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
- For the third quarter of 2025, total BOE (barrels of oil equivalent), natural gas production, and oil production all neared the high-end of our guidance ranges, with all streams beating their respective mid-points by approximately 2.5%. Incurred capital expenditures (non-GAAP) totaled $658 million, near the mid-point of our guidance range of $625 to $675 million.
- Increasing full-year 2025 total equivalent and natural gas production guidance and tightening the range around oil production guidance. Continue to expect 2025 capital expenditures (non-GAAP) around $2.3 billion, which assumes we continue to run nine rigs in the Permian, one to two rigs in the Marcellus, and one rig in the Anadarko during the fourth quarter. This delivers a full year 2025 reinvestment rate, defined as incurred capital expenditures as a percentage of Discretionary Cash Flow (non-GAAP), of approximately 55%.
- Expect 2025 Free Cash Flow (non-GAAP) of approximately $2.0 billion, at recent strip prices.
- Third-quarter 2025 declared dividend of $0.22 per share, or approximately $168 million on a cash basis. Additionally, the Company continued to prioritize debt repayment, repaying $250 million of term loans during the quarter. Coterra remains committed to reducing its leverage and maintaining its top-tier balance sheet. In addition, the Company resumed repurchasing its shares opportunistically in the fourth quarter.
- Coterra has accelerated its leasing ground game in 2025, acquiring $86 million of leasehold year-to-date, in addition to our customary acreage trade optimizations.
- Looking ahead, based on current expectations, the Company anticipates 2026 capital expenditures modestly down from 2025, while maintaining 0-5% annual BOE growth, and approximately 5% annual oil growth. Based on recent strip prices, the Company expects its 2026 reinvestment to be at, or below, 50%.
Third-Quarter 2025 Highlights
- Net Income (GAAP) totaled $322 million, or $0.42 per share. Adjusted Net Income (non-GAAP) was $312 million, or $0.41 per share.
- Cash Flow From Operating Activities (GAAP) totaled $971 million. Discretionary Cash Flow (non-GAAP) totaled $1,148 million. Free Cash Flow (non-GAAP) totaled $533 million.
- Cash paid for capital expenditures for drilling, completion, and other fixed asset additions (GAAP) totaled $615 million. Incurred capital expenditures from drilling, completion, and other fixed asset additions (non-GAAP) totaled $658 million, within our guidance range of $625 to $675 million.
- Unit operating cost (reflecting costs from direct operations, transportation, production taxes and G&A) totaled $9.81 per BOE, slightly above the mid-point of our annual guidance range. The Company expects fourth quarter per unit costs to trend closer to the mid-point of our annual guidance range.
- The Company turned in-line 48 net wells during the quarter. In the Permian, 38 net wells were turned in-line, slightly below our guidance of 40 to 50 net wells. Anadarko and Marcellus turned in-line six and four net wells, respectively, in line with guidance.
-
Total equivalent production averaged 785.0 MBoepd (thousand barrels of oil equivalent per day), near the high end of guidance (740 to 790 MBoepd).
- Oil production averaged 166.8 MBopd (thousand barrels of oil per day), near the high end of our guidance range (158 to 168 MBopd).
- Natural gas production averaged 2,894.6 MMcfpd (million cubic feet of gas per day), near the high end of guidance (2,750 to 2,900 MMcfpd).
- NGLs production averaged 135.8 MBopd.
-
Realized average prices:
- Oil was $64.10 per Bbl (barrel), excluding the effect of commodity derivatives, and $64.79 per Bbl, including the effect of commodity derivatives.
- Natural Gas was $1.95 per Mcf (thousand cubic feet), excluding the effect of commodity derivatives, and $2.05 per Mcf, including the effect of commodity derivatives.
- NGLs were $17.02 per Bbl.
Shareholder Return Highlights
- Common Dividend: On November 3, 2025, Coterra’s Board of Directors approved a quarterly dividend of $0.22 per share, equating to a 3.8% annualized yield, based on the Company’s $23.40 closing share price on October 30, 2025. The dividend will be paid on November 26, 2025 to holders of record on November 13, 2025. This will bring total dividends for the year to $504 million (cash basis) and total shareholder returns to nearly $551 million, through September 2025.
- Share Repurchases: As of September 30, 2025, $1.1 billion remains on the Company’s $2.0 billion share repurchase authorization. No shares were repurchased during the third quarter as the Company focused on the repayment of its term loans. The Company resumed share repurchases in October and expects to continue to opportunistically repurchase its shares in the fourth quarter.
- Reiterate Shareholder Return Strategy: Coterra remains committed to robust shareholder returns and expects to return 50% or greater of Free Cash Flow (non-GAAP) to shareholders through the cycles. Year-to-date, after payment of its base dividend, the Company prioritized debt reduction, retiring $600 million of the $1.0 billion term loans issued earlier in the year, associated with the Company’s Delaware Basin acquisition. During the fourth quarter, the Company restarted its share repurchase program. The Company will remain committed to debt reduction and opportunistic share repurchases.
Guidance Updates
- Continue to expect 2025 incurred capital expenditures (non-GAAP) around $2.3 billion.
- Increasing 2025 full-year guidance, including increasing total equivalent production range up to 772 to 782 MBoepd and natural gas production range up to 2,925 to 2,965 MMcfpd. Tightening the range around 2025 oil production to 159 to 161 MBopd.
- Announcing fourth-quarter 2025 guidance, including total equivalent production of 770 to 810 MBoepd, oil production of 172 to 178 MBopd, natural gas production of 2,775 to 2,925 MMcfpd, and capital expenditures (non-GAAP) of approximately $530 million.
- Estimate full-year 2025 effective tax rate of 22% and no cash taxes during fourth-quarter 2025.
- For more details on annual and fourth-quarter 2025 guidance, see 2025 Guidance Section in the tables below.
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 |
| ____________________ | |
| (1) |
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, |
|
December 31, |
||
|
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, |
|
December 31, |
||||
|
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, |
|
December 31, |
||||
|
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, |
|
December 31, |
||||
|
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, |
|
December 31, |
||||
|
Total debt |
$ |
3,922 |
|
$ |
3,535 |
||
|
Net income |
|
1,646 |
|
|
1,121 |
||
|
Total debt to net income ratio |
2.4 |
x |
|
3.2 |
x | ||
|
|
|
|
|
||||
|
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 |
x |
|
0.4 |
x | ||
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, |
|
December 31, |
||||
|
Total debt |
$ |
3,922 |
|
$ |
3,535 |
||
|
Net income |
|
1,646 |
|
|
1,121 |
||
|
Total debt to net income ratio |
2.4 |
x |
|
3.2 |
x | ||
|
|
|
|
|
||||
|
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 |
x |
|
0.3 |
x | ||
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 |
— |
$10.70 |
|
No change |
||||
| ____________________ | |
| (1) |
Excludes stock-based compensation and severance expense |
|
|
|
Quarterly Guidance |
||||||||||||
|
|
|
Third Quarter 2025 Guidance |
|
Third Quarter 2025 Actual |
|
Fourth Quarter 2025 Guidance |
||||||||
|
|
|
Low |
|
Mid |
|
High |
|
|
|
Low |
|
Mid |
|
High |
|
Total Equivalent Production (MBoed) |
|
740 |
— |
765 |
— |
790 |
|
785.0 |
|
770 |
— |
790 |
— |
810 |
|
Gas (Mmcf/day) |
|
2,750 |
— |
2,825 |
— |
2,900 |
|
2,894.6 |
|
2,775 |
— |
2,850 |
— |
2,925 |
|
Oil (MBbl/day) |
|
158 |
— |
163 |
— |
168 |
|
166.8 |
|
172 |
— |
175 |
— |
178 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net wells turned in line |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marcellus Shale |
|
|
|
4 |
|
|
|
4 |
|
2 |
— |
6 |
|
|
|
Permian Basin |
|
40 |
— |
45 |
— |
50 |
|
38 |
|
|
|
41 |
|
|
|
Anadarko Basin |
|
|
|
6 |
|
|
|
6 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures ($ in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Company |
|
$625 |
— |
$650 |
— |
$675 |
|
$658 |
|
|
|
$530 |
|
|
View source version on businesswire.com: https://www.businesswire.com/news/home/20251103792396/en/
Investor Contact
Daniel Guffey – Vice President of Finance, IR & Treasurer
281.589.4875
Hannah Stuckey – Investor Relations Manager
281.589.4983
KEYWORDS: United States North America Texas
INDUSTRY KEYWORDS: Oil/Gas Energy
MEDIA: