Coterra Energy Inc. (NYSE:CTRA) ("Coterra" or the "Company") today reported second-quarter 2025 financial and operating results and declared a quarterly dividend of $0.22 per share. Additionally, the Company provided third-quarter production and capital guidance and updated full-year 2025 guidance.

Tom Jorden, Chairman, CEO and President of Coterra, noted, "We are pleased to report an excellent quarter with strong capital efficiency driven by lower than expected capital expenditures and higher than expected production.

"We are expecting to run consistent activity in the second half of 2025, with nine rigs in the Permian, two rigs in the Marcellus, and one to two rigs in the Anadarko. Our high-quality assets provide robust returns in the current environment and remain durable through the cycles. While we maintain significant operational flexibility, we expect our steady activity cadence to support a highly capital efficient 2026.

"Coterra provides a unique and compelling investment opportunity, with durable cash flows supported by the Company's diversified commodity mix and differentiated inventory depth and quality, all supported by a peer-leading balance sheet."

Key Takeaways & Updates

For the second quarter of 2025, total BOE (barrels of oil equivalent) and natural gas production exceeded the high-end of our guidance ranges while oil volumes beat the midpoint by approximately 2%. Capital expenditures (non-GAAP) were below the low-end of our guidance range.
Increasing full-year 2025 total equivalent and natural gas production guidance, maintaining oil production midpoint.
Expect 2025 capital expenditures (non-GAAP) to be approximately $2.3 billion, which assumes consistent activity in the second half of the year with nine rigs in the Permian, two rigs in the Marcellus, and one to two rigs in the Anadarko.
Expect 2025 Free Cash Flow (non-GAAP) to total $2.1 billion, at recent strip prices.
Second-quarter 2025 direct shareholder returns totaled approximately 58% of Free Cash Flow (non-GAAP), which includes our declared dividend of $0.22 per share, or approximately $168 million, and $23 million of share repurchases. Additionally, the Company repaid $100 million of term loans bringing total returns to 89% of Free Cash Flow (non-GAAP). In 2025, Coterra remains committed to reducing leverage and executing opportunistic share repurchases.
Announcing a new power netback gas sale agreement in the Permian, expected to start in 2028, further diversifying our natural gas marketing portfolio.
Coterra published its 2025 Sustainability Report on August 4, 2025. The report can be found under "Sustainability" on the Company's website.

Second-Quarter 2025 Highlights

Net Income (GAAP) totaled $511 million, or $0.67 per share. Adjusted Net Income (non-GAAP) was $367 million, or $0.48 per share.
Cash Flow From Operating Activities (GAAP) totaled $937 million. Discretionary Cash Flow (non-GAAP) totaled $949 million. Free Cash Flow (non-GAAP) totaled $329 million.
Cash paid for capital expenditures for drilling, completion and other fixed asset additions (GAAP) totaled $620 million. Incurred capital expenditures from drilling, completion and other fixed asset additions (non-GAAP) totaled $569 million, below the low end of our guidance range of $575 to $650 million.
Unit operating cost (reflecting costs from direct operations, transportation, production taxes and G&A) totaled $9.34 per BOE, near the mid-point of our annual guidance range.
Total equivalent production of 783.9 MBoepd (thousand barrels of oil equivalent per day), above the high end of guidance (710 to 760 MBoepd).
- Oil production averaged 155.4 MBopd (thousand barrels of oil per day), near the high end of our guidance range (147 to 157 MBopd).
- Natural gas production averaged 2,998.6 MMcfpd (million cubic feet of gas per day), exceeding the high end of guidance (2,700 to 2,850 MMcfpd).
- NGLs production averaged 128.7 MBopd.
Realized average prices:
- Oil was $62.80 per Bbl (barrel), excluding the effect of commodity derivatives, and $64.01 per Bbl, including the effect of commodity derivatives.
- Natural Gas was $2.20 per Mcf (thousand cubic feet), excluding the effect of commodity derivatives, and $2.27 per Mcf, including the effect of commodity derivatives.
- NGLs were $18.72 per Bbl.

Shareholder Return Highlights

Common Dividend: On August 4, 2025, Coterra's Board of Directors approved a quarterly dividend of $0.22 per share, equating to a 3.6% annualized yield, based on the Company's $24.39 closing share price on July 31, 2025. The dividend will be paid on August 28, 2025 to holders of record on August 14, 2025.
Share Repurchases: During the quarter, the Company repurchased 0.9 million shares for $23 million, leaving $1.1 billion remaining as of June 30, 2025 on its $2.0 billion share repurchase authorization.
Shareholder Returns: During the quarter, direct shareholder returns amounted to approximately $191 million, comprised of approximately $168 million of declared dividends and $23 million of share repurchases, totaling approximately 58% of Free Cash Flow (non-GAAP).The Company also repaid $100 million of debt during the quarter.
Reiterate Shareholder Return Strategy: Coterra expects to return 50% or greater of annual Free Cash Flow (non-GAAP) to shareholders through the cycles via its base dividend and share repurchases. However, in 2025, after payment of its base dividend, the Company is prioritizing debt reduction as it looks to retire the outstanding $650 million term loans, associated with the Company's Delaware Basin acquisition in first quarter. Coterra retired $350 million of term loans in the first half of 2025.

Guidance Updates

Expect 2025 capital expenditures (non-GAAP) of approximately $2.3 billion.
Announcing third-quarter 2025 guidance, including total equivalent production of 740 to 790 MBoepd, oil production of 158 to 168 MBopd, natural gas production of 2,750 to 2,900 MMcfpd, and capital expenditures (non-GAAP) of $625 to $675 million.
Estimate full-year 2025 effective tax rate of 22%, which we expect to be 40% to 60% current tax.
For more details on annual and third-quarter 2025 guidance, see 2025 Guidance Section in the tables below.

Announcing New Power Sales Agreement in the Permian

Coterra is announcing a new power netback gas sale agreement with CPV Basin Ranch Energy Center, a proposed 1,350 megawatt (MW) combined-cycle natural gas power plant designed with the option to include a carbon capture system. The agreement to sell 50 MMcf per day for a seven-year term is expected to start in 2028, and will be indexed to ERCOT West pricing, adding to the Company's two existing power netback deals in the Marcellus which currently comprise 330 MMcf per day. Coterra has also secured a right to purchase up to 250 MW per day of power from the facility, located in Ward County, Texas. This is the first power netback deal secured by Coterra in the Permian Basin. Coterra will continue to explore ways to further diversify its gas sales portfolio across all three of its operating basins through power, LNG, data centers and other long-term opportunities.

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 $350 million of the term loans year-to-date, including an incremental $100 million during the second quarter, leaving $650 million of term loan debt outstanding. As of June 30, 2025, Coterra had total debt outstanding of $4.15 billion (principal balance). The Company exited the quarter with cash and cash equivalents of $192 million, and no debt outstanding under its $2.0 billion revolving credit facility, resulting in total liquidity of approximately $2.19 billion. Coterra's Net Debt to trailing twelve-month Adjusted Pro Forma EBITDAX ratio (non-GAAP) at June 30, 2025 was 0.9x, pro forma for the Franklin and Avant acquisitions. The Company remains committed to 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.

Second-Quarter 2025 Conference Call

Coterra will host a conference call tomorrow, Tuesday, August 5, 2025, at 9:00 AM CT (10:00 AM ET), to discuss second-quarter 2025 financial and operating results.

Conference Call Information

Date: August 5, 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 June 30,					Six Months Ended June 30,
	2025		2024			2025		2024
PRODUCTION VOLUMES
Marcellus Shale
Natural gas (Mmcf/day)		2,061.3		2,114.4			2,146.4		2,212.6
Daily equivalent production (MBoepd)		343.5		352.4			357.7		368.8

Permian Basin
Natural gas (Mmcf/day)		669.4		484.5			627.1		485.6
Oil (MBbl/day)		148.1		99.6			140.6		98.3
NGL (MBbl/day)		98.9		78.1			86.0		74.1
Daily equivalent production (MBoepd)		358.6		258.4			331.2		253.3

Anadarko Basin
Natural gas (Mmcf/day)		266.5		179.4			246.1		170.3
Oil (MBbl/day)		7.2		7.5			7.6		6.5
NGL (MBbl/day)		29.6		20.6			27.4		20.3
Daily equivalent production (MBoepd)		81.3		58.0			76.1		55.2

Total Company
Natural gas (Mmcf/day)		2,998.6		2,779.8			3,021.1		2,869.9
Oil (MBbl/day)		155.4		107.2			148.4		104.9
NGL (MBbl/day)		128.7		98.8			113.6		94.5
Daily equivalent production (MBoepd)		783.9		669.2			765.4		677.7

AVERAGE SALES PRICE (excluding hedges)
Marcellus Shale
Natural gas ($/Mcf)	$	2.57	$	1.66		$	3.13	$	1.94

Permian Basin
Natural gas ($/Mcf)	$	0.88	$	(0.53	)	$	1.28	$	0.25
Oil ($/Bbl)	$	62.76	$	79.37		$	66.02	$	77.30
NGL ($/Bbl)	$	17.98	$	18.95		$	19.66	$	19.70

Anadarko Basin
Natural gas ($/Mcf)	$	2.66	$	1.35		$	3.03	$	1.70
Oil ($/Bbl)	$	63.25	$	79.40		$	67.10	$	77.45
NGL ($/Bbl)	$	21.20	$	21.75		$	23.81	$	22.39

Total Company
Natural gas ($/Mcf)	$	2.20	$	1.26		$	2.74	$	1.64
Oil ($/Bbl)	$	62.80	$	79.37		$	66.08	$	77.31
NGL ($/Bbl)	$	18.72	$	19.53		$	20.66	$	20.28


	Quarter Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
AVERAGE SALES PRICE (including hedges)
Total Company
Natural gas ($/Mcf)	$	2.27	$	1.40	$	2.74	$	1.76
Oil ($/Bbl)	$	64.01	$	79.39	$	66.52	$	77.25
NGL ($/Bbl)	$	18.72	$	19.53	$	20.66	$	20.28


	Quarter Ended June 30,		Six Months Ended June 30,
	2025	2024	2025	2024
WELLS DRILLED⁽¹⁾⁽²⁾
Gross wells
Marcellus Shale	13	8	13	22
Permian Basin	110	63	177	111
Anadarko Basin	6	11	14	19
	129	82	204	152

Net wells
Marcellus Shale	6.3	8.0	6.3	21.0
Permian Basin	37.6	26.8	82.7	50.0
Anadarko Basin	4.4	7.0	10.0	13.7
	48.3	41.8	99.0	84.7

TURN IN LINES⁽²⁾
Gross wells
Marcellus Shale	3	12	8	23
Permian Basin	120	56	181	98
Anadarko Basin	24	26	28	31
	147	94	217	152

Net wells
Marcellus Shale	3.0	12.0	3.0	23.0
Permian Basin	49.4	22.6	86.5	44.5
Anadarko Basin	9.1	15.2	9.3	15.3
	61.5	49.8	98.8	82.8

AVERAGE OPERATED RIG COUNTS
Marcellus Shale	2.0	1.2	1.0	1.6
Permian Basin	10.9	8.0	11.3	8.0
Anadarko Basin	2.0	1.3	1.9	1.7

___________________________________
(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 June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
AVERAGE UNIT COSTS ($/Boe) ⁽¹⁾
Direct operations	$	3.32	$	2.62	$	3.26	$	2.56
Gathering, processing and transportation		3.81		3.99		4.00		3.99
Taxes other than income		1.21		0.89		1.32		1.04
General and administrative (excluding stock-based compensation)		1.00		0.85		1.06		0.92
Unit Operating Cost	$	9.34	$	8.35	$	9.64	$	8.52
Depreciation, depletion and amortization		8.11		7.34		7.83		7.12
Exploration		0.07		0.09		0.10		0.08
Stock-based compensation		0.18		0.26		0.21		0.24
Interest expense, net		0.71		0.23		0.69		0.15
	$	18.41	$	16.26	$	18.48	$	16.10

___________________________________
(1)	Total unit costs may differ from the sum of the individual costs due to rounding.





Derivatives Information

As of June 30, 2025, the Company had the following outstanding financial commodity derivatives:

	2025
Oil	Third Quarter		Fourth Quarter
WTI oil collars
Volume (MBbl)		5,152		5,152
Weighted average floor ($/Bbl)	$	61.34	$	61.34
Weighted average ceiling ($/Bbl)	$	79.00	$	79.00

WTI NYMEX oil swaps
Volume (MBbl)		1,748		1,748
Weighted average price ($/Bbl)	$	69.18	$	69.18

WTI Midland oil basis swaps
Volume (MBbl)		5,520		5,520
Weighted average differential ($/Bbl)	$	1.02	$	1.02


	2026
Oil	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
WTI oil collars
Volume (MBbl)		2,700		2,730		2,760		2,760
Weighted average floor ($/Bbl)	$	56.67	$	56.67	$	56.67	$	56.67
Weighted average ceiling ($/Bbl)	$	70.68	$	70.68	$	70.68	$	70.68

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)		1,800		1,820		1,840		1,840
Weighted average differential ($/Bbl)	$	0.95	$	0.95	$	0.95	$	0.95


	2025
Natural Gas	Third Quarter			Fourth Quarter
NYMEX gas collars
Volume (MMBtu)		87,400,000			87,400,000
Weighted average floor ($/MMBtu)	$	3.08		$	3.08
Weighted average ceiling ($/MMBtu)	$	4.88		$	5.66

Transco Leidy gas basis swaps
Volume (MMBtu)		18,400,000			18,400,000
Weighted average differential ($/MMBtu)	$	(0.70	)	$	(0.70	)

Transco Zone 6 Non-NY gas basis swaps
Volume (MMBtu)		18,400,000			18,400,000
Weighted average differential ($/MMBtu)	$	(0.49	)	$	(0.49	)

Waha gas basis swaps
Volume (MMBtu)		13,800,000			13,800,000
Weighted average differential ($/MMBtu)	$	(2.05	)	$	(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

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 June 30,						Six Months Ended June 30,
(In millions, except per share amounts)		2025			2024			2025			2024
OPERATING REVENUES
Oil	$	888		$	774		$	1,774		$	1,475
Natural gas		601			319			1,499			857
NGL		219			176			425			349
Gain (loss) on derivative instruments		232			(16	)		120			(16	)
Other		25			18			51			39
		1,965			1,271			3,869			2,704
OPERATING EXPENSES
Direct operations		236			160			452			316
Gathering, processing and transportation		271			242			553			492
Taxes other than income		87			54			183			128
Exploration		4			5			14			10
Depreciation, depletion and amortization		579			447			1,085			879
General and administrative (excluding stock-based compensation)		70			52			146			114
Stock-based compensation		14			16			30			29
		1,261			976			2,463			1,968
Gain on sale of assets		4			1			4			—
INCOME FROM OPERATIONS		708			296			1,410			736
Interest expense		53			34			106			53
Interest income		(2	)		(19	)		(10	)		(35	)
Other (income) expense		(1	)		—			(1	)		—
Income before income taxes		658			281			1,315			718
Income tax provision (benefit)
Current		97			62			227			169
Deferred		50			(1	)		61			(23	)
Total income tax provision		147			61			288			146
NET INCOME	$	511		$	220		$	1,027		$	572
Earnings per share - Basic	$	0.67		$	0.30		$	1.35		$	0.77
Weighted-average common shares outstanding		763			742			759			746





CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)

(In millions)	June 30, 2025		December 31, 2024
ASSETS
Cash and cash equivalents	$	192	$	2,038
Other current assets		1,330		1,283
Properties and equipment, net (successful efforts method)		22,097		17,890
Other assets		363		414
	$	23,982	$	21,625

LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY
Current liabilities	$	1,352	$	1,136
Long-term debt, net		4,175		3,535
Deferred income taxes		3,331		3,274
Other long term liabilities		560		550
Cimarex redeemable preferred stock		8		8
Stockholders' equity		14,556		13,122
	$	23,982	$	21,625





CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)

	Quarter Ended June 30,						Six Months Ended June 30,
(In millions)		2025			2024			2025			2024
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	511		$	220		$	1,027		$	572
Depreciation, depletion and amortization		579			447			1,085			879
Deferred income tax expense (benefit)		50			(1	)		61			(23	)
Gain on sale of assets		(4	)		(1	)		(4	)		—
Gain (loss) on derivative instruments		(232	)		16			(120	)		16
Net cash received in settlement of derivative instruments		35			36			13			62
Stock-based compensation and other		15			13			30			25
Income charges not requiring cash		(5	)		(5	)		(9	)		(9	)
Changes in assets and liabilities		(12	)		(167	)		(3	)		(108	)
Net cash provided by operating activities		937			558			2,080			1,414

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for drilling, completion and other fixed asset additions		(620	)		(479	)		(1,092	)		(936	)
Capital expenditures for leasehold and property acquisitions		(20	)		(2	)		(57	)		(3	)
Cash consideration paid for business combinations, net of cash received		(3	)		—			(3,222	)		—
Purchases of short-term investments		—			—			—			(250	)
Proceeds from sale of assets		4			1			4			1
Other		(3	)		—			(3	)		—
Net cash used in investing activities		(642	)		(480	)		(4,370	)		(1,188	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of debt		350			—			1,350			499
Repayments of debt		(450	)		—			(700	)		—
Common stock repurchases		(23	)		(140	)		(47	)		(290	)
Dividends paid		(168	)		(156	)		(346	)		(314	)
Tax withholding on vesting of stock awards		(3	)		—			(24	)		—
Other		(5	)		(1	)		(4	)		(7	)
Net cash provided by (used in) financing activities		(299	)		(297	)		229			(112	)
Net (decrease) increase in cash, cash equivalents and restricted cash	$	(4	)	$	(219	)	$	(2,061	)	$	114

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 June 30,						Six Months Ended June 30,
(In millions, except per share amounts)		2025			2024			2025			2024
As reported - net income	$	511		$	220		$	1,027		$	572
Reversal of selected items:
Gain on sale of assets		(4	)		(1	)		(4	)		—
(Gain) loss on derivative instruments⁽¹⁾		(197	)		52			(107	)		78
Stock-based compensation expense		14			16			30			29
Acquisition related expense		1			—			14			—
Tax effect on selected items		42			(15	)		18			(24	)
Adjusted net income	$	367		$	272		$	978		$	655
As reported - earnings per share	$	0.67		$	0.30		$	1.35		$	0.77
Per share impact of selected items		(0.19	)		0.07			(0.06	)		0.11
Adjusted earnings per share	$	0.48		$	0.37		$	1.29		$	0.88
Weighted-average common shares outstanding		763			742			759			746

___________________________________
(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 June 30,						Six Months Ended June 30,
(In millions)		2025			2024			2025			2024
Cash flow from operating activities		937		$	558		$	2,080		$	1,414
Changes in assets and liabilities		12			167			3			108
Discretionary cash flow		949			725			2,083			1,522
Cash paid for capital expenditures for drilling, completion and other fixed asset additions		(620	)		(479	)		(1,092	)		(936	)
Free Cash Flow	$	329		$	246		$	991		$	586



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 June 30,						Six Months Ended June 30,
(In millions)		2025			2024			2025		2024
Cash paid for capital expenditures for drilling, completion and other fixed asset additions (GAAP)	$	620		$	479		$	1,092	$	936
Change in accrued capital costs		(51	)		(2	)		29		(9	)
Capital expenditures for drilling, completion and other fixed asset additions (non-GAAP)	$	569		$	477		$	1,121	$	927





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 June 30,						Six Months Ended June 30,
(In millions)		2025			2024			2025			2024
Net income	$	511		$	220		$	1,027		$	572
Plus (less):
Interest expense		53			34			106			53
Interest income		(2	)		(19	)		(10	)		(35	)
Other income		(1	)		—			(1	)		—
Income tax expense		147			61			288			146
Depreciation, depletion and amortization		579			447			1,085			879
Exploration		4			5			14			10
Gain on sale of assets		(4	)		(1	)		(4	)		—
Non-cash (gain) loss on derivative instruments		(197	)		52			(107	)		78
Acquisition-related expenses		1			—			14			—
Stock-based compensation		14			16			30			29
Adjusted EBITDAX	$	1,105		$	815		$	2,442		$	1,732


	Trailing Twelve Months Ended
(In millions)	June 30, 2025			December 31, 2024
Net income	$	1,576		$	1,121
Plus (less):
Interest expense		159			106
Interest income		(37	)		(62	)
Other expense		(1	)		—
Income tax expense		366			224
Depreciation, depletion and amortization		2,046			1,840
Exploration		29			25
Gain on sale of assets		(7	)		(3	)
Non-cash (gain) loss on derivative instruments		(84	)		101
Acquisition-related expenses		14			—
Stock-based compensation		63			62
Adjusted EBITDAX (trailing twelve months)	$	4,124		$	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)	June 30, 2025			December 31, 2024
Pro forma net income	$	1,795		$	1,475
Plus (less):
Pro forma interest expense		234			250
Pro forma interest income		(37	)		(62	)
Pro forma other income		(1	)		—
Pro forma income tax expense		404			297
Pro forma depreciation, depletion and amortization		2,267			2,195
Pro forma exploration		29			25
Pro forma gain on sale of assets		(7	)		(3	)
Pro forma non-cash (gain) loss on derivative instruments		(84	)		101
Pro forma acquisition-related expenses		14			14
Pro forma stock-based compensation		63			62
Adjusted Pro Forma EBITDAX (trailing twelve months)	$	4,677		$	4,354





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)	June 30, 2025			December 31, 2024
Long-term debt, net		4,175			3,535
Total debt		4,175			3,535
Stockholders' equity		14,556			13,122
Total capitalization	$	18,731		$	16,657

Total debt	$	4,175		$	3,535
Less: Cash and cash equivalents		(192	)		(2,038	)
Net debt	$	3,983		$	1,497

Net debt	$	3,983		$	1,497
Stockholders' equity		14,556			13,122
Total adjusted capitalization	$	18,539		$	14,619

Total debt to total capitalization ratio		22.3	%		21.2	%
Less: Impact of cash and cash equivalents		0.8	%		11.0	%
Net debt to adjusted capitalization ratio		21.5	%		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)	June 30, 2025			December 31, 2024
Total debt	$	4,175		$	3,535
Net income		1,576			1,121
Total debt to net income ratio	2.6		x	3.2		x

Net debt (as defined above)	$	3,983		$	1,497
Adjusted EBITDAX (Trailing twelve months)	$	4,124		$	3,414
Net debt to Adjusted EBITDAX	1.0		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)	June 30, 2025			December 31, 2024
Total debt	$	4,175		$	3,535
Net income		1,576			1,121
Total debt to net income ratio	2.6		x	3.2		x

Net debt (as defined above)	$	3,983		$	1,497
Adjusted Pro Forma EBITDAX (Trailing twelve months)		4,677			4,354
Net debt to Adjusted Pro Forma EBITDAX	0.9		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	755	—	768	—	780
Gas (Mmcf/day)	2,675	—	2,775	—	2,875	2,875	—	2,913	—	2,950
Oil (MBbl/day)	152	—	160	—	168	157	—	160	—	163

Net wells turned in line
Marcellus Shale	10	—	13	—	15	No change
Permian Basin	150	—	158	—	165	No change
Anadarko Basin	15	—	20	—	25	No change

Capital expenditures ($ in millions)
Total Company	$2,100	—	$2,250	—	$2,400	$2,100	—	$2,200	—	$2,300
Drilling and completion
Marcellus Shale	$250 midpoint									$350
Permian Basin	$1,570 midpoint									$1,520
Anadarko Basin	$230 midpoint									$230
Midstream, saltwater disposal and infrastructure	$200 midpoint									$200

Commodity price assumptions:
WTI ($ per bbl)			$71					$66
Henry Hub ($ per mmbtu)			$4.22					$3.67

Cash Flow & Investment ($ in billions)
Discretionary Cash Flow			$5.0							$4.4
Capital Expenditures	$2.1	—	$2.3	—	$2.4	$2.1	—	$2.2	—	$2.3
Free Cash Flow (DCF - incurred capex)			$2.7							$2.1

$ 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
	Second Quarter 2025 Guidance					Second Quarter 202 Actual	Third Quarter 2025 Guidance
	Low		Mid		High		Low		Mid		High
Total Equivalent Production (MBoed)	710	—	735	—	760	783.9	740	—	765	—	790
Gas (Mmcf/day)	2,700	—	2,775	—	2,850	2,998.6	2,750	—	2,825	—	2,900
Oil (MBbl/day)	147	—	152	—	157	155.4	158	—	163	—	168

Net wells turned in line
Marcellus Shale			3			3			4
Permian Basin	45	—	55	—	65	49	40	—	45	—	50
Anadarko Basin			9			9			6

Capital expenditures ($ in millions)
Total Company	$575	—	$613	—	$650	$569	$625	—	$650	—	$675

View source version on businesswire.com: https://www.businesswire.com/news/home/20250804649509/en/

Investor Contact

Daniel Guffey - Vice President of Finance, IR & Treasurer

281.589.4875

Hannah Stuckey - Investor Relations Manager

281.589.4983

Coterra Energy Reports Second-Quarter 2025 Results, Announces Quarterly Dividend, and Provides Guidance Update