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

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

Tom Jorden, Chairman, CEO and President of Coterra, noted, "The company's top-tier balance sheet, diversified portfolio of high-quality oil and natural gas-focused assets and low reinvestment rate position Coterra to prosper throughout cyclical commodity price environments."

"As our industry faces macroeconomic uncertainty and oil price headwinds, we believe it is prudent to reduce oil-directed activity at this time. As such, we are lowering Permian investment in 2025 and now expect to average seven Permian rigs during the second half of the year, down 30% from our original guidance of ten. As planned, we added two natural gas-focused rigs in the Marcellus in April and may keep this activity running for the balance of 2025. These decisions to reduce and reallocate capital bolster free cash flow in 2025, allow for a conservative investment ratio at lower commodity prices, and allow us to maintain our oil production guidance while slightly increasing our natural gas and BOE volumes for 2025. Additionally, these actions support free cash flow upside over the medium and long-term while generating attractive full-cycle returns in each of our operating regions in the current environment."

Mr. Jorden continued, "Due to the short-term nature of our service contracts and limited marketing commitments, Coterra maintains significant flexibility to adjust our capital investment and maintains a series of activity off-ramps in 2025 that could further reduce activity and investment should fundamentals warrant. The Company remains committed to further reducing debt in 2025 to ensure we maintain one of the best balance sheets in our industry."

Key Takeaways & Updates

• For the first quarter of 2025, total barrels of oil equivalent (BOE) production, natural gas production, and oil production were all above the midpoint of guidance, and capital expenditures (non-GAAP) were below the midpoint of guidance.
• Raising BOE and natural gas production guidance at the midpoint and maintaining full-year 2025 oil production midpoint guidance.
• Lowering 2025 capital budget range to $2.0 to $2.3 billion, driven by less oil-directed activity partially offset by higher natural gas-directed activity. The Company's reinvestment rate (non-GAAP), which is capital expenditures (non-GAAP) as a percentage of Discretionary Cash Flow, at recent strip prices, is expected to remain conservative at approximately 50% in 2025.
  • Reducing 2025 Permian activity to seven rigs from our original plan of ten rigs during the second half of 2025 and reducing total Permian capital by approximately $150 million.
  • Added two Marcellus rigs in April, as planned. We now expect to keep both rigs running into the second half of 2025, adding an incremental $50 million of capital to our 2025 Marcellus program. We also maintain an option to keep the second rig running through year-end, which could add an incremental $50 million of capital in the year. We expect to make this decision during the third quarter.
• Expected 2025 Free Cash Flow to total $2.1 billion, at recent strip prices, which we expect will be used to fund our dividend, reduce debt and execute share repurchases.
• First-quarter 2025 direct shareholder returns totaled approximately 30% of Free Cash Flow (non-GAAP), which included our declared dividend of $0.22, or approximately $168 million, and $24 million of share repurchases (cash basis, excluding 1% excise tax). Additionally, the Company repaid $250 million of term loans bringing total returns to 67% of Free Cash Flow (non-GAAP). In 2025, Coterra remains committed to reducing leverage and executing opportunistic share repurchases.

First-Quarter 2025 Highlights

• Net Income (GAAP) totaled $516 million, or $0.68 per share. Adjusted Net Income (non-GAAP) was $608 million, or $0.80 per share.
• Cash Flow From Operating Activities (GAAP) totaled $1,144 million. Discretionary Cash Flow (non-GAAP) totaled $1,135 million. Free Cash Flow (non-GAAP) totaled $663 million.
• Cash paid for capital expenditures for drilling, completion and other fixed asset additions (GAAP) totaled $472 million. Incurred capital expenditures from drilling, completion and other fixed asset additions (non-GAAP) totaled $552 million, in the lower half of our guidance range of $525 to $625 million.
• Unit operating cost (reflecting costs from direct operations, transportation, production taxes and G&A) totaled $9.97 per Boe.
• Total equivalent production of 747 MBoepd (thousand barrels of oil equivalent per day), near the high-end of guidance (710 to 750 MBoepd).
  • Oil production averaged 141.2 MBopd (thousand barrels of oil per day), approximately 2% above the midpoint of our guidance range (134 to 144 MBopd).
  • Natural gas production averaged 3,044 MMcfpd (million cubic feet of gas per day), exceeding the high end of guidance (2,850 to 3,000 MMcfpd).
  • NGLs production averaged 98.3 MBopd.
• Realized average prices:
  • Oil was $69.73 per Bbl (barrel), excluding the effect of commodity derivatives, and $69.30 per Bbl, including the effect of commodity derivatives.
  • Natural Gas was $3.28 per Mcf (thousand cubic feet), excluding the effect of commodity derivatives, and $3.21 per Mcf, including the effect of commodity derivatives.
  • NGLs were $23.23 per Bbl.
• Closed the Franklin Mountain Energy and Avant Natural Resources acquisitions in late January.

Shareholder Return Highlights

• Common Dividend: On May 5, 2025, Coterra's Board of Directors (the "Board") approved a quarterly dividend of $0.22 per share, equating to a 3.4% annualized yield, based on the Company's $25.67 closing share price on May 2, 2025. The dividend will be paid on May 29, 2025 to holders of record on May 15, 2025.
• Share Repurchases: During the quarter, the Company repurchased 0.9 million shares for $24 million at a weighted-average price of approximately $27.54 per share, leaving $1.1 billion remaining as of March 31, 2025 on its $2.0 billion share repurchase authorization.
• Shareholder Return: During the quarter, direct shareholder returns amounted to approximately $192 million, comprised of approximately $168 million of declared dividends and $24 million of share repurchases. The Company also repaid $250 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 $750 million term loans, which mature in 2027 and 2028.

Guidance Updates

• Lowered 2025 capital expenditures range (non-GAAP) to $2.0 to $2.3 billion, down from $2.1 to $2.4 billion.
  • After closing our recent acquisitions in January, we exited the first quarter with 13 rigs in the Permian. Our original plan called for ten rigs in the second half of 2025, but we now plan to operate seven rigs in the second half of the year.
• Announcing second-quarter 2025 total equivalent production of 710 to 760 MBoepd, oil production of 147 to 157 MBopd, natural gas production of 2,700 to 2,850 MMcfpd, and capital expenditures (non-GAAP) of $575 to $650 million.
• Estimate 2025 Discretionary Cash Flow (non-GAAP) of approximately $4.3 billion and 2025 Free Cash Flow (non-GAAP) of approximately $2.1 billion, at approximately $63 per bbl WTI and $3.70 per mmbtu (metric million British thermal unit) annual average NYMEX assumptions.
• For more details on annual and second 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 paid down $250 million of the term loans prior to the end of the first quarter, leaving $750 million of term loan debt outstanding. As of March 31, 2025, Coterra had total debt outstanding of $4.25 billion (principal balance). The Company exited the quarter with cash and cash equivalents of $186 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 March 31, 2025 was 0.9x, pro forma 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 "ESG" on www.coterra.com. Coterra published its 2024 Sustainability report on August 1, 2024.

First-Quarter 2025 Conference Call

Coterra will host a conference call tomorrow, Tuesday, May 6, 2025, at 9:00 AM CT (10:00 AM ET), to discuss first-quarter 2025 financial and operating results.

Conference Call Information

Date: May 6, 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 operations focused 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:

		Three Months Ended March 31,
			2025			2024
PRODUCTION VOLUMES
Marcellus Shale
Natural gas (Mmcf/day)			2,232.6			2,310.8
Daily equivalent production (MBoepd)			372.1			385.1
Permian Basin
Natural gas (Mmcf/day)			584.3			486.7
Oil (MBbl/day)			133.1			97.0
NGL (MBbl/day)			73.0			70.1
Daily equivalent production (MBoepd)			303.4			248.2
Anadarko Basin
Natural gas (Mmcf/day)			225.4			161.2
Oil (MBbl/day)			8.0			5.5
NGL (MBbl/day)			25.3			20.1
Daily equivalent production (MBoepd)			70.8			52.4
Total Company
Natural gas (Mmcf/day)			3,043.8			2,960.1
Oil (MBbl/day)			141.2			102.5
NGL (MBbl/day)			98.3			90.2
Daily equivalent production (MBoepd)			746.8			686.1
AVERAGE SALES PRICE (excluding hedges)
Marcellus Shale
Natural gas ($/Mcf)		$	3.65		$	2.20
Permian Basin
Natural gas ($/Mcf)		$	1.75		$	1.02
Oil ($/Bbl)		$	69.70		$	75.18
NGL ($/Bbl)		$	21.97		$	20.53
Anadarko Basin
Natural gas ($/Mcf)		$	3.48		$	2.10
Oil ($/Bbl)		$	70.64		$	74.78
NGL ($/Bbl)		$	26.91		$	23.05
Total Company
Natural gas ($/Mcf)		$	3.28		$	2.00
Oil ($/Bbl)		$	69.73		$	75.16
NGL ($/Bbl)		$	23.23		$	21.09

		Three Months Ended March 31,
			2025			2024
AVERAGE SALES PRICE (including hedges)
Total Company
Natural gas ($/Mcf)		$	3.21		$	2.10
Oil ($/Bbl)		$	69.30		$	75.00
NGL ($/Bbl)		$	23.23		$	21.09

		Three Months Ended March 31,
		2025		2024
WELLS DRILLED(1)
Gross wells
Marcellus Shale		—		14
Permian Basin		67		48
Anadarko Basin		8		8
		75		70
Net wells
Marcellus Shale		—		13.0
Permian Basin		45.1		23.2
Anadarko Basin		5.6		6.7
		50.7		42.9
TURN IN LINES
Gross wells
Marcellus Shale		5		11
Permian Basin		61		42
Anadarko Basin		4		5
		70		58
Net wells
Marcellus Shale		—		11.0
Permian Basin		37.1		21.9
Anadarko Basin		0.2		0.1
		37.3		33.0
AVERAGE OPERATED RIG COUNTS
Marcellus Shale		—		2.0
Permian Basin		11.7		8.0
Anadarko Basin		1.8		2.0

_______________________________________________________________________________
(1)		Wells drilled represents wells drilled to total depth during the period.

		Three Months Ended March 31,
			2025			2024
AVERAGE UNIT COSTS ($/Boe) (1)
Direct operations		$	3.21		$	2.50
Gathering, processing and transportation			4.20			4.00
Taxes other than income			1.43			1.19
General and administrative (excluding stock-based compensation)			1.13			0.99
Unit Operating Cost		$	9.97		$	8.68
Depreciation, depletion and amortization			7.53			6.92
Exploration			0.15			0.07
Stock-based compensation			0.24			0.22
Interest expense, net			0.67			0.06
		$	18.55		$	15.94

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

Derivatives Information   As of March 31, 2025, the Company had the following outstanding financial commodity derivatives:
		2025
Oil		Second Quarter			Third Quarter			Fourth Quarter
WTI oil collars
Volume (MBbl)			5,096			4,232			4,232
Weighted average floor ($/Bbl)		$	61.79		$	61.63		$	61.63
Weighted average ceiling ($/Bbl)		$	79.36		$	78.64		$	78.64
WTI oil swaps
Volume			1,729			1,748			1,748
Weighted average price ($/Bbl)		$	69.18		$	69.18		$	69.18
WTI Midland oil basis swaps
Volume (MBbl)			6,370			5,520			5,520
Weighted average price ($/Bbl)		$	1.07		$	1.02		$	1.02

		2026
Oil		First Quarter			Second Quarter			Third Quarter			Fourth Quarter
WTI oil collars
Volume (MBbl)			900			910			920			920
Weighted average floor ($/Bbl)		$	62.50		$	62.50		$	62.50		$	62.50
Weighted average ceiling ($/Bbl)		$	69.40		$	69.40		$	69.40		$	69.40
WTI 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		Second Quarter				Third Quarter				Fourth Quarter
NYMEX gas collars
Volume (MMBtu)			72,800,000				73,600,000				73,600,000
Weighted average floor ($/MMBtu)		$	3.01			$	3.01			$	3.01
Weighted average ceiling ($/MMBtu)		$	4.82			$	4.82			$	5.75
Transco Leidy gas basis swaps
Volume (MMBtu)			18,200,000				18,400,000				18,400,000
Weighted average differential ($/MMBtu)		$	(0.70	)		$	(0.70	)		$	(0.70	)
Transco Zone 6 Non-NY gas basis swaps
Volume (MMBtu)			18,200,000				18,400,000				18,400,000
Weighted average differential ($/MMBtu)		$	(0.49	)		$	(0.49	)		$	(0.49	)

		2026
Natural Gas		First Quarter			Second Quarter			Third Quarter			Fourth Quarter
NYMEX gas collars
Volume (MMBtu)			67,500,000			40,950,000			41,400,000			41,400,000
Weighted average floor ($/MMBtu)		$	2.97		$	3.11		$	3.11		$	3.11
Weighted average ceiling ($/MMBtu)		$	6.62		$	5.93		$	5.93		$	5.93

In April 2025, the Company entered into the following financial commodity derivatives:
		2025
Natural Gas		Second Quarter				Third Quarter				Fourth Quarter
NYMEX gas collars
Volume (MMBtu)			9,150,000				13,800,000				13,800,000
Weighted average floor ($/MMBtu)		$	3.50			$	3.50			$	3.50
Weighted average ceiling ($/MMBtu)		$	5.21			$	5.21			$	5.21
Waha gas basis swaps
Volume (MMBtu)			9,150,000				13,800,000				13,800,000
Weighted average differential ($/MMBtu)		$	(2.05	)		$	(2.05	)		$	(2.05	)

		2026
Natural Gas		First Quarter				Second Quarter				Third Quarter				Fourth Quarter
NYMEX gas collars
Volume (MMBtu)			13,500,000				13,650,000				13,800,000				13,800,000
Weighted average floor ($/MMBtu)		$	3.50			$	3.50			$	3.50			$	3.50
Weighted average ceiling ($/MMBtu)		$	5.24			$	5.24			$	5.24			$	5.24
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)
	Three Months Ended March 31,
(In millions, except per share amounts)		2025				2024
OPERATING REVENUES
Oil	$	886			$	701
Natural gas		898				538
NGL		206				173
Loss on derivative instruments		(112	)			—
Other		26				21
		1,904				1,433
OPERATING EXPENSES
Direct operations		216				156
Gathering, processing and transportation		282				250
Taxes other than income		96				74
Exploration		10				5
Depreciation, depletion and amortization		506				432
General and administrative (excluding stock-based compensation)		76				62
Stock-based compensation		16				13
		1,202				992
Loss on sale of assets		—				(1	)
INCOME FROM OPERATIONS		702				440
Interest expense		53				19
Interest income		(8	)			(16	)
Income before income taxes		657				437
Income tax provision (benefit)
Current		130				107
Deferred		11				(22	)
Total income tax provision		141				85
NET INCOME	$	516			$	352
Earnings per share - Basic	$	0.68			$	0.47
Weighted-average common shares outstanding		756				750

CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)
(In millions)	March 31, 2025			December 31, 2024
ASSETS
Cash and cash equivalents	$	186		$	2,038
Other current assets		1,260			1,283
Properties and equipment, net (successful efforts method)		22,081			17,890
Other assets		424			414
	$	23,951		$	21,625
LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY
Current liabilities	$	1,608		$	1,136
Long-term debt, net		4,280			3,535
Deferred income taxes		3,285			3,274
Other long term liabilities		546			550
Cimarex redeemable preferred stock		8			8
Stockholders’ equity		14,224			13,122
	$	23,951		$	21,625

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)
	Three Months Ended March 31,
(In millions)		2025				2024
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	516			$	352
Depreciation, depletion and amortization		506				432
Deferred income tax expense (benefit)		11				(22	)
Loss on sale of assets		—				1
Loss on derivative instruments		112				—
Net cash (paid) received in settlement of derivative instruments		(22	)			26
Stock-based compensation and other		15				12
Income charges not requiring cash		(3	)			(4	)
Changes in assets and liabilities		9				59
Net cash provided by operating activities		1,144				856
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for drilling, completion and other fixed asset additions		(472	)			(457	)
Capital expenditures for leasehold and property acquisitions		(37	)			(1	)
Cash consideration paid for business combinations		(3,219	)			—
Purchases of short-term investments		—				(250	)
Net cash used in investing activities		(3,728	)			(708	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of debt		1,000				499
Repayments of debt		(250	)			—
Common stock repurchases		(24	)			(150	)
Dividends paid		(178	)			(158	)
Tax withholding on vesting of stock awards		(21	)			—
Other		1				(6	)
Net cash provided by financing activities		528				185
Net increase (decrease) in cash, cash equivalents and restricted cash	$	(2,056	)		$	333

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.
		Three Months Ended March 31,
(In millions)			2025			2024
Cash paid for capital expenditures for drilling, completion and other fixed asset additions (GAAP)		$	472		$	457
Change in accrued capital costs			80			(7	)
Capital expenditures for drilling, completion and other fixed asset additions (non-GAAP)		$	552		$	450

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.
		Three Months Ended March 31,
(In millions, except per share amounts)			2025				2024
As reported - net income		$	516			$	352
Reversal of selected items:
Loss on sale of assets			—				1
Loss on derivative instruments(1)			90				26
Stock-based compensation expense			16				13
Acquisition related expense			13				—
Tax effect on selected items			(27	)			(9	)
Adjusted net income		$	608			$	383
As reported - earnings per share		$	0.68			$	0.47
Per share impact of selected items			0.12				0.04
Adjusted earnings per share		$	0.80			$	0.51
Weighted-average common shares outstanding			756				750

_______________________________________________________________________________
(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

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.
		Three Months Ended March 31,
(In millions)			2025				2024
Cash flow from operating activities		$	1,144			$	856
Changes in assets and liabilities			(9	)			(59	)
Discretionary cash flow			1,135				797
Cash paid for capital expenditures for drilling, completion and other fixed asset additions			(472	)			(457	)
Free Cash Flow		$	663			$	340

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.
		Three Months Ended March 31,
(In millions)			2025				2024
Net income		$	516			$	352
Plus (less):
Interest expense			53				19
Interest income			(8	)			(16	)
Income tax expense			141				85
Depreciation, depletion and amortization			506				432
Exploration			10				5
Loss on sale of assets			—				1
Non-cash loss on derivative instruments			90				26
Acquisition-related expenses			13				—
Stock-based compensation			16				13
Adjusted EBITDAX		$	1,337			$	917

	Trailing Twelve Months Ended
(In millions)	March 31, 2025				December 31, 2024
Net income	$	1,285			$	1,121
Plus (less):
Interest expense		140				106
Interest income		(54	)			(62	)
Income tax expense		280				224
Depreciation, depletion and amortization		1,914				1,840
Exploration		30				25
Gain on sale of assets		(4	)			(3	)
Non-cash loss on derivative instruments		165				101
Acquisition-related expenses		13				—
Stock-based compensation		65				62
Adjusted EBITDAX (trailing twelve months)	$	3,834			$	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)	March 31, 2025				December 31, 2024
Pro forma net income	$	1,493			$	1,401
Plus (less):
Pro forma interest expense		251				250
Pro forma interest income		(54	)			(62	)
Pro forma income tax expense		338				290
Pro forma depreciation, depletion and amortization		2,240				2,197
Pro forma exploration		30				25
Pro forma gain on sale of assets		(4	)			(3	)
Pro forma non-cash loss on derivative instruments		291				101
Pro forma acquisition-related expenses		13				—
Pro forma stock-based compensation		65				62
Adjusted Pro Forma EBITDAX (trailing twelve months)	$	4,663			$	4,261

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)	March 31, 2025				December 31, 2024
Long-term debt, net		4,280				3,535
Total debt		4,280				3,535
Stockholders’ equity		14,224				13,122
Total capitalization	$	18,504			$	16,657
Total debt	$	4,280			$	3,535
Less: Cash and cash equivalents		(186	)			(2,038	)
Net debt	$	4,094			$	1,497
Net debt	$	4,094			$	1,497
Stockholders’ equity		14,224				13,122
Total adjusted capitalization	$	18,318			$	14,619
Total debt to total capitalization ratio		23.1	%			21.2	%
Less: Impact of cash and cash equivalents		0.8	%			11.0	%
Net debt to adjusted capitalization ratio		22.3	%			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)	March 31, 2025			December 31, 2024
Total debt	$	4,280		$	3,535
Net income		1,285			1,121
Total debt to net income ratio	3.3 x			3.2 x
Net debt (as defined above)	$	4,094		$	1,497
Adjusted EBITDAX (Trailing twelve months)	$	3,834		$	3,414
Net debt to Adjusted EBITDAX	1.1 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)	March 31, 2025			December 31, 2024
Total debt	$	4,280		$	3,535
Net income		1,285			1,121
Total debt to net income ratio	3.3 x			3.2 x
Net debt (as defined above)	$	4,094		$	1,497
Adjusted Pro Forma EBITDAX (Trailing twelve months)		4,663			4,261
Net debt to Adjusted EBITDAX	0.9 x			0.4 x

2025 Guidance
The tables below present full-year and second quarter 2025 guidance.
		Full Year Guidance
		2025 Guidance (February)						Updated 2025 Guidance
		Low		Mid		High		Low		Mid		High
Total Equivalent Production (MBoed)		710	—	740	—	770		720	—	745	—	770
Gas (Mmcf/day)		2,675	—	2,775	—	2,875		2,725	—	2,800	—	2,875
Oil (MBbl/day)		152	—	160	—	168		155	—	160	—	165
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		$2,000	—	$2,150	—	$2,300
Drilling and completion
Marcellus Shale		$250 midpoint						$300 midpoint
Permian Basin		$1,570 midpoint						$1,450 midpoint
Anadarko Basin		$230 midpoint						No change
Midstream, saltwater disposal and infrastructure		$200 midpoint						$170 midpoint
Commodity price assumptions:
WTI ($ per bbl)				$71						$63
Henry Hub ($ per mmbtu)				$4.22						$3.70
Cash Flow & Investment ($ in billions)
Discretionary Cash Flow				$5.0						$4.3
Capital Expenditures		$2.1	—	$2.3	—	$2.4		$2.0	—	$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
		First Quarter 2025 Guidance						First Quarter 2025 Actual		Second Quarter 2025 Guidance
		Low		Mid		High				Low		Mid		High
Total Equivalent Production (MBoed)		710	—	730	—	750		747		710	—	735	—	760
Gas (Mmcf/day)		2,850	—	2,925	—	3,000		3,044		2,700	—	2,775	—	2,850
Oil (MBbl/day)		134	—	139	—	144		141		147	—	152	—	157
Net wells turned in line
Marcellus Shale				0				0				3
Permian Basin		35	—	40	—	45		37.1		45	—	55	—	65
Anadarko Basin				0				0.2				9
Capital expenditures ($ in millions)
Total Company		$525	—	$575	—	$625		$552		$575	—	$613	—	$650

 

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Investor Contact

Daniel Guffey - Vice President of Finance, IR & Treasury

281.589.4875

Hannah Stuckey - Investor Relations Manager

281.589.4983

Source: Coterra Energy Inc.