Latest news with #Jorden
CNBC
21 hours ago
- Business
- CNBC
Coterra shifts its view on oil, again. Here are our 3 takeaways as investors in the stock
Coterra Energy is refocusing on oil. CEO Thomas Jorden shared the company's decision not to reduce its oil rig count at the JPMorgan Energy conference earlier this week. Here are several key takeaways for investors. 1. For starters, the move signals that Coterra has regained confidence in the direction of oil markets — and inherent in that is more confidence in the outlook for the economy. Alongside its first-quarter earnings report in early May, Coterra said it planned to shift some capital expenditures from its oil assets into natural gas production amid concerns about a potential tariff-driven recession that would dent demand for oil, leading to lower prices. As part of the shift, the company said it planned to reduce its oil rig count in the Permian Basin to seven. They're now walking back that change. "We're holding firm right now at nine [oil rigs] and we have very few under contract, so we have the flexibility," Jorden said at the conference Tuesday. "We were looking at the possibility of a collapse," he added, explaining the company's view last month. "We're feeling a little better about that now." @CL.1 3M mountain WTI three month performance When Coterra reported its Q1 on May 5, U.S. oil benchmark West Texas Intermediate crude had fallen around 20% since President Donald Trump announced his "reciprocal" tariffs in early April. Oil cartel OPEC was also signaling that it would increase production. As Trump walked back his most aggressive trade policies, the outlook for the economy improved, which was supportive for oil prices. Then, in mid-June, the start of the Iran-Israel conflict caused a temporary oil price spike as traders worried about supply disruptions. Prices have given back those gains as tensions eased. WTI has dropped more than 11% this week alone as the market deemed Iran-Israel conflict, and last weekend's U.S. bombing of three Iranian nuclear sites, not systemically concerning for now. With few rigs under contract, Coterra can scale back if circumstances change yet again. But for now, we were encouraged to hear Coterra isn't worried about a price collapse driven by a recession. 2. In reacting to the first-quarter earnings, Mizuho analysts flagged concerns that Coterra's lower oil activity spending could have negative implications down the road, particularly as it relates to the company's three-year goal of oil production growth of at least 5% annually on average. "We believe the impact will be felt in 2026-27 given the loss in momentum," the analysts wrote in a note to clients. Those worries might be alleviated as maintaining nine rigs could help Coterra hit its three-year goal, which the company outlined in February . The increased rig count, however, does put Coterra's capital expenditure spending at the higher end of its 2025 guidance, which falls between $2 billion and $2.3 billion. Keep in mind, though, investors may not fret capex coming in at the high end of the range if it's the result of more rigs staying in operation with drilling being done efficiently. It would be concerning if drilling activity fell off, but capex went higher. 3. At the same time, Coterra's decision to keep its oil rig count steady for now is not impacting the company's plans to increase activity in the natural gas-focused Marcellus Shale. "We are proceeding," Jorden said at the conference. "Gas prices look very constructive and we really do see the Marcellus as a really meaningful part of our program go forward." @NG.1 3M mountain Natural Gas three month peformance Coterra stands to win big on natural gas if the Constitution Pipeline project, which starts in the Marcellus, were to get revived. Coterra also has active nat gas assets in the Anadarko Basin and started drilling again in the Dimock Township of Pennsylvania following a 12-year-long ban that was lifted in December 2023. The company plans to drill 11 wells this year and expects to have around 17 total in the years to come. (Jim Cramer's Charitable Trust is long CTRA. See here for a full list of the stocks.) As a subscriber to the CNBC Investing Club with Jim Cramer, you will receive a trade alert before Jim makes a trade. Jim waits 45 minutes after sending a trade alert before buying or selling a stock in his charitable trust's portfolio. If Jim has talked about a stock on CNBC TV, he waits 72 hours after issuing the trade alert before executing the trade. THE ABOVE INVESTING CLUB INFORMATION IS SUBJECT TO OUR TERMS AND CONDITIONS AND PRIVACY POLICY , TOGETHER WITH OUR DISCLAIMER . NO FIDUCIARY OBLIGATION OR DUTY EXISTS, OR IS CREATED, BY VIRTUE OF YOUR RECEIPT OF ANY INFORMATION PROVIDED IN CONNECTION WITH THE INVESTING CLUB. NO SPECIFIC OUTCOME OR PROFIT IS GUARANTEED.
Business Wire
05-05-2025
- Business
- Business Wire
Coterra Energy Reports First-Quarter 2025 Results, Announces Quarterly Dividend, and Provides Guidance Update
HOUSTON--(BUSINESS WIRE)-- Coterra Energy Inc. (NYSE: CTRA) ('Coterra' or the 'Company') today reported first-quarter 2025 financial and operating results and declared a quarterly dividend of $0.22 per share. Additionally, the Company provided second-quarter production and capital guidance and updated full-year 2025 guidance. Tom Jorden, Chairman, CEO and President of Coterra, noted, "The company's top-tier balance sheet, diversified portfolio of high-quality oil and natural gas-focused assets and low reinvestment rate position Coterra to prosper throughout cyclical commodity price environments." "As our industry faces macroeconomic uncertainty and oil price headwinds, we believe it is prudent to reduce oil-directed activity at this time. As such, we are lowering Permian investment in 2025 and now expect to average seven Permian rigs during the second half of the year, down 30% from our original guidance of ten. As planned, we added two natural gas-focused rigs in the Marcellus in April and may keep this activity running for the balance of 2025. These decisions to reduce and reallocate capital bolster free cash flow in 2025, allow for a conservative investment ratio at lower commodity prices, and allow us to maintain our oil production guidance while slightly increasing our natural gas and BOE volumes for 2025. Additionally, these actions support free cash flow upside over the medium and long-term while generating attractive full-cycle returns in each of our operating regions in the current environment." Mr. Jorden continued, "Due to the short-term nature of our service contracts and limited marketing commitments, Coterra maintains significant flexibility to adjust our capital investment and maintains a series of activity off-ramps in 2025 that could further reduce activity and investment should fundamentals warrant. The Company remains committed to further reducing debt in 2025 to ensure we maintain one of the best balance sheets in our industry." Key Takeaways & Updates For the first quarter of 2025, total barrels of oil equivalent (BOE) production, natural gas production, and oil production were all above the midpoint of guidance, and capital expenditures (non-GAAP) were below the midpoint of guidance. Raising BOE and natural gas production guidance at the midpoint and maintaining full-year 2025 oil production midpoint guidance. Lowering 2025 capital budget range to $2.0 to $2.3 billion, driven by less oil-directed activity partially offset by higher natural gas-directed activity. The Company's reinvestment rate (non-GAAP), which is capital expenditures (non-GAAP) as a percentage of Discretionary Cash Flow, at recent strip prices, is expected to remain conservative at approximately 50% in 2025. Reducing 2025 Permian activity to seven rigs from our original plan of ten rigs during the second half of 2025 and reducing total Permian capital by approximately $150 million. Added two Marcellus rigs in April, as planned. We now expect to keep both rigs running into the second half of 2025, adding an incremental $50 million of capital to our 2025 Marcellus program. We also maintain an option to keep the second rig running through year-end, which could add an incremental $50 million of capital in the year. We expect to make this decision during the third quarter. Expected 2025 Free Cash Flow to total $2.1 billion, at recent strip prices, which we expect will be used to fund our dividend, reduce debt and execute share repurchases. First-quarter 2025 direct shareholder returns totaled approximately 30% of Free Cash Flow (non-GAAP), which included our declared dividend of $0.22, or approximately $168 million, and $24 million of share repurchases (cash basis, excluding 1% excise tax). Additionally, the Company repaid $250 million of term loans bringing total returns to 67% of Free Cash Flow (non-GAAP). In 2025, Coterra remains committed to reducing leverage and executing opportunistic share repurchases. First-Quarter 2025 Highlights Net Income (GAAP) totaled $516 million, or $0.68 per share. Adjusted Net Income (non-GAAP) was $608 million, or $0.80 per share. Cash Flow From Operating Activities (GAAP) totaled $1,144 million. Discretionary Cash Flow (non-GAAP) totaled $1,135 million. Free Cash Flow (non-GAAP) totaled $663 million. Cash paid for capital expenditures for drilling, completion and other fixed asset additions (GAAP) totaled $472 million. Incurred capital expenditures from drilling, completion and other fixed asset additions (non-GAAP) totaled $552 million, in the lower half of our guidance range of $525 to $625 million. Unit operating cost (reflecting costs from direct operations, transportation, production taxes and G&A) totaled $9.97 per Boe. Total equivalent production of 747 MBoepd (thousand barrels of oil equivalent per day), near the high-end of guidance (710 to 750 MBoepd). Oil production averaged 141.2 MBopd (thousand barrels of oil per day), approximately 2% above the midpoint of our guidance range (134 to 144 MBopd). Natural gas production averaged 3,044 MMcfpd (million cubic feet of gas per day), exceeding the high end of guidance (2,850 to 3,000 MMcfpd). NGLs production averaged 98.3 MBopd. Realized average prices: Oil was $69.73 per Bbl (barrel), excluding the effect of commodity derivatives, and $69.30 per Bbl, including the effect of commodity derivatives. Natural Gas was $3.28 per Mcf (thousand cubic feet), excluding the effect of commodity derivatives, and $3.21 per Mcf, including the effect of commodity derivatives. NGLs were $23.23 per Bbl. Closed the Franklin Mountain Energy and Avant Natural Resources acquisitions in late January. Shareholder Return Highlights Common Dividend: On May 5, 2025, Coterra's Board of Directors (the "Board") approved a quarterly dividend of $0.22 per share, equating to a 3.4% annualized yield, based on the Company's $25.67 closing share price on May 2, 2025. The dividend will be paid on May 29, 2025 to holders of record on May 15, 2025. Share Repurchases: During the quarter, the Company repurchased 0.9 million shares for $24 million at a weighted-average price of approximately $27.54 per share, leaving $1.1 billion remaining as of March 31, 2025 on its $2.0 billion share repurchase authorization. Shareholder Return: During the quarter, direct shareholder returns amounted to approximately $192 million, comprised of approximately $168 million of declared dividends and $24 million of share repurchases. The Company also repaid $250 million of debt during the quarter. Reiterate Shareholder Return Strategy: Coterra expects to return 50% or greater of annual Free Cash Flow (non-GAAP) to shareholders through the cycles via its base dividend and share repurchases. However, in 2025, after payment of its base dividend, the Company is prioritizing debt reduction as it looks to retire the outstanding $750 million term loans, which mature in 2027 and 2028. Guidance Updates Lowered 2025 capital expenditures range (non-GAAP) to $2.0 to $2.3 billion, down from $2.1 to $2.4 billion. After closing our recent acquisitions in January, we exited the first quarter with 13 rigs in the Permian. Our original plan called for ten rigs in the second half of 2025, but we now plan to operate seven rigs in the second half of the year. Announcing second-quarter 2025 total equivalent production of 710 to 760 MBoepd, oil production of 147 to 157 MBopd, natural gas production of 2,700 to 2,850 MMcfpd, and capital expenditures (non-GAAP) of $575 to $650 million. Estimate 2025 Discretionary Cash Flow (non-GAAP) of approximately $4.3 billion and 2025 Free Cash Flow (non-GAAP) of approximately $2.1 billion, at approximately $63 per bbl WTI and $3.70 per mmbtu (metric million British thermal unit) annual average NYMEX assumptions. For more details on annual and second quarter 2025 guidance, see 2025 Guidance Section in the tables below. Strong Financial Position In conjunction with the closing of the Franklin Mountain Energy and Avant Natural Resources acquisitions in late January, Coterra issued $1.0 billion of new debt through its term loan agreements. Subsequently, Coterra paid down $250 million of the term loans prior to the end of the first quarter, leaving $750 million of term loan debt outstanding. As of March 31, 2025, Coterra had total debt outstanding of $4.25 billion (principal balance). The Company exited the quarter with cash and cash equivalents of $186 million, and no debt outstanding under its $2.0 billion revolving credit facility, resulting in total liquidity of approximately $2.19 billion. Coterra's Net Debt to trailing twelve-month Adjusted Pro Forma EBITDAX ratio (non-GAAP) at March 31, 2025 was 0.9x, pro forma the Franklin and Avant acquisitions. The Company remains committed to near-term debt reduction. See 'Supplemental non-GAAP Financial Measures' below for descriptions of the above non-GAAP measures as well as reconciliations of these measures to the associated GAAP measures. Committed to Sustainability and ESG Leadership Coterra is committed to environmental stewardship, sustainable practices, and strong corporate governance. The Company's sustainability report can be found under "ESG" on Coterra published its 2024 Sustainability report on August 1, 2024. First-Quarter 2025 Conference Call Coterra will host a conference call tomorrow, Tuesday, May 6, 2025, at 9:00 AM CT (10:00 AM ET), to discuss first-quarter 2025 financial and operating results. Conference Call Information Date: May 6, 2025 Time: 9:00 AM CT / 10:00 AM ET Dial-in (for callers in the U.S. and Canada): (800) 715-9871 International dial-in: +1 (646) 307-1963 Conference ID: 4309719 The live audio webcast and related earnings presentation can be accessed on the "Events & Presentations" page under the "Investors" section of the Company's website at The webcast will be archived and available at the same location after the conclusion of the live event. About Coterra Energy Coterra is a premier exploration and production company based in Houston, Texas with operations focused in the Permian Basin, Marcellus Shale, and Anadarko Basin. We strive to be a leading energy producer, delivering sustainable returns through the efficient and responsible development of our diversified asset base. Learn more about us at Cautionary Statement Regarding Forward-Looking Information This press release contains certain forward-looking statements within the meaning of federal securities laws. Forward-looking statements are not statements of historical fact and reflect Coterra's current views about future events. Such forward-looking statements include, but are not limited to, statements about returns to shareholders, enhanced shareholder value, reserves estimates, future financial and operating performance, and goals and commitment to sustainability and ESG leadership, strategic pursuits and goals, and other statements that are not historical facts contained in this press release. The words "expect," "project," "estimate," "believe," "anticipate," "intend," "budget," "plan," "predict," "potential," "possible," "may," "should," "could," "would," "will," "strategy," "outlook", "guide" and similar expressions are also intended to identify forward-looking statements. We can provide no assurance that the forward-looking statements contained in this press release will occur as projected and actual results may differ materially from those projected. Forward-looking statements are based on current expectations, estimates and assumptions that involve a number of risks and uncertainties that could cause actual results to differ materially from those projected. These risks and uncertainties include, without limitation, the volatility in commodity prices for crude oil and natural gas; changes in U.S. and international economic policy (including tariffs and retaliatory tariffs and the impacts thereof); cost increases; the effect of future regulatory or legislative actions; actions by, or disputes among or between, the Organization of Petroleum Exporting Countries and other producer countries; market factors; market prices (including geographic basis differentials) of oil and natural gas; impacts of inflation; labor shortages and economic disruption, (geopolitical disruptions such as the war in Ukraine or conflict in the Middle East or further escalation thereof); determination of reserves estimates, adjustments or revisions, including factors impacting such determination such as commodity prices, well performance, results of future drilling and marketing activities (including seismicity and similar data), operating expenses and completion of Coterra's annual PUD reserves process, as well as the impact on our financial statements resulting therefrom; the presence or recoverability of estimated reserves; the ability to replace reserves; environmental risks; drilling and operating risks; exploration and development risks; competition; the ability of management to execute its plans to meet its goals; the impact of public health crises, including pandemics and epidemics and any related company or governmental policies or actions, financial condition and results of operations; and other risks inherent in Coterra's businesses. In addition, the declaration and payment of any future dividends, whether regular base quarterly dividends, variable dividends or special dividends, will depend on Coterra's financial results, cash requirements, future prospects and other factors deemed relevant by Coterra's Board. While the list of factors presented here is considered representative, no such list should be considered to be a complete statement of all potential risks and uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. For additional information about other factors that could cause actual results to differ materially from those described in the forward-looking statements, please refer to Coterra's annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other filings with the SEC, which are available on Coterra's website at 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. Three Months Ended March 31, 2025 2024 AVERAGE SALES PRICE (including hedges) Total Company Natural gas ($/Mcf) $ 3.21 $ 2.10 Oil ($/Bbl) $ 69.30 $ 75.00 NGL ($/Bbl) $ 23.23 $ 21.09 Expand Three Months Ended March 31, 2025 2024 WELLS DRILLED (1) Gross wells Marcellus Shale — 14 Permian Basin 67 48 Anadarko Basin 8 8 75 70 Net wells Marcellus Shale — 13.0 Permian Basin 45.1 23.2 Anadarko Basin 5.6 6.7 50.7 42.9 TURN IN LINES Gross wells Marcellus Shale 5 11 Permian Basin 61 42 Anadarko Basin 4 5 70 58 Net wells Marcellus Shale — 11.0 Permian Basin 37.1 21.9 Anadarko Basin 0.2 0.1 37.3 33.0 AVERAGE OPERATED RIG COUNTS Marcellus Shale — 2.0 Permian Basin 11.7 8.0 Anadarko Basin 1.8 2.0 Expand _______________________________________________________________________________ (1) Wells drilled represents wells drilled to total depth during the period. Expand _______________________________________________________________________________ (1) Total unit costs may differ from the sum of the individual costs due to rounding. Expand 2026 Oil First Quarter Second Quarter Third Quarter Fourth Quarter WTI oil collars Volume (MBbl) 900 910 920 920 Weighted average floor ($/Bbl) $ 62.50 $ 62.50 $ 62.50 $ 62.50 Weighted average ceiling ($/Bbl) $ 69.40 $ 69.40 $ 69.40 $ 69.40 WTI oil swaps Volume (MBbl) 900 910 920 920 Weighted average price ($/Bbl) $ 66.14 $ 66.14 $ 66.14 $ 66.14 WTI Midland oil basis swaps Volume (MBbl) 1,800 1,820 1,840 1,840 Weighted average differential ($/Bbl) $ 0.95 $ 0.95 $ 0.95 $ 0.95 Expand 2025 Natural Gas Second Quarter Third Quarter Fourth Quarter NYMEX gas collars Volume (MMBtu) 72,800,000 73,600,000 73,600,000 Weighted average floor ($/MMBtu) $ 3.01 $ 3.01 $ 3.01 Weighted average ceiling ($/MMBtu) $ 4.82 $ 4.82 $ 5.75 Transco Leidy gas basis swaps Volume (MMBtu) 18,200,000 18,400,000 18,400,000 Weighted average differential ($/MMBtu) $ (0.70 ) $ (0.70 ) $ (0.70 ) Transco Zone 6 Non-NY gas basis swaps Volume (MMBtu) 18,200,000 18,400,000 18,400,000 Weighted average differential ($/MMBtu) $ (0.49 ) $ (0.49 ) $ (0.49 ) Expand 2026 Natural Gas First Quarter Second Quarter Third Quarter Fourth Quarter NYMEX gas collars Volume (MMBtu) 67,500,000 40,950,000 41,400,000 41,400,000 Weighted average floor ($/MMBtu) $ 2.97 $ 3.11 $ 3.11 $ 3.11 Weighted average ceiling ($/MMBtu) $ 6.62 $ 5.93 $ 5.93 $ 5.93 Expand In April 2025, the Company entered into the following financial commodity derivatives: 2025 Natural Gas Second Quarter Third Quarter Fourth Quarter NYMEX gas collars Volume (MMBtu) 9,150,000 13,800,000 13,800,000 Weighted average floor ($/MMBtu) $ 3.50 $ 3.50 $ 3.50 Weighted average ceiling ($/MMBtu) $ 5.21 $ 5.21 $ 5.21 Waha gas basis swaps Volume (MMBtu) 9,150,000 13,800,000 13,800,000 Weighted average differential ($/MMBtu) $ (2.05 ) $ (2.05 ) $ (2.05 ) Expand 2026 Natural Gas First Quarter Second Quarter Third Quarter Fourth Quarter NYMEX gas collars Volume (MMBtu) 13,500,000 13,650,000 13,800,000 13,800,000 Weighted average floor ($/MMBtu) $ 3.50 $ 3.50 $ 3.50 $ 3.50 Weighted average ceiling ($/MMBtu) $ 5.24 $ 5.24 $ 5.24 $ 5.24 Waha gas basis swaps Volume (MMBtu) 13,500,000 13,650,000 13,800,000 13,800,000 Weighted average differential ($/MMBtu) $ (1.86 ) $ (1.86 ) $ (1.86 ) $ (1.86 ) Expand CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited) March 31, (In millions, except per share amounts) 2025 2024 OPERATING REVENUES Oil $ 886 $ 701 Natural gas 898 538 NGL 206 173 Loss on derivative instruments (112 ) — Other 26 21 1,904 1,433 OPERATING EXPENSES Direct operations 216 156 Gathering, processing and transportation 282 250 Taxes other than income 96 74 Exploration 10 5 Depreciation, depletion and amortization 506 432 General and administrative (excluding stock-based compensation) 76 62 Stock-based compensation 16 13 1,202 992 Loss on sale of assets — (1 ) INCOME FROM OPERATIONS 702 440 Interest expense 53 19 Interest income (8 ) (16 ) Income before income taxes 657 437 Income tax provision (benefit) Current 130 107 Deferred 11 (22 ) Total income tax provision 141 85 NET INCOME $ 516 $ 352 Earnings per share - Basic $ 0.68 $ 0.47 Weighted-average common shares outstanding 756 750 Expand CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited) (In millions) March 31, 2025 December 31, 2024 ASSETS Cash and cash equivalents $ 186 $ 2,038 Other current assets 1,260 1,283 Properties and equipment, net (successful efforts method) 22,081 17,890 Other assets 424 414 $ 23,951 $ 21,625 LIABILITIES, REDEEMABLE PREFERRED STOCK AND STOCKHOLDERS' EQUITY Current liabilities $ 1,608 $ 1,136 Long-term debt, net 4,280 3,535 Deferred income taxes 3,285 3,274 Other long term liabilities 546 550 Cimarex redeemable preferred stock 8 8 Stockholders' equity 14,224 13,122 $ 23,951 $ 21,625 Expand CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited) Three Months Ended March 31, (In millions) 2025 2024 CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 516 $ 352 Depreciation, depletion and amortization 506 432 Deferred income tax expense (benefit) 11 (22 ) Loss on sale of assets — 1 Loss on derivative instruments 112 — Net cash (paid) received in settlement of derivative instruments (22 ) 26 Stock-based compensation and other 15 12 Income charges not requiring cash (3 ) (4 ) Changes in assets and liabilities 9 59 Net cash provided by operating activities 1,144 856 CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures for drilling, completion and other fixed asset additions (472 ) (457 ) Capital expenditures for leasehold and property acquisitions (37 ) (1 ) Cash consideration paid for business combinations (3,219 ) — Purchases of short-term investments — (250 ) Net cash used in investing activities (3,728 ) (708 ) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from issuance of debt 1,000 499 Repayments of debt (250 ) — Common stock repurchases (24 ) (150 ) Dividends paid (178 ) (158 ) Tax withholding on vesting of stock awards (21 ) — Other 1 (6 ) Net cash provided by financing activities 528 185 Net increase (decrease) in cash, cash equivalents and restricted cash $ (2,056 ) $ 333 Expand Reconciliation of Capital Expenditures Capital expenditures is defined as cash paid for capital expenditures for drilling, completion and other fixed asset additions less changes in accrued capital costs. Three Months Ended March 31, (In millions) 2025 2024 Cash paid for capital expenditures for drilling, completion and other fixed asset additions (GAAP) $ 472 $ 457 Change in accrued capital costs 80 (7 ) Capital expenditures for drilling, completion and other fixed asset additions (non-GAAP) $ 552 $ 450 Expand Supplemental Non-GAAP Financial Measures (Unaudited) We report our financial results in accordance with accounting principles generally accepted in the United States (GAAP). However, we believe certain non-GAAP performance measures may provide financial statement users with additional meaningful comparisons between current results and results of prior periods. In addition, we believe these measures are used by analysts and others in the valuation, rating and investment recommendations of companies within the oil and natural gas exploration and production industry. See the reconciliations below that compare GAAP financial measures to non-GAAP financial measures for the periods indicated. We have also included herein certain forward-looking non-GAAP financial measures, including, among others, the reinvestment rate, which is defined as capital expenditures (non-GAAP) as a percentage of Discretionary Cash Flow (non-GAAP). We believe the reinvestment rate provides investors with useful information on management's projected use and reinvestment of its future cash flows back into Coterra's operations. Due to the forward-looking nature of these non-GAAP financial measures, we cannot reliably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as changes in assets and liabilities (including future impairments) and cash paid for certain capital expenditures. Accordingly, we are unable to present a quantitative reconciliation of such forward-looking non-GAAP financial measures to their most directly comparable forward-looking GAAP financial measures. Reconciling items in future periods could be significant. Adjusted Net Income and Adjusted Earnings per Share are presented based on our management's belief that these non-GAAP measures enable a user of financial information to understand the impact of identified adjustments on reported results. Adjusted Net Income is defined as net income plus gain and loss on sale of assets, non-cash gain and loss on derivative instruments, stock-based compensation expense, severance expense, and tax effect on selected items. Adjusted Earnings per Share is defined as Adjusted Net Income divided by weighted-average common shares outstanding. Additionally, we believe these measures provide beneficial comparisons to similarly adjusted measurements of prior periods and use these measures for that purpose. Adjusted Net Income and Adjusted Earnings per Share are not measures of financial performance under GAAP and should not be considered as alternatives to net income and earnings per share, as defined by GAAP. Three Months Ended March 31, (In millions, except per share amounts) 2025 2024 As reported - net income $ 516 $ 352 Reversal of selected items: Loss on sale of assets — 1 Loss on derivative instruments (1) 90 26 Stock-based compensation expense 16 13 Acquisition related expense 13 — Tax effect on selected items (27 ) (9 ) Adjusted net income $ 608 $ 383 As reported - earnings per share $ 0.68 $ 0.47 Per share impact of selected items 0.12 0.04 Adjusted earnings per share $ 0.80 $ 0.51 Weighted-average common shares outstanding 756 750 Expand _______________________________________________________________________________ (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 Expand Reconciliation of Discretionary Cash Flow and Free Cash Flow Discretionary Cash Flow is defined as cash flow from operating activities excluding changes in assets and liabilities. Discretionary Cash Flow is widely accepted as a financial indicator of an oil and gas company's ability to generate available cash to internally fund exploration and development activities, return capital to shareholders through dividends and share repurchases, and service debt and is used by our management for that purpose. Discretionary Cash Flow is presented based on our management's belief that this non-GAAP measure is useful information to investors when comparing our cash flows with the cash flows of other companies that use the full cost method of accounting for oil and gas producing activities or have different financing and capital structures or tax rates. Discretionary Cash Flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities or net income, as defined by GAAP, or as a measure of liquidity. Free Cash Flow is defined as Discretionary Cash Flow less cash paid for capital expenditures. Free Cash Flow is an indicator of a company's ability to generate cash flow after spending the money required to maintain or expand its asset base, and is used by our management for that purpose. Free Cash Flow is presented based on our management's belief that this non-GAAP measure is useful information to investors when comparing our cash flows with the cash flows of other companies. Free Cash Flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities or net income, as defined by GAAP, or as a measure of liquidity. Three Months Ended March 31, (In millions) 2025 2024 Cash flow from operating activities $ 1,144 $ 856 Changes in assets and liabilities (9 ) (59 ) Discretionary cash flow 1,135 797 Cash paid for capital expenditures for drilling, completion and other fixed asset additions (472 ) (457 ) Free Cash Flow $ 663 $ 340 Expand Reconciliation of Adjusted EBITDAX Adjusted EBITDAX is defined as net income plus interest expense, interest income, income tax expense, depreciation, depletion, and amortization (including impairments), exploration expense, gain and loss on sale of assets, non-cash gain and loss on derivative instruments, stock-based compensation expense, and acquisition-related expenses. Adjusted EBITDAX is presented on our management's belief that this non-GAAP measure is useful information to investors when evaluating our ability to internally fund exploration and development activities and to service or incur debt without regard to financial or capital structure. Our management uses Adjusted EBITDAX for that purpose. Adjusted EBITDAX is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities or net income, as defined by GAAP, or as a measure of liquidity. Three Months Ended March 31, (In millions) 2025 2024 Net income $ 516 $ 352 Plus (less): Interest expense 53 19 Interest income (8 ) (16 ) Income tax expense 141 85 Depreciation, depletion and amortization 506 432 Exploration 10 5 Loss on sale of assets — 1 Non-cash loss on derivative instruments 90 26 Acquisition-related expenses 13 — Stock-based compensation 16 13 Adjusted EBITDAX $ 1,337 $ 917 Expand Trailing Twelve Months Ended (In millions) March 31, 2025 December 31, 2024 Net income $ 1,285 $ 1,121 Plus (less): Interest expense 140 106 Interest income (54 ) (62 ) Income tax expense 280 224 Depreciation, depletion and amortization 1,914 1,840 Exploration 30 25 Gain on sale of assets (4 ) (3 ) Non-cash loss on derivative instruments 165 101 Acquisition-related expenses 13 — Stock-based compensation 65 62 Adjusted EBITDAX (trailing twelve months) $ 3,834 $ 3,414 Expand Reconciliation of Adjusted Pro Forma EBITDAX Adjusted Pro Forma EBITDAX is defined as pro forma net income plus pro forma interest expense, pro forma interest income, pro forma income tax expense, pro forma depreciation, depletion, and amortization (including impairments), pro forma exploration expense, pro forma gain and loss on sale of assets, pro forma non-cash gain and loss on derivative instruments, pro forma acquisition-related expenses, and pro forma stock-based compensation expense. Adjusted Pro Forma EBITDAX represents the effects of the Franklin Mountain Energy and Avant Natural Resources acquisitions as if they had occurred on January 1, 2024. Adjusted Pro Forma EBITDAX is presented on our management's belief that this non-GAAP measure is useful information to investors when evaluating our ability to internally fund exploration and development activities and to service or incur debt after the acquisitions without regard to financial or capital structure. Our management uses Adjusted Pro Forma EBITDAX for that purpose. Adjusted Pro Forma EBITDAX is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities, pro forma net income or net income, as defined by GAAP, or as a measure of liquidity. Trailing Twelve Months Ended (In millions) March 31, 2025 December 31, 2024 Pro forma net income $ 1,493 $ 1,401 Plus (less): Pro forma interest expense 251 250 Pro forma interest income (54 ) (62 ) Pro forma income tax expense 338 290 Pro forma depreciation, depletion and amortization 2,240 2,197 Pro forma exploration 30 25 Pro forma gain on sale of assets (4 ) (3 ) Pro forma non-cash loss on derivative instruments 291 101 Pro forma acquisition-related expenses 13 — Pro forma stock-based compensation 65 62 Adjusted Pro Forma EBITDAX (trailing twelve months) $ 4,663 $ 4,261 Expand Reconciliation of Net Debt The total debt to total capitalization ratio is calculated by dividing total debt by the sum of total debt and total stockholders' equity. This ratio is a measurement which is presented in our annual and interim filings and our management believes this ratio is useful to investors in assessing our leverage. Net Debt is calculated by subtracting cash and cash equivalents and short-term investments from total debt. The Net Debt to Adjusted Capitalization ratio is calculated by dividing Net Debt by the sum of Net Debt and total stockholders' equity. Net Debt and the Net Debt to Adjusted Capitalization ratio are non-GAAP measures which our management believes are also useful to investors when assessing our leverage since we have the ability to and may decide to use a portion of our cash and cash equivalents and short-term investments to retire debt. Our management uses these measures for that purpose. Additionally, as our planned expenditures are not expected to result in additional debt, our management believes it is appropriate to apply cash and cash equivalents and short-term investments to reduce debt in calculating the Net Debt to Adjusted Capitalization ratio. (In millions) March 31, 2025 December 31, 2024 Long-term debt, net 4,280 3,535 Total debt 4,280 3,535 Stockholders' equity 14,224 13,122 Total capitalization $ 18,504 $ 16,657 Total debt $ 4,280 $ 3,535 Less: Cash and cash equivalents (186 ) (2,038 ) Net debt $ 4,094 $ 1,497 Net debt $ 4,094 $ 1,497 Stockholders' equity 14,224 13,122 Total adjusted capitalization $ 18,318 $ 14,619 Total debt to total capitalization ratio 23.1 % 21.2 % Less: Impact of cash and cash equivalents 0.8 % 11.0 % Net debt to adjusted capitalization ratio 22.3 % 10.2 % Expand Reconciliation of Net Debt to Adjusted EBITDAX Total debt to net income is defined as total debt divided by net income. Net debt to Adjusted EBITDAX is defined as net debt divided by trailing twelve month Adjusted EBITDAX. Net debt to Adjusted EBITDAX is a non-GAAP measure which our management believes is useful to investors when assessing our credit position and leverage. (In millions) March 31, 2025 December 31, 2024 Total debt $ 4,280 $ 3,535 Net income 1,285 1,121 Total debt to net income ratio 3.3 x 3.2 x Net debt (as defined above) $ 4,094 $ 1,497 Adjusted EBITDAX (Trailing twelve months) $ 3,834 $ 3,414 Net debt to Adjusted EBITDAX 1.1 x 0.4 x Expand Reconciliation of Net Debt to Adjusted Pro Forma EBITDAX Total debt to net income is defined as total debt divided by net income. Net debt to Adjusted Pro Forma EBITDAX is defined as net debt divided by trailing twelve month Adjusted Pro Forma EBITDAX. Net debt to Adjusted Pro Forma EBITDAX is a non-GAAP measure which our management believes is useful to investors when assessing our credit position and leverage. (In millions) March 31, 2025 December 31, 2024 Total debt $ 4,280 $ 3,535 Net income 1,285 1,121 Total debt to net income ratio 3.3 x 3.2 x Net debt (as defined above) $ 4,094 $ 1,497 Adjusted Pro Forma EBITDAX (Trailing twelve months) 4,663 4,261 Net debt to Adjusted EBITDAX 0.9 x 0.4 x Expand 2025 Guidance The tables below present full-year and second quarter 2025 guidance. Full Year Guidance 2025 Guidance (February) Low Mid High Low Mid High Total Equivalent Production (MBoed) 710 — 740 — 770 720 — 745 — 770 Gas (Mmcf/day) 2,675 — 2,775 — 2,875 2,725 — 2,800 — 2,875 Oil (MBbl/day) 152 — 160 — 168 155 — 160 — 165 Net wells turned in line Marcellus Shale 10 — 13 — 15 No change Permian Basin 150 — 158 — 165 No change Anadarko Basin 15 — 20 — 25 No change Capital expenditures ($ in millions) Total Company $2,100 — $2,250 — $2,400 $2,000 — $2,150 — $2,300 Drilling and completion Marcellus Shale $250 midpoint $300 midpoint Permian Basin $1,570 midpoint $1,450 midpoint Anadarko Basin $230 midpoint No change Midstream, saltwater disposal and infrastructure $200 midpoint $170 midpoint Commodity price assumptions: WTI ($ per bbl) $71 $63 Henry Hub ($ per mmbtu) $4.22 $3.70 Cash Flow & Investment ($ in billions) Discretionary Cash Flow $5.0 $4.3 Capital Expenditures $2.1 — $2.3 — $2.4 $2.0 — $2.2 — $2.3 Free Cash Flow (DCF - incurred capex) $2.7 $2.1 $ per boe, unless noted: Lease operating expense + workovers + region office $2.50 — $3.05 — $3.60 No change Gathering, processing, & transportation $3.25 — $3.75 — $4.25 No change Taxes other than income $1.25 — $1.50 — $1.75 No change General & administrative (1) $0.90 — $1.00 — $1.10 No change Unit Operating Cost $7.90 — $9.30 — $10.70 No change Expand _______________________________________________________________________________ (1) Excludes stock-based compensation and severance expense Expand
