HOUSTON, October 31, 2024 - Coterra Energy Inc. (NYSE: CTRA) (“Coterra” or the “Company”) today reported third-quarter 2024 financial and operating results and declared a quarterly dividend of $0.21 per share. Additionally, the Company provided fourth-quarter production and capital guidance and updated full-year 2024 guidance.

Tom Jorden, Chairman, CEO and President of Coterra, noted, "Coterra continues to exceed its 2024 plan and has strong momentum with significant optionality heading into 2025. Our teams continue to deliver strong and improving capital efficiency through operational execution, all of which is guided by our relentless focus on economic returns. The Company's strong positioning is underpinned by its advantaged balance sheet, operational aptitude, diversified commodity mix and its durable, high-quality inventory.

We are also pleased to announce our three new LNG agreements. The U.S. has an abundant, low-cost natural gas resource that can help support energy reliability and energy affordability around the world. America's role as a major energy exporter strengthens our nation's standing on the global stage. As part of Coterra’s ongoing strategy, these agreements further diversify our natural gas marketing portfolio with the addition of international LNG pricing exposure to European and Asian markets."

•For the third quarter of 2024, total barrels of oil equivalent (BOE) production, natural gas production, and oil production all beat the high-end of guidance, and capital expenditures (non-GAAP) came in below the low-end of guidance.

•Increasing full-year 2024 production guidance mid-point for BOE, natural gas, and oil. The full-year 2024 oil guidance mid-point now assumes 12% year over year growth and a 5% increase compared to the initial guidance mid-point provided in February. These upward revisions throughout the year have been driven by faster cycle times and strong well performance across our portfolio.

•Lowering full-year 2024 capital expenditure (non-GAAP) guidance by $50 million at the mid-point, to $1.75-1.85 billion, driven by lower midstream, saltwater disposal, and infrastructure capital as well as lower Marcellus activity.

•During the quarter, the Company signed three new LNG agreements to sell a total of 200 MMcfpd (million cubic feet per day) of natural gas, indexed to international price points. Sales will begin in 2027 and 2028 and will be sourced from the Permian Basin, Anadarko Basin, and Marcellus Shale.

•For the third quarter of 2024, shareholder returns totaled 96% of Free Cash Flow (non-GAAP), inclusive of our declared quarterly base dividend and $111 million of share repurchases during the quarter (cash basis, excluding 1% excise tax). The Company remains committed to returning 50% or greater of its annual Free Cash Flow (non-GAAP) to shareholders and has returned 100% year to date, in addition to the retirement of $75 million of debt, net of new issue proceeds.

•To date, 36 of the 57 Windham Row wells have come online.

◦Currently, 10 additional wells are expected to come online by the end of the year.

◦The final 11 wells are expected to come online in first-quarter 2025.

•Net Income (GAAP) totaled $252 million, or $0.34 per share. Adjusted Net Income (non-GAAP) was $233 million, or $0.32 per share.

•Cash Flow From Operating Activities (GAAP) totaled $755 million. Discretionary Cash Flow (non-GAAP) totaled $670 million. Free Cash Flow (non-GAAP) totaled $277 million.

•Cash paid for capital expenditures for drilling, completion and other fixed asset additions (GAAP) totaled $393 million. Capital expenditures from drilling, completion and other fixed asset additions (non-GAAP) totaled $418 million, below the low-end of our guidance range of $450 to $530 million.

•Unit operating cost (reflecting costs from direct operations, transportation, production taxes and G&A) totaled $8.73 per BOE, within our annual guidance range of $7.45 to $9.55 per BOE.

•Total equivalent production of 669 MBoepd (thousand barrels of oil equivalent per day), was 3% above the high-end of guidance (620 to 650 MBoepd), driven by timing and strong well performance in all three of our regions.

◦Oil production averaged 112.3 MBopd (thousand barrels of oil per day), slightly exceeding the high-end of guidance (107 to 111 MBopd) by 1%.

◦Natural gas production averaged 2,682 MMcfpd, exceeding the high end of guidance (2,500 to 2,630 MMcfpd) by 2%, driven primarily by Permian growth.

◦NGLs production averaged 109.7 MBopd.

•Realized average prices:

◦Oil was $74.04 per Bbl (barrel), excluding the effect of commodity derivatives, and $74.18 per Bbl, including the effect of commodity derivatives.

◦Natural Gas was $1.30 per Mcf (thousand cubic feet), excluding the effect of commodity derivatives, and $1.41 per Mcf, including the effect of commodity derivatives.

◦NGLs were $18.42 per Bbl.

•Common Dividend: On October 31, 2024, Coterra's Board of Directors (the "Board") approved a quarterly base dividend of $0.21 per share, equating to a 3.5% annualized yield, based on the Company's $24.13 closing share price on October 30, 2024. The dividend will be paid on November 27, 2024 to holders of record on November 14, 2024.

•Share Repurchases: During the quarter, the Company repurchased 4.3 million shares for $111 million at a weighted-average price of approximately $25.15 per share, leaving $1.2 billion remaining as of September 30, 2024 on its $2.0 billion share repurchase authorization. Year-to-date, the Company repurchased 15 million shares for $401 million.

•Shareholder Return: During the quarter, shareholder returns amounted to $265 million, comprised of $154 million of declared dividends and $111 million of share repurchases.

•Reiterate Shareholder Return Strategy: Coterra is committed to returning 50% or greater of annual Free Cash Flow (non-GAAP) to shareholders through its $0.84 per share annual dividend and share repurchases. Year to date, Coterra has returned 100% of Free Cash Flow (non-GAAP) to shareholders.

•Lowered 2024 capital expenditures (non-GAAP) to $1.75 to $1.85 billion, down from $1.75 to $1.95 billion.

•Increased 2024 oil production guidance to 107 to 108 MBopd, up 0.5 MBopd at the mid-point versus prior guidance.

•Increased 2024 natural gas production guidance to 2,735 to 2,775 MMcfpd, up 1% at the mid-point versus prior guidance.

•Increased 2024 BOE production guidance to 660 to 675 MBoepd, up 1% at the mid-point versus prior guidance.

•Announced fourth-quarter 2024 total equivalent production of 630 to 660 MBoepd, oil production of 106 to 110 MBopd, natural gas production of 2,530 to 2,660 MMcfpd, and capital expenditures (non-GAAP) of $410 to $500 million.

•Estimate 2024 Discretionary Cash Flow (non-GAAP) of approximately $2.9 billion and 2024 Free Cash Flow (non-GAAP) of approximately $1.1 billion, at $75.58/bbl WTI and $2.22/mmbtu (metric million British thermal unit) annual average NYMEX assumptions.

•For more details on annual and fourth quarter 2024 guidance, see 2024 Guidance Section in the tables below.

As of September 30, 2024, Coterra had total debt outstanding of $2.066 billion. During the quarter, Coterra repaid $575 million of its 3.65% weighted-average private placement senior notes that matured in September 2024. During the quarter, the Company expanded its credit facility to $2.0 billion, up from $1.5 billion. The Company exited the quarter with cash and cash equivalents of $843 million, and no debt outstanding under its $2.0 billion revolving credit facility, resulting in total liquidity of approximately $2.843 billion. Coterra's net debt to trailing twelve-month EBITDAX ratio (non-GAAP) at September 30, 2024 was 0.3x.

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.

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.

Coterra will host a conference call tomorrow, Friday, November 1, 2024, at 8:00 AM CT (9:00 AM ET), to discuss third-quarter 2024 financial and operating results.

Conference Call Information

Date: November 1, 2024

Time: 8:00 AM CT / 9:00 AM ET

Dial-in (for callers in the U.S. and Canada): (800) 715-9871

International dial-in: +1 (646) 307-1963

Conference ID: 7309925

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.

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.

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; 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, 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.

The tables below provide a summary of production volumes, price realizations and operational activity by region and units costs for the Company for the periods indicated:

			Quarter Ended  September 30,												Nine Months Ended  September 30,
			2024						2023						2024						2023
PRODUCTION VOLUMES
Marcellus Shale
Natural gas (Mmcf/day)			1,928.5						2,286.4						2,117.2						2,248.5
Daily equivalent production (MBoepd)			321.4						381.1						352.9						374.7
Permian Basin
Natural gas (Mmcf/day)			531.2						446.4						500.9						426.9
Oil (MBbl/day)			102.7						86.6						99.8						86.9
NGL (MBbl/day)			82.7						75.4						77.0						68.3
Daily equivalent production (MBoepd)			273.9						236.3						260.2						226.3
Anadarko Basin
Natural gas (Mmcf/day)			218.8						168.3						186.6						178.8
Oil (MBbl/day)			9.5						5.2						7.5						6.4
NGL (MBbl/day)			26.9						19.1						22.6						19.3
Daily equivalent production (MBoepd)			72.9						52.3						61.1						55.5
Total Company
Natural gas (Mmcf/day)			2,682.0						2,903.2						2,806.8						2,855.3
Oil (MBbl/day)			112.3						91.9						107.4						93.3
NGL (MBbl/day)			109.7						94.5						99.6						87.7
Daily equivalent production (MBoepd)			669.1						670.3						674.8						656.9
AVERAGE SALES PRICE (excluding hedges)
Marcellus Shale
Natural gas ($/Mcf)			$	1.78					$	1.80					$	1.89					$	2.39
Permian Basin
Natural gas ($/Mcf)			$	(0.63)					$	1.58					$	(0.06)					$	1.31
Oil ($/Bbl)			$	73.96					$	80.84					$	76.14					$	75.50
NGL ($/Bbl)			$	17.30					$	18.56					$	18.83					$	18.75
Anadarko Basin
Natural gas ($/Mcf)			$	1.66					$	2.37					$	1.68					$	2.39
Oil ($/Bbl)			$	74.83					$	80.35					$	76.34					$	76.15
NGL ($/Bbl)			$	21.90					$	23.30					$	22.20					$	23.95
Total Company
Natural gas ($/Mcf)			$	1.30					$	1.80					$	1.53					$	2.23
Oil ($/Bbl)			$	74.04					$	80.80					$	76.16					$	75.54
NGL ($/Bbl)			$	18.42					$	19.52					$	19.59					$	19.90

			Quarter Ended  September 30,												Nine Months Ended  September 30,
			2024						2023						2024						2023
WELLS DRILLED(1)
Gross wells
Marcellus Shale			4						17						26						53
Permian Basin			63						43						174						115
Anadarko Basin			20						13						39						30
			87						73						239						198
Net wells
Marcellus Shale			4.0						17.0						25.0						53.0
Permian Basin			25.9						25.6						75.9						63.5
Anadarko Basin			6.3						7.9						20.0						16.3
			36.2						50.5						120.9						132.8
TURN IN LINES
Gross wells
Marcellus Shale			7						14						30						59
Permian Basin			61						43						159						122
Anadarko Basin			10						9						41						16
			78						66						230						197
Net wells
Marcellus Shale			7.0						14.0						30.0						59.0
Permian Basin			23.9						24.7						68.4						66.9
Anadarko Basin			4.6						7.0						19.9						7.1
			35.5						45.7						118.3						133.0
AVERAGE RIG COUNTS
Marcellus Shale			0.6						2.3						1.3						2.8
Permian Basin			8.0						7.0						8.0						6.3
Anadarko Basin			1.0						1.0						1.4						1.3

_______________________________________________________________________________

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

_______________________________________________________________________________

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

As of September 30, 2024, the Company had the following outstanding financial commodity derivatives:

In October 2024, the Company entered into the following financial commodity derivatives:

Capital expenditures is defined as cash paid for capital expenditures for drilling, completion and other fixed asset additions less changes in accrued capital costs.

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. 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.

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.

_______________________________________________________________________________

(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.

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.

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 severance 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.

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.

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.

The tables below present full-year and third quarter 2024 guidance.

						Full Year Guidance
						2024 Guidance (August)																		Updated 2024 Guidance
						Low						Mid						High						Low						Mid						High
Total Equivalent Production (MBoed)						645			—			660			—			675						660			—			668			—			675
Gas (Mmcf/day)						2,675			—			2,725			—			2,775						2,735			—			2,755			—			2,775
Oil (MBbl/day)						105.5			—			107			—			108.5						107			—			107.5			—			108
Net wells turned in line
Marcellus Shale						37			—			40			—			43						40
Permian Basin						80			—			85			—			90						No change
Anadarko Basin						21			—			24			—			27						No change
Capital expenditures ($ in millions)
Total Company						$1,750			—			$1,850			—			$1,950						$1,750			—			$1,800			—			$1,850
Drilling and completion
Marcellus Shale						$375 midpoint																		$300 midpoint
Permian Basin						$1,000 midpoint																		$1,050 midpoint
Anadarko Basin						$290 midpoint																		$300 midpoint
Midstream, saltwater disposal and infrastructure						$185 midpoint																		$150 midpoint
Commodity price assumptions:
WTI ($ per bbl)												$80																		$76
Henry Hub ($ per mmbtu)												$2.37																		$2.22
Cash Flow & Investment ($ in billions)
Discretionary Cash Flow												$3.2																		$2.9
Capital Expenditures						$1.75			—			$1.85			—			$1.95						$1.75			—			$1.80			—			$1.85
Free Cash Flow (DCF - cash capex)												$1.3																		$1.1
$ per boe, unless noted:
Lease operating expense + workovers + region office						$2.15			—			$2.50			—			$2.85						No change
Gathering, processing, & transportation						$3.50			—			$4.00			—			$4.50						No change
Taxes other than income						$1.00			—			$1.10			—			$1.20						No change
General & administrative (1)						$0.80			—			$0.90			—			$1.00						No change
Unit Operating Cost						$7.45			—			$8.50			—			$9.55						No change

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(1)Excludes stock-based compensation and severance expense

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