Coterra Energy Reports Third-Quarter 2025 Results, Announces Quarterly Dividend, and Provides Fourth-Quarter and Full Year 2025 Guidance Update
HOUSTON--( BUSINESS WIRE)--Coterra Energy Inc. (NYSE: CTRA) (“Coterra” or the “Company”) today reported third-quarter 2025 financial and operating results and declared a quarterly dividend of $0.22 per share. Additionally, the Company provided fourth-quarter production and capital guidance and updated full-year 2025 guidance.
Tom Jorden, Chairman, CEO and President of Coterra, noted, "We are pleased with our strong operational execution during the quarter and are on track to meet or exceed our annual targets. Our nine rig and three completion crew program in the Permian program continues to be highly capital efficient, cost effective, and is generating strong returns at today’s prevailing prices. We are also pleased with the competitive returns currently being generated in both the Marcellus and Anadarko Basin. The durability of our high-quality asset portfolio shines throughout various price cycles.
The stellar returns across our diversified asset base are driven by the quality of the rock, our competitive drilling and completion costs, low cost structure and high margins. We remain focused on delivering a highly capital efficient program and maintaining a conservative reinvestment rate. Our balance sheet strength and limited long-term contracts provide maximum flexibility through commodity cycles. These attributes in the hands of a high performing organization differentiates Coterra."
Key Takeaways & Updates
Third-Quarter 2025 Highlights
Shareholder Return Highlights
Guidance Updates
Strong Financial Position
In conjunction with the closing of the Franklin Mountain Energy and Avant Natural Resources acquisitions in late January, Coterra issued $1.0 billion of new debt through its term loan agreements. Subsequently, Coterra has paid down $600 million of the term loans through September 2025, including $250 million in the third quarter, leaving $400 million of term loan debt outstanding. As of September 30, 2025, Coterra had total debt outstanding of $3.9 billion (principal balance), down from $4.5 billion in January 2025. The Company exited the quarter with cash and cash equivalents of $98 million, and no debt outstanding under its $2.0 billion revolving credit facility, resulting in total liquidity of approximately $2.1 billion. Net Debt to trailing twelve-month Adjusted Pro Forma EBITDAX ratio (non-GAAP) at September 30, 2025 was 0.8x, pro forma for the Franklin and Avant acquisitions. The Company remains committed to further near-term debt reduction.
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.
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. Coterra published its 2025 Sustainability report on August 4, 2025.
Third-Quarter 2025 Conference Call
Coterra will host a conference call tomorrow, Tuesday, November 4, 2025, at 9:00 AM CT (10:00 AM ET), to discuss third-quarter 2025 financial and operating results.
Conference Call Information
Date: November 4, 2025
Time: 9:00 AM CT / 10:00 AM ET
Dial-in (for callers in the U.S. and Canada): (800) 715-9871
International dial-in: +1 (646) 307-1963
Conference ID: 4309719
The live audio webcast and related earnings presentation can be accessed on the "Events & Presentations" page under the "Investors" section of the Company's website at www.coterra.com. The webcast will be archived and available at the same location after the conclusion of the live event.
About Coterra Energy
Coterra is a premier exploration and production company based in Houston, Texas with focused operations in the Permian Basin, Marcellus Shale, and Anadarko Basin. We strive to be a leading energy producer, delivering sustainable returns through the efficient and responsible development of our diversified asset base. Learn more about us at www.coterra.com.
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 returns to shareholders, enhanced shareholder value, reserves estimates, future financial and operating performance, and goals and commitment to sustainability and ESG leadership, strategic pursuits and goals, 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 volatility in commodity prices for crude oil and natural gas; changes in U.S. and international economic policy (including tariffs and retaliatory tariffs and the impacts thereof); cost increases; the effect of future regulatory or legislative actions; 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, (geopolitical disruptions such as the war in Ukraine or conflict in the Middle East or further escalation thereof); determination of reserves estimates, adjustments or revisions, including factors impacting such determination such as commodity prices, well performance, results of future drilling and marketing activities (including seismicity and similar data), operating expenses and completion of Coterra’s annual PUD reserves process, as well as the impact on our financial statements resulting therefrom; the presence or recoverability of estimated reserves; the ability to replace reserves; environmental risks; drilling and operating risks; exploration and development risks; competition; the ability of management to execute its plans to meet its goals; the impact of public health crises, including pandemics and epidemics and any related company or governmental policies or actions, financial condition and results of operations; and other risks inherent in Coterra's businesses. In addition, the declaration and payment of any future dividends, whether regular base quarterly dividends, variable dividends or special dividends, will depend on Coterra's financial results, cash requirements, future prospects and other factors deemed relevant by Coterra's Board. While the list of factors presented here is considered representative, no such list should be considered to be a complete statement of all potential risks and uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. For additional information about other factors that could cause actual results to differ materially from those described in the forward-looking statements, please refer to Coterra's annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other filings with the SEC, which are available on Coterra's website at www.coterra.com.
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
September 30,
Nine Months Ended
September 30,
2025
2024
2025
2024
PRODUCTION VOLUMES
Marcellus Shale
Natural gas (Mmcf/day)
1,977.6
1,928.5
2,089.5
2,117.2
Daily equivalent production (MBoepd)
329.6
321.4
348.3
352.9
Permian Basin
Natural gas (Mmcf/day)
620.4
531.2
624.8
500.9
Oil (MBbl/day)
160.1
102.7
147.2
99.8
NGL (MBbl/day)
103.8
82.7
92.0
77.0
Daily equivalent production (MBoepd)
367.3
273.9
343.3
260.2
Anadarko Basin
Natural gas (Mmcf/day)
295.7
218.8
262.8
186.6
Oil (MBbl/day)
6.5
9.5
7.2
7.5
NGL (MBbl/day)
31.9
26.9
29.0
22.6
Daily equivalent production (MBoepd)
87.7
72.9
80.0
61.1
Total Company
Natural gas (Mmcf/day)
2,894.6
2,682.0
2,978.5
2,806.8
Oil (MBbl/day)
166.8
112.3
154.6
107.4
NGL (MBbl/day)
135.8
109.7
121.1
99.6
Daily equivalent production (MBoepd)
785.0
669.1
772.0
674.8
AVERAGE SALES PRICE (excluding hedges)
Marcellus Shale
Natural gas ($/Mcf)
$
2.27
$
1.78
$
2.86
$
1.89
Permian Basin
Natural gas ($/Mcf)
$
0.55
$
(0.63
)
$
1.04
$
(0.06
)
Oil ($/Bbl)
$
64.09
$
73.96
$
65.31
$
76.14
NGL ($/Bbl)
$
16.27
$
17.30
$
18.37
$
18.83
Anadarko Basin
Natural gas ($/Mcf)
$
2.70
$
1.66
$
2.91
$
1.68
Oil ($/Bbl)
$
64.31
$
74.83
$
66.26
$
76.34
NGL ($/Bbl)
$
19.52
$
21.90
$
22.22
$
22.20
Total Company
Natural gas ($/Mcf)
$
1.95
$
1.30
$
2.48
$
1.53
Oil ($/Bbl)
$
64.10
$
74.04
$
65.36
$
76.16
NGL ($/Bbl)
$
17.02
$
18.42
$
19.29
$
19.59
Quarter Ended
September 30,
Nine Months Ended
September 30,
2025
2024
2025
2024
AVERAGE SALES PRICE (including hedges)
Total Company
Natural gas ($/Mcf)
$
2.05
$
1.41
$
2.52
$
1.65
Oil ($/Bbl)
$
64.79
$
74.18
$
65.89
$
76.17
NGL ($/Bbl)
$
17.02
$
18.42
$
19.29
$
19.59
Quarter Ended
September 30,
Nine Months Ended
September 30,
2025
2024
2025
2024
WELLS DRILLED (1)(2)
Gross wells
Marcellus Shale
15
4
28
26
Permian Basin
68
63
245
174
Anadarko Basin
11
20
25
39
94
87
298
239
Net wells
Marcellus Shale
13.1
4.0
19.4
25.0
Permian Basin
38.5
25.9
121.2
75.9
Anadarko Basin
4.0
6.3
14.0
20.0
55.6
36.2
154.6
120.9
TURN IN LINES (2)
Gross wells
Marcellus Shale
4
7
12
30
Permian Basin
64
61
245
159
Anadarko Basin
8
10
36
41
76
78
293
230
Net wells
Marcellus Shale
4.0
7.0
7.0
30.0
Permian Basin
38.0
23.9
124.5
68.4
Anadarko Basin
5.6
4.6
14.9
19.9
47.6
35.5
146.4
118.3
AVERAGE OPERATED RIG COUNTS
Marcellus Shale
2.0
0.6
1.3
1.3
Permian Basin
9.0
8.0
9.9
8.0
Anadarko Basin
2.0
1.0
1.9
1.4
(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
September 30,
Nine Months Ended
September 30,
2025
2024
2025
2024
AVERAGE UNIT COSTS ($/Boe) (1)
Direct operations
$
3.80
$
2.69
$
3.45
$
2.60
Gathering, processing and transportation
3.75
3.97
3.91
3.98
Taxes other than income
1.29
1.08
1.31
1.05
General and administrative (excluding stock-based compensation)
0.97
0.99
1.03
0.91
Unit Operating Cost
$
9.81
$
8.73
$
9.69
$
8.54
Depreciation, depletion and amortization
8.58
7.73
8.09
7.32
Exploration
0.09
0.15
0.10
0.10
Stock-based compensation
0.18
0.23
0.20
0.23
Severance expense
—
—
—
0.03
Interest expense, net
0.68
0.12
0.69
0.14
$
19.33
$
16.96
$
18.76
$
16.36
Total unit costs may differ from the sum of the individual costs due to rounding.
Derivatives Information
As of September 30, 2025, the Company had the following outstanding financial commodity derivatives:
2025
Oil
Fourth Quarter
WTI oil collars
Volume (MBbl)
5,152
Weighted average floor ($/Bbl)
$
61.34
Weighted average ceiling ($/Bbl)
$
79.00
WTI NYMEX oil swaps
Volume (MBbl)
1,748
Weighted average price ($/Bbl)
$
69.18
WTI Midland oil basis swaps
Volume (MBbl)
5,520
Weighted average differential ($/Bbl)
$
1.02
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
2025
Natural Gas
Fourth Quarter
NYMEX gas collars
Volume (MMBtu)
87,400,000
Weighted average floor ($/MMBtu)
$
3.08
Weighted average ceiling ($/MMBtu)
$
5.66
Transco Leidy gas basis swaps
Volume (MMBtu)
18,400,000
Weighted average differential ($/MMBtu)
$
(0.70
)
Transco Zone 6 Non-NY gas basis swaps
Volume (MMBtu)
18,400,000
Weighted average differential ($/MMBtu)
$
(0.49
)
Waha gas basis swaps
Volume (MMBtu)
13,800,000
Weighted average differential ($/MMBtu)
$
(2.05
)
2026
Natural Gas
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
NYMEX gas collars
Volume (MMBtu)
81,000,000
54,600,000
55,200,000
55,200,000
Weighted average floor ($/MMBtu)
$
3.06
$
3.21
$
3.21
$
3.21
Weighted average ceiling ($/MMBtu)
$
6.39
$
5.76
$
5.76
$
5.76
Transco Zone 6 Non-NY gas basis swaps
Volume (MMBtu)
13,500,000
13,650,000
13,800,000
13,800,000
Weighted average differential ($/MMBtu)
$
(0.26
)
$
(0.26
)
$
(0.26
)
$
(0.26
)
Waha gas basis swaps
Volume (MMBtu)
13,500,000
13,650,000
13,800,000
13,800,000
Weighted average differential ($/MMBtu)
$
(1.86
)
$
(1.86
)
$
(1.86
)
$
(1.86
)
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)
Quarter Ended
September 30,
Nine Months
Ended
September 30,
(In millions, except per share amounts)
2025
2024
2025
2024
OPERATING REVENUES
Oil
$
984
$
765
$
2,758
$
2,240
Natural gas
519
320
2,018
1,177
NGL
213
186
638
535
Gain (loss) on derivative instruments, net
62
64
182
48
Other
39
24
90
63
1,817
1,359
5,686
4,063
OPERATING EXPENSES
Direct operations
275
165
727
481
Gathering, processing and transportation
270
245
823
737
Taxes other than income
93
66
276
194
Exploration
7
9
21
19
Depreciation, depletion and amortization
619
475
1,704
1,354
General and administrative (excluding stock-based compensation)
70
61
216
175
Stock-based compensation
13
14
43
43
1,347
1,035
3,810
3,003
Gain on sale of assets
1
3
5
3
INCOME FROM OPERATIONS
471
327
1,881
1,063
Interest expense
50
24
156
77
Interest income
(2
)
(16
)
(12
)
(51
)
Other income
—
—
(1
)
—
Income before income taxes
423
319
1,738
1,037
Income tax provision (benefit)
Current
(123
)
104
104
273
Deferred
224
(37
)
285
(60
)
Total income tax provision
101
67
389
213
NET INCOME
$
322
$
252
$
1,349
$
824
Earnings per share - Basic
$
0.42
$
0.34
$
1.77
$
1.11
Weighted-average common shares outstanding
763
738
761
743
CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)
(In millions)
September 30,
2025
December 31,
2024
ASSETS
Cash and cash equivalents
$
98
$
2,038
Other current assets
1,428
1,283
Properties and equipment, net (successful efforts method)
22,167
17,890
Other assets
314
414
$
24,007
$
21,625
LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY
Current liabilities
$
1,239
$
1,136
Current portion of long-term debt
250
—
Long-term debt, net
3,672
3,535
Deferred income taxes
3,555
3,274
Other long term liabilities
565
550
Redeemable preferred stock
8
8
Stockholders’ equity
14,718
13,122
$
24,007
$
21,625
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)
Quarter Ended
September 30,
Nine Months Ended
September 30,
(In millions)
2025
2024
2025
2024
CASH FLOWS FROM OPERATING ACTIVITIES
Net income
$
322
$
252
$
1,349
$
824
Depreciation, depletion and amortization
619
475
1,704
1,354
Deferred income tax expense (benefit)
224
(37
)
285
(60
)
Gain on sale of assets
(1
)
(3
)
(5
)
(3
)
Exploratory dry hole cost
—
5
—
5
Gain on derivative instruments
(62
)
(64
)
(182
)
(48
)
Net cash received in settlement of derivative instruments
36
28
49
90
Stock-based compensation and other
13
18
43
43
Income charges not requiring cash
(3
)
(4
)
(12
)
(13
)
Changes in assets and liabilities
(177
)
85
(180
)
(23
)
Net cash provided by operating activities
971
755
3,051
2,169
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for drilling, completion and other fixed asset additions
(615
)
(393
)
(1,707
)
(1,329
)
Capital expenditures for leasehold and property acquisitions
(29
)
(3
)
(86
)
(6
)
Cash consideration paid for business combinations, net of cash received
(16
)
—
(3,238
)
—
Purchases of short-term investments
—
—
—
(250
)
Proceeds from sale of short-term investments
—
250
—
250
Other
(3
)
7
(2
)
8
Net cash used in investing activities
(663
)
(139
)
(5,033
)
(1,327
)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of debt
96
—
1,446
499
Repayments of debt
(346
)
(575
)
(1,046
)
(575
)
Common stock repurchases
(4
)
(111
)
(51
)
(401
)
Dividends paid
(168
)
(156
)
(514
)
(470
)
Tax withholding on vesting of stock awards
(5
)
—
(29
)
—
Other
6
(5
)
2
(12
)
Net cash used in financing activities
(421
)
(847
)
(192
)
(959
)
Net decrease in cash, cash equivalents and restricted cash
$
(113
)
$
(231
)
$
(2,174
)
$
(117
)
Supplemental Non-GAAP Financial Measures (Unaudited)
We report our financial results in accordance with accounting principles generally accepted in the United States (GAAP). However, we believe certain non-GAAP performance measures may provide financial statement users with additional meaningful comparisons between current results and results of prior periods. In addition, we believe these measures are used by analysts and others in the valuation, rating and investment recommendations of companies within the oil and natural gas exploration and production industry. See the reconciliations below that compare GAAP financial measures to non-GAAP financial measures for the periods indicated.
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, severance expense, 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
September 30,
Nine Months Ended
September 30,
(In millions, except per share amounts)
2025
2024
2025
2024
As reported - net income
$
322
$
252
$
1,349
$
824
Reversal of selected items:
Gain on sale of assets
(1
)
(3
)
(5
)
(3
)
(Gain) loss on derivative instruments (1)
(26
)
(36
)
(133
)
42
Stock-based compensation expense
13
14
43
43
Acquisition related expense
1
—
15
—
Tax effect on selected items
3
6
21
(19
)
Adjusted net income
$
312
$
233
$
1,290
$
887
As reported - earnings per share
$
0.42
$
0.34
$
1.77
$
1.11
Per share impact of selected items
(0.01
)
(0.02
)
(0.07
)
0.08
Adjusted earnings per share
$
0.41
$
0.32
$
1.70
$
1.19
Weighted-average common shares outstanding
763
738
761
743
(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
September 30,
Nine Months Ended
September 30,
(In millions)
2025
2024
2025
2024
Cash flow from operating activities
$
971
$
755
$
3,051
$
2,169
Changes in assets and liabilities
177
(85
)
180
23
Discretionary cash flow
1,148
670
3,231
2,192
Cash paid for capital expenditures for drilling, completion and other fixed asset additions
(615
)
(393
)
(1,707
)
(1,329
)
Free Cash Flow
$
533
$
277
$
1,524
$
863
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.
Quarter Ended
September 30,
Nine Months Ended
September 30,
(In millions)
2025
2024
2025
2024
Cash paid for capital expenditures for drilling, completion and other fixed asset additions (GAAP)
$
615
$
393
$
1,707
$
1,329
Change in accrued capital costs
43
20
72
11
Exploratory dry-hole cost
—
5
—
5
Capital expenditures for drilling, completion and other fixed asset additions (non-GAAP)
$
658
$
418
$
1,779
$
1,345
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
September 30,
Nine Months Ended
September 30,
(In millions)
2025
2024
2025
2024
Net income
$
322
$
252
$
1,349
$
824
Plus (less):
Interest expense
50
24
156
77
Interest income
(2
)
(16
)
(12
)
(51
)
Other income
—
—
(1
)
—
Income tax expense
101
67
389
213
Depreciation, depletion and amortization
619
475
1,704
1,354
Exploration
7
9
21
19
Gain on sale of assets
(1
)
(3
)
(5
)
(3
)
Non-cash (gain) loss on derivative instruments
(26
)
(36
)
(133
)
42
Acquisition-related expenses
1
—
15
—
Stock-based compensation
13
14
43
43
Adjusted EBITDAX
$
1,084
$
786
$
3,526
$
2,518
Trailing Twelve Months Ended
(In millions)
September 30,
2025
December 31,
2024
Net income
$
1,646
$
1,121
Plus (less):
Interest expense
185
106
Interest income
(23
)
(62
)
Other expense
(1
)
—
Income tax expense
400
224
Depreciation, depletion and amortization
2,190
1,840
Exploration
27
25
Gain on sale of assets
(5
)
(3
)
Non-cash (gain) loss on derivative instruments
(74
)
101
Acquisition-related expenses
15
—
Stock-based compensation
62
62
Adjusted EBITDAX (trailing twelve months)
$
4,422
$
3,414
Reconciliation of Adjusted Pro Forma EBITDAX
Adjusted Pro Forma EBITDAX is defined as pro forma net income plus pro forma interest expense, pro forma interest income, pro forma income tax expense, pro forma depreciation, depletion, and amortization (including impairments), pro forma exploration expense, pro forma gain and loss on sale of assets, pro forma non-cash gain and loss on derivative instruments, pro forma acquisition-related expenses, and pro forma stock-based compensation expense. Adjusted Pro Forma EBITDAX represents the effects of the Franklin Mountain Energy and Avant Natural Resources acquisitions as if they had occurred on January 1, 2024. Adjusted Pro Forma 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 after the acquisitions without regard to financial or capital structure. Our management uses Adjusted Pro Forma EBITDAX for that purpose. Adjusted Pro Forma EBITDAX is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities, pro forma net income or net income, as defined by GAAP, or as a measure of liquidity.
Trailing Twelve Months Ended
(In millions)
September 30,
2025
December 31,
2024
Pro forma net income
$
1,762
$
1,475
Plus (less):
Pro forma interest expense
224
250
Pro forma interest income
(23
)
(62
)
Pro forma other income
(1
)
—
Pro forma income tax expense
411
297
Pro forma depreciation, depletion and amortization
2,314
2,195
Pro forma exploration
27
25
Pro forma gain on sale of assets
(5
)
(3
)
Pro forma non-cash (gain) loss on derivative instruments
(74
)
101
Pro forma acquisition-related expenses
15
15
Pro forma stock-based compensation
62
62
Adjusted Pro Forma EBITDAX (trailing twelve months)
$
4,712
$
4,355
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)
September 30,
2025
December 31,
2024
Current portion of long-term debt
$
250
$
—
Long-term debt, net
3,672
3,535
Total debt
3,922
3,535
Stockholders’ equity
14,718
13,122
Total capitalization
$
18,640
$
16,657
Total debt
$
3,922
$
3,535
Less: Cash and cash equivalents
(98
)
(2,038
)
Net debt
$
3,824
$
1,497
Net debt
$
3,824
$
1,497
Stockholders’ equity
14,718
13,122
Total adjusted capitalization
$
18,542
$
14,619
Total debt to total capitalization ratio
21.0
%
21.2
%
Less: Impact of cash and cash equivalents
0.4
%
11.0
%
Net debt to adjusted capitalization ratio
20.6
%
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)
September 30,
2025
December 31,
2024
Total debt
$
3,922
$
3,535
Net income
1,646
1,121
Total debt to net income ratio
2.4
3.2
Net debt (as defined above)
$
3,824
$
1,497
Adjusted EBITDAX (Trailing twelve months)
$
4,422
$
3,414
Net debt to Adjusted EBITDAX
0.9
0.4
Reconciliation of Net Debt to Adjusted Pro Forma EBITDAX
Total debt to net income is defined as total debt divided by net income. Net debt to Adjusted Pro Forma EBITDAX is defined as net debt divided by trailing twelve month Adjusted Pro Forma EBITDAX. Net debt to Adjusted Pro Forma EBITDAX is a non-GAAP measure which our management believes is useful to investors when assessing our credit position and leverage.
(In millions)
September 30,
2025
December 31,
2024
Total debt
$
3,922
$
3,535
Net income
1,646
1,121
Total debt to net income ratio
2.4
3.2
Net debt (as defined above)
$
3,824
$
1,497
Adjusted Pro Forma EBITDAX (Trailing twelve months)
4,712
4,355
Net debt to Adjusted Pro Forma EBITDAX
0.8
0.3
2025 Guidance
The tables below present full-year and quarterly 2025 guidance.
Full Year Guidance
2025 Guidance (February)
Updated 2025 Guidance
Low
Mid
High
Low
Mid
High
Total Equivalent Production (MBoed)
710
—
740
—
770
772
—
777
—
782
Gas (Mmcf/day)
2,675
—
2,775
—
2,875
2,925
—
2,945
—
2,965
Oil (MBbl/day)
152
—
160
—
168
159
—
160
—
161
Net wells turned in line
Marcellus Shale
10
—
13
—
15
9
—
13
Permian Basin
150
—
158
—
165
165
Anadarko Basin
15
—
20
—
25
20
Capital expenditures ($ in millions)
Total Company
$2,100
—
$2,250
—
$2,400
$2,310
Drilling and completion
Marcellus Shale
$250 midpoint
$320
Permian Basin
$1,570 midpoint
$1,560
Anadarko Basin
$230 midpoint
$230
Midstream, saltwater disposal and infrastructure
$200 midpoint
$200
Commodity price assumptions:
WTI ($ per bbl)
$71
$65
Henry Hub ($ per mmbtu)
$4.22
$3.41
Cash Flow & Investment ($ in billions)
Discretionary Cash Flow
$5.0
$4.3
Capital Expenditures
$2.1
—
$2.3
—
$2.4
$2.3
Free Cash Flow (DCF - incurred capex)
$2.7
$2.0
$ per boe, unless noted:
Lease operating expense + workovers + region office
$2.50
—
$3.05
—
$3.60
No change
Gathering, processing, & transportation
$3.25
—
$3.75
—
$4.25
No change
Taxes other than income
$1.25
—
$1.50
—
$1.75
No change
General & administrative (1)
$0.90
—
$1.00
—
$1.10
No change
Unit Operating Cost
$7.90
—
$9.30
—
$10.70
No change
Excludes stock-based compensation and severance expense
Quarterly Guidance
Third Quarter 2025
Guidance
Third Quarter
2025 Actual
Fourth Quarter 2025
Guidance
Low
Mid
High
Low
Mid
High
Total Equivalent Production (MBoed)
740
—
765
—
790
785.0
770
—
790
—
810
Gas (Mmcf/day)
2,750
—
2,825
—
2,900
2,894.6
2,775
—
2,850
—
2,925
Oil (MBbl/day)
158
—
163
—
168
166.8
172
—
175
—
178
Net wells turned in line
Marcellus Shale
4
4
2
—
6
Permian Basin
40
—
45
—
50
38
41
Anadarko Basin
6
6
5
Capital expenditures ($ in millions)
Total Company
$625
—
$650
—
$675
$658
$530