Coterra Energy Reports 2024 Results, Provides 2025 Guidance and Updated Three-Year Outlook, and Announces Dividend Increase

Rhea-AI Summary

Coterra Energy (CTRA) reported strong Q4 and full-year 2024 results, exceeding production guidance while maintaining lower capital expenditures. The company announced a 5% dividend increase to $0.22 per share for Q4 2024, with an annualized dividend of $0.88 per share yielding 3.1%.

Q4 2024 highlights include Net Income of $297 million ($0.40/share), total production of 682 MBoepd, and Free Cash Flow of $351 million. The company completed previously announced Permian acquisitions for approximately $3.2 billion in cash and 28.2 million shares.

2025 guidance projects capital expenditures of $2.1-2.4 billion, with total production expected to increase 9% year-over-year. The three-year outlook (2025-2027) forecasts annual average oil growth of 5% or greater, with BOE growth of 0-5%. The company maintains a strong financial position with total liquidity of approximately $5.0 billion at year-end 2024.

Positive

• Q4 production exceeded guidance by 3% while maintaining lower capital expenditures
• 5% dividend increase to $0.22 per share (3.1% yield)
• Strong Q4 Free Cash Flow of $351 million
• Projected 9% production growth for 2025
• Completion of strategic Permian acquisitions
• Strong liquidity position of $5.0 billion

Negative

• 2.1-2.4 billion capital expenditures for 2025, up 28% year-over-year
• 2% year-over-year decrease in proved reserves
• Lower realized natural gas prices in 2024 ($1.65/Mcf vs previous year)

HOUSTON--(BUSINESS WIRE)-- Coterra Energy Inc. (NYSE: CTRA) (“Coterra” or the “Company”) today reported fourth-quarter and full-year 2024 results, provided first-quarter and full-year 2025 guidance, and released a new three-year outlook for 2025 through 2027.

Key Takeaways & Updates

• For the fourth quarter of 2024, total barrels of oil equivalent (BOE), oil production and natural gas production beat the high-end of guidance by 3% or more and capital expenditures (non-GAAP) came in near the low-end of guidance. Relative to our full-year 2024 guidance, total BOE, oil production and natural gas production exceeded the high-end of guidance and capital expenditures (non-GAAP) came in near the low-end of guidance. Dividends and share repurchases totaled $218 million, or 61% of Free Cash Flow (non-GAAP), in the fourth quarter of 2024 and $1,086 million, or 89% of full-year 2024 Free Cash Flow (non-GAAP).

• 2025 capital expenditures are expected to be between $2.1 and $2.4 billion, in line with the 2025 pro forma framework announced with our acquisitions in November 2024. Relative to last November, Permian drilling and completion capital expenditures are estimated to be approximately $70 million lower, driven by improved services costs and acquisition synergies. Marcellus drilling and completion capital expenditures are estimated to be approximately $50 million higher than expected in November as we restart activity in the basin early in the second quarter. Anadarko capital expenditures are expected to be relatively consistent. At the mid-point of capital, and based on current commodity price outlook, the Company’s 2025 reinvestment rate (non-GAAP) is estimated to be slightly below 50%.

• Our 2025 production guidance is unchanged at the midpoint from the 2025 pro forma framework announced last November. 2025 total BOE production is expected to be up approximately 9% year-over-year at the mid-point, with oil volumes up approximately 47%, and natural gas volumes relatively flat to 2024 levels. Our 2025 guidance includes the impact of the recent acquisitions from the closings in late January. Organic 2025 annual oil and BOE growth for Coterra’s legacy assets, excluding the recently closed acquisitions, is estimated to be greater than 5% for oil and 0 to 5% for BOE.

• Updated three-year outlook (2025 through 2027) includes annual average oil growth of 5% or greater, annual average BOE growth of 0 to 5% and an average annual capital range of $2.1 to $2.4 billion, which includes legacy organic Coterra growth in 2025 and pro forma combined growth in 2026 and 2027. This outlook reflects an average reinvestment rate below 50% at the recent strip, pairing strong capital efficiency with consistent production growth.

• The Company is announcing a 5% dividend increase to $0.22 per share for the fourth quarter of 2024. The new annualized dividend of $0.88 per share equates to a 3.1% yield, based on the Company's $28.14 closing share price as of February 21, 2025.

• In late January 2025, the Company completed the previously announced Permian acquisitions for aggregate consideration of approximately $3.2 billion of cash and 28.2 million shares of Coterra common stock, subject to post-closing purchase price adjustments. These acquisitions, combined with previously owned leaseholds, create a new focus area in the Northern Delaware basin consisting of approximately 83,000 acres.

Tom Jorden, Chairman, CEO and President of Coterra, noted, “I am proud to report that Coterra continued its trend of excellent operational execution throughout 2024. Capital expenditures came in near the low end and production was above the high end of guidance, delivering improved capital efficiency. The team continues to engineer better solutions across our operating regions through decreased cycle times, increased productivity and lower costs. Additionally, I am pleased to report that we closed on our accretive Delaware Basin acquisitions on schedule, as well as finished bringing online our large 57 well Culberson row development. We enter 2025 with strong momentum in the Permian Basin and we exited the year at a three-year production high in the Marcellus. We are pleased to announce that we expect to restart our Marcellus development program in the coming months, which will provide incremental natural gas volumes next winter. We remain committed to value creation through operational excellence, disciplined capital allocation driven by full-cycle returns, and returning value to shareholders.”

Fourth-Quarter 2024 Highlights

• Net Income (GAAP) totaled $297 million, or $0.40 per share. Adjusted Net Income (non-GAAP) was $358 million, or $0.49 per share.

• Cash Flow From Operating Activities (GAAP) totaled $626 million. Discretionary Cash Flow (non-GAAP) totaled $776 million.

• Cash paid for capital expenditures for drilling, completion and other fixed asset additions (GAAP) totaled $425 million. Capital expenditures for drilling, completion and other fixed asset additions (non-GAAP) totaled $417 million, near the low end of our guidance range of $410 to $500 million.

• Free Cash Flow (non-GAAP) totaled $351 million.

• Unit operating cost (reflecting costs from direct operations, transportation, production taxes, and G&A) totaled $8.89 per BOE (barrel of oil equivalent), near the mid-point of our annual guidance range of $7.45 to $9.55 per BOE.

• Total equivalent production of 682 MBoepd (thousand barrels of oil equivalent per day), exceeded the high end of guidance (630 to 660 MBoepd), driven by improved cycle times and strong well performance.

• Oil production averaged 113.0 MBopd (thousand barrels of oil per day), exceeding the high end of guidance (106 to 110 MBopd).

• Natural gas production averaged 2,779 MMcfpd (million cubic feet per day), exceeding the high end of guidance (2,530 to 2,660 MMcfpd).

• Natural Gas Liquids (NGLs) production averaged 105.4 MBoepd.

• Realized average prices:

• Oil was $68.57 per barrel (Bbl), excluding the effect of commodity derivatives, and $68.70 per Bbl, including the effect of commodity derivatives.

• Natural Gas was $2.02 per Mcf (thousand cubic feet), excluding the effect of commodity derivatives, and $2.04 per Mcf, including the effect of commodity derivatives.

• NGLs were $20.94 per BOE.

2025 Outlook (including the impact of acquisitions from their closing dates in January)

• Estimate Discretionary Cash Flow (non-GAAP) of approximately $5.0 billion and Free Cash Flow (non-GAAP) of approximately $2.7 billion, at recent strip prices.

• Expect 2025 capital expenditures of $2.1 to $2.4 billion, up 28% year-over-year at the mid-point, driven by incremental spend associated with our recently completed Delaware Basin acquisitions. The 2025 reinvestment rate (non-GAAP) is slightly below 50%, at the recent strip. In 2025, the Company expects to average approximately 11 drilling rigs and 3 completion crews in the Permian Basin, 1 rig and 0.5 completion crews in the Marcellus, and 1.5 drilling rigs and 0.5 completion crews in the Anadarko Basin.

• Expect 2025 total equivalent production of 710 to 770 MBoepd, up approximately 9% year-over-year at the mid-point; oil production of 152 to 168 MBopd, up approximately 47% year-over-year at the mid-point; and natural gas production of 2,675 to 2,875 MMcfpd, relatively flat year-over-year at the mid-point.

• Expect 1Q25 total equivalent production of 710 to 750 MBoepd, oil production of 134 to 144 MBopd, natural gas production of 2,850 to 3,000 MMcfpd, and capital expenditures of $525 to $625 million.

Three Year Outlook: 2025 to 2027

• Reflecting legacy Coterra growth in 2025 and pro forma growth in 2026 and 2027, our new three-year outlook (2025 through 2027), includes annual average oil growth of 5% or greater, annual average BOE growth of 0 to 5%, which includes legacy organic Coterra growth in 2025 and pro forma combined growth in 2026 and 2027, and an average annual capital range of $2.1 to $2.4 billion. At the recent strip, this would imply an average reinvestment rate (non-GAAP) below 50% over the three-year period.

• The Company maintains significant flexibility to adjust its total capital investment level and allocation of capital across its three basins, supported by limited long-term service contracts and minimal lease obligations. The Company maintains flexibility and optionality in each of its three operating regions, allowing a flexible allocation of capital to its highest return projects.

• We expect this three year outlook to deliver significant Free Cash Flow (non-GAAP) to support our healthy base dividend, rapid debt reduction, and an impactful share repurchase program.

Fourth Quarter and Full-Year 2024 Shareholder Return Highlights

• Common Dividend: On February 24, 2025, Coterra's Board of Directors (the "Board") approved a quarterly base dividend of $0.22 per share, a 5% increase. The dividend will be paid on March 27, 2025 to holders of record on March 13, 2025.

• Share Repurchases: During the quarter, the Company repurchased 2.1 million shares for $50 million (excluding 1% excise tax) at a weighted-average price of $24.29 per share. During 2024, the Company repurchased 17.1 million shares for $451 million at a weighted-average price of $26.41 per share. $1.1 billion remains on the Company's $2.0 billion share repurchase authorization as of December 31, 2024.

• Total Shareholder Return: During the quarter, total shareholder returns amounted to $218 million, composed of $168 million of declared dividends and $50 million of share repurchases (excluding 1% excise tax). In 2024, total shareholder returns amounted to $1,086 million, composed of $635 million of declared dividends and $451 million of share repurchases (excluding 1% excise tax), representing 89% of 2024 Free Cash Flow (non-GAAP).

• Shareholder Return Strategy: Based on our current outlook, Coterra expects to return 50% or more of its annual Free Cash Flow (non-GAAP). In 2025, the Company intends to utilize a significant portion of its Free Cash Flow (non-GAAP) for its base dividend, the retirement of its term loans and share repurchases. Coterra also expects to continue to review increasing its base dividend on an annual cadence.

Full-Year 2024 Highlights

• Net Income (GAAP) totaled $1,121 million, or $1.51 per share. Adjusted Net Income (non-GAAP) was $1,245 million, or $1.68 per share.

• Cash Flow From Operating Activities (GAAP) totaled $2,795 million. Discretionary Cash Flow (non-GAAP) totaled $2,968 million.

• Cash paid for capital expenditures for drilling, completion and other fixed asset additions (GAAP) totaled $1,754 million. Capital expenditures for drilling, completion and other fixed asset additions (non-GAAP) totaled $1,762 million, at the low end of our original guidance range of $1.75 to $1.95 billion.

• Free Cash Flow (non-GAAP) totaled $1,214 million. Unit operating costs (reflecting costs from direct operations, transportation, production taxes, and G&A) totaled $8.66 per BOE, within our annual guidance range of $7.45 to $9.55 per BOE.

• Total equivalent production of 677 MBoepd, exceeded the high end of our original guidance (635 to 675 MBoepd), driven by improved cycle times and strong well performance.

• Oil production averaged 108.8 MBopd, exceeding the high end of original guidance (99 to 105 MBopd).

• Natural gas production averaged 2,800 MMcfpd, exceeding the high end of original guidance (2,650 to 2,800 MMcfpd).

• NGLs production averaged 101.1 MBoepd.

• Realized average prices:

• Oil: $74.18 per Bbl, excluding the effect of commodity derivatives, and $74.22 per Bbl, including the effect of commodity derivatives

• Natural Gas: $1.65 per Mcf, excluding the effect of commodity derivatives, and $1.75 per Mcf, including the effect of commodity derivatives

• NGLs: $19.95 per BOE

Strong Financial Position

The Company ended the year with a cash balance of $2.0 billion, two undrawn $500 million term loans totaling $1.0 billion, and no debt outstanding under its $2.0 billion revolving credit facility, resulting in total liquidity of approximately $5.0 billion. Coterra's net debt to trailing twelve-month EBITDAX ratio (non-GAAP) at December 31, 2024 was 0.4x.

In January 2025, we closed on our Delaware Basin acquisitions, which, after purchase price adjustments, included total cash consideration of approximately $3.2 billion and stock consideration to the sellers totaling 28.2 million Coterra common shares. Due to purchase price adjustments, which were calculated based on Coterra's share price at the time the acquisitions were announced, of $24.24 per share, 28.2 million shares were issued, down from 40.9 million shares anticipated to be issued at announcement of the transactions. Based on our current outlook, Coterra expects to retire its term loans totaling $1.0 billion in 2025 and expects to maintain a Net Debt to Adjusted EBITDAX leverage ratio (non-GAAP) below 1.0x, through commodity price cycles.

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.

2024 Proved Reserves

At December 31, 2024, Coterra's proved reserves totaled 2,271 million barrels of oil equivalent (MMBoe), down approximately 2% year-over-year. This was primarily driven by lower trailing 12 months natural gas prices and the decision to book fewer proved undeveloped reserves. At year-end 2024 proved undeveloped reserves were 18% of total proved reserves, down from 21% at year-end 2023. The proved undeveloped percentage reduction allows management to maintain future budgeting flexibility and the ability to allocate future capital to its most productive use between its business units.

Proved developed producing reserves were up 1% year over year.

SEC realized commodity prices used to calculate our proved reserves in 2024 for oil, natural gas liquids and natural gas, adjusted for basis and quality differentials, are $72.84 per Bbl, $18.16 per Bbl and $1.23 per Mcf, respectively, down from 2023 prices of $75.05 per Bbl, $18.39 per Bbl and $2.04 per Mcf.

The Company had net positive revisions of prior estimates of 9 MMBoe. This revision included a 59 MMBoe negative revision due to price, offset by a positive 64 MMBoe performance revision and a 4 MMBoe positive revision for improved operating expenses.

For a summary of Coterra's estimated proved reserves at December 31, 2024, see the "Year-End Proved Reserves" table below and in our annual report on Form 10-K for the fiscal year ended December 31, 2024.

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.

Conference Call

Coterra will host a conference call tomorrow, Tuesday, February 25, 2025, at 9:00 AM CT (10:00 AM ET), to discuss fourth-quarter and full-year 2024 financial and operating results and its 2025 outlook.

Conference Call Information

Date: Tuesday, February 25, 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: (646) 307-1963

Conference ID: 4460734

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 (including anticipated future dividend increases), enhanced shareholder value, reserves estimates, future financial and operating performance, and goals and commitment to sustainability and ESG leadership, strategic pursuits and goals, including with respect to the publication of Coterra’s Sustainability Report, and other statements that are not historical facts contained in this press release. The words "expect," "project," "estimate," "believe," "anticipate," "intend," "budget," "plan," "predict," "potential," "possible," "may," "should," "could," "would," "will," "strategy," "outlook", "guide" and similar expressions are also intended to identify forward-looking statements. We can provide no assurance that the forward-looking statements contained in this press release will occur as projected and actual results may differ materially from those projected. Forward-looking statements are based on current expectations, estimates and assumptions that involve a number of risks and uncertainties that could cause actual results to differ materially from those projected. These risks and uncertainties include, without limitation, the volatility in commodity prices for crude oil and natural gas; cost increases; the effect of future regulatory or legislative actions; the impact of public health crises, including pandemics (such as the coronavirus pandemic) and epidemics and any related governmental policies or actions on Coterra’s business, financial condition and results of operations; actions by, or disputes among or between, the Organization of Petroleum Exporting Countries and other producer countries; market factors; market prices (including geographic basis differentials) of oil and natural gas; impacts of inflation; labor shortages and economic disruption (including as a result of geopolitical disruptions such as the war in Ukraine or conflict in the Middle East); determination of reserves estimates, adjustments or revisions, including factors impacting such determination such as commodity prices, well performance, 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 (including successful integration of the Delaware Basin acquisitions into Coterra's operations); and other risks inherent in Coterra's businesses. In addition, the declaration and payment of any future dividends (or any increases thereto), whether regular base quarterly dividends, variable dividends or special dividends, as well as any share repurchases or pay downs of existing debt, 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 December 31,						Twelve Months Ended December 31,
		2024			2023			2024			2023
PRODUCTION VOLUMES
Marcellus Shale
Natural gas (Mmcf/day)			2,042.8			2,304.9			2,098.5			2,262.7
Daily equivalent production (MBoepd)			340.5			384.2			349.7			377.1
Permian Basin
Natural gas (Mmcf/day)			517.5			482.0			505.1			440.8
Oil (MBbl/day)			103.8			97.3			100.8			89.5
NGL (MBbl/day)			78.3			76.9			77.3			70.5
Daily equivalent production (MBoepd)			268.3			254.5			262.2			233.4
Anadarko Basin
Natural gas (Mmcf/day)			217.2			179.4			194.3			178.9
Oil (MBbl/day)			9.1			6.7			7.9			6.5
NGL (MBbl/day)			27.1			20.7			23.7			19.7
Daily equivalent production (MBoepd)			72.4			57.3			64.0			56.0
Total Company
Natural gas (Mmcf/day)			2,778.9			2,970.0			2,799.8			2,884.2
Oil (MBbl/day)			113.0			104.7			108.8			96.2
NGL (MBbl/day)			105.4			97.8			101.1			90.2
Daily equivalent production (MBoepd)			681.5			697.4			676.5			667.1
AVERAGE SALES PRICE (excluding hedges)
Marcellus Shale
Natural gas ($/Mcf)		$	2.27		$	2.17		$	1.98		$	2.33
Permian Basin
Natural gas ($/Mcf)		$	0.79		$	1.19		$	0.16		$	1.28
Oil ($/Bbl)		$	68.55		$	77.26		$	74.18		$	75.98
NGL ($/Bbl)		$	20.00		$	17.65		$	19.13		$	18.44
Anadarko Basin
Natural gas ($/Mcf)		$	2.51		$	2.30		$	1.92		$	2.37
Oil ($/Bbl)		$	68.80		$	79.12		$	74.16		$	76.92
NGL ($/Bbl)		$	23.66		$	22.40		$	22.62		$	23.54
Total Company
Natural gas ($/Mcf)		$	2.02		$	2.03		$	1.65		$	2.18
Oil ($/Bbl)		$	68.57		$	77.10		$	74.18		$	75.97
NGL ($/Bbl)		$	20.94		$	18.66		$	19.95		$	19.56

		Quarter Ended December 31,						Twelve Months Ended December 31,
		2024			2023			2024			2023
AVERAGE SALES PRICE (including hedges)
Total Company
Natural gas ($/Mcf)		$	2.04		$	2.19		$	1.75		$	2.44
Oil ($/Bbl)		$	68.70		$	77.21		$	74.22		$	76.07
NGL ($/Bbl)		$	20.94		$	18.66		$	19.95		$	19.56

		Quarter Ended December 31,						Twelve Months Ended December 31,
		2024			2023			2024			2023
WELLS DRILLED(1)
Gross wells
Marcellus Shale			—			20			26			73
Permian Basin			56			44			230			159
Anadarko Basin			18			2			57			32
			74			66			313			264
Net wells
Marcellus Shale			—			16.2			25.0			69.2
Permian Basin			35.3			18.6			111.3			82.1
Anadarko Basin			3.2			1.8			23.1			18.1
			38.5			36.6			159.4			169.4
TURN IN LINES
Gross wells
Marcellus Shale			11			12			41			71
Permian Basin			36			61			195			183
Anadarko Basin			17			3			58			19
			64			76			294			273
Net wells
Marcellus Shale			11.0			12.0			41.0			71.0
Permian Basin			18.1			28.0			86.5			94.9
Anadarko Basin			5.6			—			25.5			7.1
			34.7			40.0			153.0			173.0
AVERAGE RIG COUNTS
Marcellus Shale			—			2.0			0.9			2.6
Permian Basin			8.7			7.0			8.2			6.5
Anadarko Basin			1.0			1.0			1.3			1.3
		Quarter Ended December 31,						Twelve Months Ended December 31,
		2024			2023			2024			2023
AVERAGE UNIT COSTS ($/Boe)(2)
Direct operations		$	2.83		$	2.51		$	2.66		$	2.31
Gathering, processing and transportation			3.82			3.83			3.94			4.00
Taxes other than income			1.22			1.12			1.09			1.16
General and administrative (excluding stock-based compensation and severance expense)			1.02			0.95			0.97			0.90
Unit Operating Cost		$	8.89		$	8.41		$	8.66		$	8.37
Depreciation, depletion and amortization			7.75			7.11			7.43			6.74
Exploration			0.09			0.08			0.10			0.08
Stock-based compensation			0.29			0.23			0.25			0.24
Severance expense			—			0.03			—			0.05
Interest expense			0.29			0.13			0.18			0.11
		$	17.31		$	16.00		$	16.62		$	15.60

_______________________________________________________________________________
(1)		Wells drilled represents wells drilled to total depth during the period. Wells completed includes wells completed during the period, regardless of when they were drilled.
(2)		Total unit costs may differ from the sum of the individual costs due to rounding.

Derivatives Information

As of December 31, 2024, the Company had the following outstanding financial commodity derivatives:

		2025
Oil		First Quarter				Second Quarter				Third Quarter				Fourth Quarter
WTI oil collars
Volume (MBbl)			5,040				5,096				4,232				4,232
Weighted average floor ($/Bbl)		$	61.79			$	61.79			$	61.63			$	61.63
Weighted average ceiling ($/Bbl)		$	79.36			$	79.36			$	78.64			$	78.64
WTI Midland oil basis swaps
Volume (MBbl)			6,300				6,370				5,520				5,520
Weighted average differential ($/Bbl)		$	1.07			$	1.07			$	1.02			$	1.02
WTI oil swaps
Volume (MBbl)			1,710				1,729				1,748				1,748
Weighted average price ($/Bbl)			69.18				69.18				69.18				69.18
		2026
Oil		First Quarter				Second Quarter				Third Quarter				Fourth Quarter
WTI oil collars
Volume (MBbl)			900				910				920				920
Weighted average floor ($/Bbl)		$	62.50			$	62.50			$	62.50			$	62.50
Weighted average ceiling ($/Bbl)		$	69.40			$	69.40			$	69.40			$	69.40
WTI 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
WTI oil swaps
Volume (MBbl)			900				910				920				920
Weighted average price ($/Bbl)		$	66.14			$	66.14			$	66.14			$	66.14
		2025
Natural Gas		First Quarter				Second Quarter				Third Quarter				Fourth Quarter
NYMEX Collars
Volume (MMBtu)			45,000,000				45,500,000				46,000,000				46,000,000
Weighted average floor ($/MMBtu)		$	2.85			$	2.85			$	2.85			$	2.85
Weighted average ceiling ($/MMBtu)		$	4.51			$	4.07			$	4.07			$	5.55
Transco Leidy gas basis swaps
Volume (MMBtu)			18,000,000				18,200,000				18,400,000				18,400,000
Weighted average price ($/MMBtu)		$	(0.70	)		$	(0.70	)		$	(0.70	)		$	(0.70	)
Transco Zone 6 Non-NY gas basis swaps
Volume (MMBtu)			9,000,000				9,100,000				9,200,000				9,200,000
Weighted average price ($/MMBtu)		$	(0.29	)		$	(0.29	)		$	(0.29	)		$	(0.29	)

		2026
Natural Gas		First Quarter
NYMEX Collars
Volume (MMBtu)			27,000,000
Weighted average floor ($/MMBtu)		$	2.75
Weighted average ceiling ($/MMBtu)		$	7.66
In January 2025, the Company entered into the following financial commodity derivatives:
		2025
Natural Gas		First Quarter			Second Quarter			Third Quarter			Fourth Quarter
NYMEX collars
Volume (MMBtu)			5,900,000			9,100,000			9,200,000			9,200,000
Weighted average floor ($/MMBtu)		$	3.00		$	3.00		$	3.00		$	3.00
Weighted average ceiling ($/MMBtu)		$	4.46		$	4.46		$	4.46		$	4.46
		2026
Natural Gas		First Quarter			Second Quarter			Third Quarter			Fourth Quarter
NYMEX collars
Volume (MMBtu)			22,500,000			22,750,000			23,000,000			23,000,000
Weighted average floor ($/MMBtu)		$	3.00		$	3.00		$	3.00		$	3.00
Weighted average ceiling ($/MMBtu)		$	5.79		$	5.79		$	5.79		$	5.79

Year-End Proved Reserves

The tables below provide a summary of changes in proved reserves for the year ended December 31, 2024.

		Oil (MBbl)			Natural Gas (Bcf)			NGL (MBbl)			Total (MBOE)
PROVED RESERVES
December 31, 2023		249,213			10,525			317,456			2,320,757
Revision of previous estimates		11,636			(181	)		27,686			9,039
Extensions and discoveries		48,956			516			53,628			188,516
Production		(39,808	)		(1,025	)		(36,993	)		(247,589	)
Sales of reserves		(2	)		(1	)		—			(2	)
December 31, 2024		269,995			9,834			361,777			2,270,721
PROVED DEVELOPED RESERVES
December 31, 2023		173,392			8,590			234,306			1,839,219
December 31, 2024		189,275			8,420			271,030			1,863,583

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)
		Quarter Ended December 31,								Twelve Months Ended December 31,
(In millions, except per share amounts)		2024				2023				2024				2023
OPERATING REVENUES
Oil		$	713			$	742			$	2,953			$	2,667
Natural gas			516				553				1,693				2,292
NGL			203				168				738				644
Gain (loss) on derivative instruments			(51	)			101				(3	)			230
Other			14				32				77				81
			1,395				1,596				5,458				5,914
OPERATING EXPENSES
Direct operations			177				161				658				562
Gathering, processing and transportation			239				246				976				975
Taxes other than income			77				72				271				283
Exploration			6				6				25				20
Depreciation, depletion and amortization			486				456				1,840				1,641
General and administrative (excluding stock-based compensation and severance expense)			65				61				240				220
Stock-based compensation(1)			19				15				62				59
Severance expense			—				2				—				12
			1,069				1,019				4,072				3,772
Gain (loss) on sale of assets			—				—				3				12
INCOME FROM OPERATIONS			326				577				1,389				2,154
Interest expense			29				23				106				73
Interest income			(11	)			(15	)			(62	)			(47	)
Income before income taxes			308				569				1,345				2,128
Income tax provision (benefit)
Current			96				97				369				428
Deferred			(85	)			56				(145	)			75
Total Income tax provision			11				153				224				503
NET INCOME		$	297			$	416			$	1,121			$	1,625
Earnings per share - Basic		$	0.40			$	0.55			$	1.51			$	2.14
Weighted-average common shares outstanding			736				751				742				756
_______________________________________________________________________________
(1) Includes the impact of our performance share awards and restricted stock.

CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)
(In millions)		December 31, 2024			December 31, 2023
ASSETS
Current assets		$	3,321		$	2,015
Properties and equipment, net (successful efforts method)			17,890			17,933
Other assets			414			467
		$	21,625		$	20,415
LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY
Current liabilities		$	1,136		$	1,085
Current portion of long-term debt			—			575
Long-term debt, net (excluding current maturities)			3,535			1,586
Deferred income taxes			3,274			3,413
Other long term liabilities			550			709
Cimarex redeemable preferred stock			8			8
Stockholders’ equity			13,122			13,039
		$	21,625		$	20,415

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)
		Quarter Ended December 31,								Twelve Months Ended December 31,
(In millions)		2024				2023				2024				2023
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	297			$	416			$	1,121			$	1,625
Depreciation, depletion and amortization			486				456				1,840				1,641
Deferred income tax expense			(85	)			55				(145	)			74
(Gain) loss on sale of assets			—				—				(3	)			(12	)
Exploratory dry hole cost			—				—				5				—
(Gain) loss on derivative instruments			51				(101	)			3				(230	)
Net cash received (paid) in settlement of derivative instruments			8				46				98				284
Stock-based compensation and other			18				14				61				57
Income charges not requiring cash			1				(5	)			(12	)			(18	)
Changes in assets and liabilities			(150	)			(121	)			(173	)			237
Net cash provided by operating activities			626				760				2,795				3,658
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for drilling, completion and other fixed asset additions			(425	)			(468	)			(1,754	)			(2,089	)
Capital expenditures for leasehold and property acquisitions			(11	)			(2	)			(17	)			(10	)
Proceeds from sale of assets			1				—				9				40
Proceeds from sale of short-term investments			—				—				250				—
Purchase of short-term investments			—				—				(250	)			—
Net cash used in investing activities			(435	)			(470	)			(1,762	)			(2,059	)
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings (repayments) of debt			1,491				—				1,415				—
Common stock repurchases			(54	)			(20	)			(455	)			(405	)
Dividends paid			(155	)			(151	)			(625	)			(890	)
Capitalized debt issuance costs			(33	)			(7	)			(33	)			(7	)
Other			(11	)			(3	)			(23	)			(15	)
Net cash provided by (used in) financing activities			1,238				(181	)			279				(1,317	)
Net increase (decrease) in cash, cash equivalents and restricted cash		$	1,429			$	109			$	1,312			$	282

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, including 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, merger-related expenses and tax effect on selected items. Adjusted Earnings per Share is defined as Adjusted Net Income divided by weighted-average common shares outstanding. Additionally, we believe these measures provide beneficial comparisons to similarly adjusted measurements of prior periods and use these measures for that purpose. Adjusted Net Income and Adjusted Earnings per Share are not measures of financial performance under GAAP and should not be considered as alternatives to net income and earnings per share, as defined by GAAP.

		Quarter Ended December 31,								Twelve Months Ended December 31,
(In millions, except per share amounts)		2024				2023				2024				2023
As reported - net income		$	297			$	416			$	1,121			$	1,625
Reversal of selected items:
(Gain) loss on sale of assets			—				—				(3	)			(12	)
(Gain) loss on derivative instruments(1)			59				(55	)			101				54
Stock-based compensation expense			19				15				62				59
Severance expense			—				2				—				12
Tax effect on selected items			(17	)			9				(36	)			(26	)
Adjusted net income		$	358			$	387			$	1,245			$	1,712
As reported - earnings per share		$	0.40			$	0.55			$	1.51			$	2.14
Per share impact of selected items			0.09				(0.03	)			0.17				0.12
Adjusted earnings per share		$	0.49			$	0.52			$	1.68			$	2.26
Weighted-average common shares outstanding			736				751				742				756

_______________________________________________________________________________
(1)		This amount represents the non-cash mark-to-market changes of our commodity derivative instruments recorded in Gain (loss) on derivative instruments in the Condensed Consolidated Statement of Operations.

Reconciliation of Discretionary Cash Flow and Free Cash Flow

Discretionary Cash Flow is defined as cash flow from operating activities excluding changes in assets and liabilities. Discretionary Cash Flow is widely accepted as a financial indicator of an oil and gas company’s ability to generate available cash to internally fund exploration and development activities, return capital to shareholders through dividends and share repurchases, and service debt and is used by our management for that purpose. Discretionary Cash Flow is presented based on our management’s belief that this non-GAAP measure is useful information to investors when comparing our cash flows with the cash flows of other companies that use the full cost method of accounting for oil and gas producing activities or have different financing and capital structures or tax rates. Discretionary Cash Flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities or net income, as defined by GAAP, or as a measure of liquidity.

Free Cash Flow is defined as Discretionary Cash Flow less cash paid for capital expenditures. Free Cash Flow is an indicator of a company’s ability to generate cash flow after spending the money required to maintain or expand its asset base, and is used by our management for that purpose. Free Cash Flow is presented based on our management’s belief that this non-GAAP measure is useful information to investors when comparing our cash flows with the cash flows of other companies. Free Cash Flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities or net income, as defined by GAAP, or as a measure of liquidity.

		Quarter Ended December 31,								Twelve Months Ended December 31,
(In millions)		2024				2023				2024				2023
Cash flow from operating activities		$	626			$	760			$	2,795			$	3,658
Changes in assets and liabilities			150				121				173				(237	)
Discretionary cash flow			776				881				2,968				3,421
Cash paid for capital expenditures for drilling, completion and other fixed asset additions			(425	)			(468	)			(1,754	)			(2,089	)
Free cash flow		$	351			$	413			$	1,214			$	1,332

Capital Expenditures

		Quarter Ended December 31,								Twelve Months Ended December 31,
(In millions)		2024				2023				2024			2023
Cash paid for capital expenditures for drilling, completion and other fixed asset additions		$	425			$	468			$	1,754		$	2,089
Change in accrued capital costs			(8	)			(11	)			3			15
Exploratory dry-hole cost			—				—				5			—
Capital expenditures		$	417			$	457			$	1,762		$	2,104

Reconciliation of Adjusted EBITDAX

Adjusted EBITDAX is defined as net income plus interest expense, other expense, 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, severance expense and merger-related expense. Adjusted EBITDAX is presented on our management’s belief that this non-GAAP measure is useful information to investors when evaluating our ability to internally fund exploration and development activities and to service or incur debt without regard to financial or capital structure. Our management uses Adjusted EBITDAX for that purpose. Adjusted EBITDAX is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities or net income, as defined by GAAP, or as a measure of liquidity.

		Quarter Ended December 31,								Twelve Months Ended December 31,
(In millions)		2024				2023				2024				2023
Net income		$	297			$	416			$	1,121			$	1,625
Plus (less):
Interest expense			29				23				106				73
Interest income			(11	)			(15	)			(62	)			(47	)
Income tax expense			11				153				224				503
Depreciation, depletion and amortization			486				456				1,840				1,641
Exploration			6				6				25				20
(Gain) loss on sale of assets			—				—				(3	)			(12	)
Non-cash (gain) loss on derivative instruments			59				(55	)			101				54
Stock-based compensation			19				15				62				59
Severance expense			—				2				—				12
Adjusted EBITDAX		$	896			$	1,001			$	3,414			$	3,928

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 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 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 to reduce debt in calculating the Net Debt to Adjusted Capitalization ratio.

(In millions)		December 31, 2024				December 31, 2023
Current portion of long-term debt		$	—			$	575
Long-term debt, net			3,535			$	1,586
Total debt		$	3,535			$	2,161
Stockholders’ equity			13,122				13,039
Total capitalization		$	16,657			$	15,200
Total debt		$	3,535			$	2,161
Less: Cash and cash equivalents			(2,038	)			(956	)
Net debt		$	1,497			$	1,205
Net debt		$	1,497			$	1,205
Stockholders’ equity			13,122				13,039
Total adjusted capitalization		$	14,619			$	14,244
Total debt to total capitalization ratio			21.2	%			14.2	%
Less: Impact of cash and cash equivalents			11.0	%			5.7	%
Net debt to adjusted capitalization ratio			10.2	%			8.5	%

Reconciliation of Net Debt to Adjusted EBITDAX

Total debt to net income is defined as total debt divided by net income. Net debt to Adjusted EBITDAX is defined as net debt divided by trailing twelve month Adjusted EBITDAX. Net debt to Adjusted EBITDAX is a non-GAAP measure which our management believes is useful to investors when assessing our credit position and leverage.

(In millions)		December 31, 2024			December 31, 2023
Total debt		$	3,535		$	2,161
Net income			1,121		$	1,625
Total debt to net income ratio		3.2 x			1.3 x
Net debt (as defined above)		$	1,497		$	1,205
Adjusted EBITDAX (Twelve months ended December 31)			3,414			3,928
Net debt to Adjusted EBITDAX		0.4 x			0.3 x

2025 Guidance

The tables below present full-year and first quarter 2025 guidance.

		Full Year Guidance
		2024 Guidance						2024 Actual		2025 Guidance
		Low		Mid		High				Low		Mid		High
Total Equivalent Production (MBoed)		660		668		675		677		710		740		770
Gas (Mmcf/day)		2,735		2,755		2,775		2,800		2,675		2,775		2,875
Oil (MBbl/day)		107		108		108		108.8		152		160		168
Net wells turned in line
Marcellus Shale				40				41		10		13		15
Permian Basin		80		85		90		87		150		158		165
Anadarko Basin		21		24		27		26		15		20		25
Incurred capital expenditures ($ in millions)
Total Company		$1,750		$1,800		$1,850		$1,762		$2,100		$2,250		$2,400
Drilling and completion
Marcellus Shale				$300 midpoint				$286				$250 midpoint
Permian Basin				$1,050 midpoint				$1,051				$1,570 midpoint
Anadarko Basin				$300 midpoint				$287				$230 midpoint
Midstream, saltwater disposal and infrastructure				$150 midpoint				$137				$200 midpoint

		First Quarter Guidance
		Fourth Quarter 2024 Guidance						Fourth Quarter 2024 Actual		First Quarter 2025 Guidance
		Low		Mid		High				Low		Mid		High
Total Equivalent Production (MBoed)		630		645		660		682		710		730		750
Gas (Mmcf/day)		2,530		2,595		2,660		2,779		2,850		2,925		3,000
Oil (MBbl/day)		106		108		110		113		134		139		144
Net wells turned in line
Marcellus Shale				11				11				0
Permian Basin		13		18		23		18.1		35		40		45
Anadarko Basin		1		4		7		5.6				0
Incurred capital expenditures ($ in millions)
Total Company		$410		$455		$500		$417		$525		$575		$625

 

View source version on businesswire.com: https://www.businesswire.com/news/home/20250224266260/en/

Investor Contact

Daniel Guffey - VP - Finance, IR, & Treasurer

281.589.4875

Hannah Stuckey - Investor Relations Manager

281.589.4983

Source: Coterra Energy Inc.

FAQ

What is CTRA's new quarterly dividend payment for Q4 2024?

Coterra Energy increased its quarterly dividend by 5% to $0.22 per share, payable on March 27, 2025, to shareholders of record on March 13, 2025.

How much did CTRA spend on share repurchases in 2024?

CTRA repurchased 17.1 million shares for $451 million at an average price of $26.41 per share during 2024.

What is CTRA's production guidance for 2025?

CTRA expects 2025 total production of 710-770 MBoepd, representing a 9% year-over-year increase, with oil production up approximately 47%.

How much did CTRA pay for its recent Permian acquisitions?

CTRA completed the Permian acquisitions for approximately $3.2 billion in cash and 28.2 million shares of common stock in January 2025.

What is CTRA's three-year growth outlook for 2025-2027?

CTRA projects annual average oil growth of 5% or greater and BOE growth of 0-5%, with annual capital spending of $2.1-2.4 billion.