Net debt to Adjusted EBITDAX is defined as net debt divided by trailing twelve month Adjusted EBITDAX. Net debt to Adjusted EBITDAX is a non-GAAP measure which our management believes is useful to investors when assessing our credit position and leverage.
(In millions) |
December 31,
|
|
December 31,
|
||
Total debt |
$ |
3,818 |
|
$ |
3,535 |
Net income |
|
1,717 |
|
|
1,121 |
Total debt to net income ratio |
2.2 x |
|
3.2 x |
||
|
|
|
|
||
Net debt (as defined above) |
$ |
3,704 |
|
$ |
1,497 |
Adjusted EBITDAX (Twelve months ended December 31) |
|
4,677 |
|
|
3,414 |
Net debt to Adjusted EBITDAX |
0.8 x |
|
0.4 x |
||
2026 Guidance
The tables below present 2026 guidance for Coterra standalone operations. Following the closing of the Devon and Coterra merger, expected in the second quarter of 2026, full-year guidance for the combined entity will be provided.
|
|
Full Year Guidance |
||||||||||||
|
|
November 2025 Guidance |
|
2025 Actual |
|
2026 Guidance |
||||||||
|
|
Low |
|
Mid |
|
High |
|
|
|
Low |
|
Mid |
|
High |
Total Equivalent Production (MBoed) |
|
772 |
|
777 |
|
782 |
|
782 |
|
750 |
|
780 |
|
810 |
Gas (Mmcf/day) |
|
2,925 |
|
2,945 |
|
2,965 |
|
2,975 |
|
2,775 |
|
2,875 |
|
2,975 |
Oil (MBbl/day) |
|
159 |
|
160 |
|
161 |
|
160 |
|
162 |
|
167 |
|
172 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net wells turned in line |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marcellus Shale |
|
9 |
|
13 |
|
|
|
13 |
|
32 |
|
36 |
|
40 |
Permian Basin |
|
|
|
165 |
|
|
|
167 |
|
130 |
|
140 |
|
150 |
|
|
|
|
20 |
|
|
|
19 |
|
12 |
|
15 |
|
18 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($ in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Company |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling and completion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marcellus Shale |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Permian Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Midstream, saltwater disposal, infrastructure, and other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity price assumptions: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI ($ per bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Henry Hub ($ per mmbtu) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow & Investment ($ in billions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discretionary Cash Flow |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Free Cash Flow |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ per boe, unless noted: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense + workovers + region office |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering, processing, & transportation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Taxes other than income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General & administrative (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit Operating Cost |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% effective tax rate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
% cash tax rate (cash tax/pre-tax income) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ______________________________ | |
| (1) | Excludes stock-based compensation. |
View source version on businesswire.com: https://www.businesswire.com/news/home/20260226054429/en/
Investor Contact
Daniel Guffey - Senior Vice President - Finance, IR, & Treasurer
281.589.4875
Hannah Stuckey - Director Investor Relations
281.589.4983
Source: Coterra Energy Inc.
