HOUSTON, May 4, 2023 - Coterra Energy Inc. (NYSE: CTRA) (“Coterra” or the “Company”) today reported first-quarter 2023 financial and operating results. Thomas E. Jorden, Chairman, Chief Executive Officer and President, commented, “Coterra delivered strong first quarter results, driven by solid execution, and is well positioned to meet or exceed 2023 guidance. Our operating teams continue to generate competitive returns across each of our three regions. Coterra’s portfolio, with its equal weighting to both liquids and natural gas, provides numerous benefits to our Company and shareholders by delivering a more consistent cash flow profile through commodity price cycles. As we look ahead, Coterra will remain disciplined and focused on value creation through consistent, profitable growth.”

•Net Income (GAAP) totaled $677 million, or $0.88 per share. Adjusted Net Income (non-GAAP) was $661 million, or $0.87 per share.

•Cash Flow From Operating Activities (GAAP) totaled $1,494 million. Discretionary Cash Flow (non-GAAP) totaled $1,039 million.

•Cash capital expenditures for drilling, completion and other fixed asset additions (GAAP) totaled $483 million. Accrued capital expenditures totaled $569 million, in line with our 1H23-weighted capital program.

•Free Cash Flow (non-GAAP) equaled $556 million.

•Total equivalent production of 635 MBoepd (thousand barrels of oil equivalent per day), exceeded the high-end of guidance, driven by strong well performance and improved cycle times. Oil production averaged 92.2 MBopd (thousand barrels of oil per day), exceeding the high-end of guidance. Natural gas production averaged 2,757 MMcfpd (million cubic feet per day), exceeding the high-end of guidance.

•Realized average prices:

◦Oil: $74.03 per barrel (Bbl), excluding the effect of commodity derivatives, and $74.09 per Bbl of oil, including the effect of commodity derivatives

◦Natural Gas: $3.31 per thousand cubic feet (Mcf), excluding the effect of commodity derivatives, and $3.72 per Mcf of natural gas, including the effect of commodity derivatives

◦Natural Gas Liquids (NGLs): $23.66 per barrel of natural gas liquids Jorden noted, “Based on first quarter results, Coterra will return $420 million to shareholders, which equals 76% of the company’s Free Cash Flow.

The return will include $152 million from our recently increased base dividend ($0.20 per quarter, $0.80 annum) and $268 million via share buybacks. We reiterate our commitment to return 50%+ of Free Cash Flow to shareholders, with an emphasis on the base dividend and buybacks, in the near-term.”

•On May 3, 2023, Coterra's Board of Directors (the "Board") approved a quarterly base dividend of $0.20 per share, which will be paid on June 9, 2023 to holders of record on May 26, 2023.

•During the quarter, the Company repurchased 11 million shares for $268 million, averaging $24.36 per share and leaving $1,732 million remaining on the $2.0 billion share repurchase authorization as of March 31, 2023.

2023 cash flow guidance updates include:

•Estimate full-year 2023 Discretionary Cash Flow of approximately $3.6 billion, at recent strip prices

•2023 capital budget remains unchanged at $2.0-2.2 billion (accrued); see potential for 2H23 deflation

•Estimate 2023 Free Cash Flow of approximately $1.6 billion at recent strip prices

•2023 oil production range increasing by 1.0 MBopd, to 87.0-93.0 MBopd

2023 cash unit cost mid-point remains unchanged at $7.35-$9.55/Boe, with a few updates listed below:

•LOE updated to $1.75-$2.25/Boe, with the high-end of the range up by $0.25/Boe, driven primarily by a reclassification of expenses from G&A to LOE

•Production tax expense updated to $1.20-$1.50/Boe, with both ends of the range shifting downward by $0.10/Boe

•Exploration expense updated to $0.05-$0.15/Boe, with the low-end of the range down by $0.05/Boe

Second-quarter 2023 production and capital guidance:

•Production volumes are expected to average between 620 and 650 MBoepd, with oil estimated between 88.5 and 91.5 MBopd and natural gas volumes estimated between 2,750 and 2,850 MMcfpd.

•Expect capital expenditures (accrued) during 2Q23 between $510 – $570 million.

Coterra is currently running six rigs and two completion crews in the Permian Basin, two rigs in the Anadarko Basin, and three rigs and two completion crew in the Marcellus. The Company plans to drop to 2 rigs and 1 crew in the Marcellus during 2Q23, as expected in our original plan.

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 maintains a strong financial position with an investment-grade credit rating and approximately $2.5 billion of liquidity. As of March 31, 2023, Coterra had total long-term debt of $2.2 billion with a principal amount of $2.1 billion. The Company exited the quarter with a cash balance of $973 million, no debt outstanding under its new $1.5 billion five-year revolving credit facility, and no near-term debt maturities. Coterra's net debt to Adjusted EBITDAX ratio (non-GAAP) at March 31, 2023 was 0.2x.

Coterra is committed to environmental stewardship, sustainable practices, and strong corporate governance. The Company's sustainability report can be found under "A Sustainable Future" on www.coterra.com. Coterra plans to publish its 2023 Sustainability Report in the fourth-quarter of 2023.

Coterra will host a conference call tomorrow, Friday, May 5, 2023, at 9:00 AM CT (10:00 AM ET), to discuss first-quarter 2023 financial and operating results.

Date: May 5, 2023

Time: 10:00 AM ET / 9:00 AM CT

Dial-in (for callers in the U.S. and Canada): (888) 550-5424

International dial-in: (646) 960-0819

Conference ID: 3813676

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 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.

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, including with respect to the publication of Coterra's first 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" 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 risk that the combined businesses will not be integrated successfully; the risk that the cost savings and any other synergies from the Merger may not be fully realized or may take longer to realize than expected; the volatility in commodity prices for crude oil and natural gas; cost increases; supply chain disruptions; the effect of future regulatory or legislative actions, including the risk of new restrictions with respect to well spacing, hydraulic fracturing, natural gas flaring, seismicity, produced water disposal, or other oil and natural gas development activities; disruption from the Merger making it more difficult to maintain relationships with customers, employees or suppliers; the diversion of management time on integration-related issues; the potential effects of further developments to the long-term impact of the COVID-19 pandemic and variants thereof 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 the pandemic or geopolitical disruptions such as the war in Ukraine); 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; 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 report 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:

									Three Months Ended  March 31,
															2023						2022
WELLS DRILLED(1)
Gross wells
Marcellus Shale															20						22
Permian Basin															39						29
Anadarko Basin															6						3
															65						54
Net wells
Marcellus Shale															20.0						22.0
Permian Basin															16.6						18.0
Anadarko Basin															3.3						1.4
															39.9						41.4
TURN IN LINES
Gross wells
Marcellus Shale															25						12
Permian Basin															45						31
Anadarko Basin															4						7
															74						50
Net wells
Marcellus Shale															25.0						9.1
Permian Basin															23.1						15.9
Anadarko Basin															0.1						—
															48.2						25.0
									Three Months Ended  March 31,
															2023						2022
AVERAGE UNIT COSTS ($/Boe)(2)
Direct operations															$	2.34					$	1.76
Transportation, processing and gathering															4.13						4.11
Taxes other than income															1.50						1.34
Exploration															0.07						0.11
Depreciation, depletion and amortization															6.45						6.35
General and administrative (excluding stock-based compensation and merger-related expense)															0.93						1.06
Stock-based compensation															0.28						0.41
Merger-related expense															—						0.12
Interest expense															0.09						0.37
Severance expense															0.12						0.42
															$	15.91					$	16.05

_______________________________________________________________________________

(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.

As of March 31, 2023, the Company had the following outstanding financial commodity derivatives:

						2023
Natural Gas						Second Quarter						Third Quarter						Fourth Quarter
Waha gas collars
Volume (MMBtu)						8,190,000						8,280,000						8,280,000
Weighted average floor ($/MMBtu)						$	3.03					$	3.03					$	3.03
Weighted average ceiling ($/MMBtu)						$	5.39					$	5.39					$	5.39
NYMEX collars
Volume (MMBtu)						31,850,000						32,200,000						29,150,000
Weighted average floor ($/MMBtu)						$	4.07					$	4.07					$	4.03
Weighted average ceiling ($/MMBtu)						$	6.78					$	6.78					$	6.61

In April 2023, the Company entered into the following financial commodity derivatives:

_______________________________________________________________________________

(1)Includes the impact of our performance share awards and restricted stock.

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 future impairments and future changes in capital. 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.

Present Value of Investment (PVI10) is often used by management as a return-on-investment metric and defined as the estimated net present value (using a 10% discount rate) of the future net cash flows from such reserves (for which we utilize certain assumptions regarding future commodity prices and operating costs), adding back our direct net costs incurred in drilling and adding back our completing, constructing facilities, and flowing back such wells, and then dividing that sum by our direct net costs incurred in drilling, completing, constructing facilities, and flowing back such wells.

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.

									Three Months Ended  March 31,
(In millions, except per share amounts)															2023						2022
As reported - net income															$	677					$	608
Reversal of selected items:
Gain on sale of assets															(5)						(2)
(Gain) loss on derivative instruments(1)															(38)						220
Stock-based compensation expense															16						23
Merger-related expense															—						7
Severance expense															7						24
Tax effect on selected items															4						(62)
Adjusted net income															$	661					$	818
As reported - earnings per share															$	0.88					$	0.75
Per share impact of selected items															(0.01)						0.26
Adjusted earnings per share															$	0.87					$	1.01
Weighted-average common shares outstanding															764						810

_______________________________________________________________________________

(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, 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.

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.

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.

281.589.4875

281.589.4983