# Coterra (CTRA) Financial Model Free Excel 3-statement financial model and company analysis for Coterra. - Canonical: https://finamodel.com/companies/coterra - Industry: Oil and Gas - Downloadable model: Yes - Excel download: https://finamodel.com/company-models/CTRA.xlsx ## Model Purpose This model provides a standalone equity valuation and cash flow forecast for Coterra Energy (CTRA) to evaluate its intrinsic value and capital return capacity ahead of its pending all-stock merger with Devon Energy. ## Company Overview Coterra Energy is a premier, diversified independent oil and natural gas exploration and production (E&P) company based in Houston, Texas. The company operates across three premier US basins, extracting hydrocarbons and selling them to market purchasers. Business segments are defined by operating region: * Permian Basin (oil and liquids-rich, ~50% of revenue) * Marcellus Shale (dry natural gas, ~35% of revenue) * Anadarko Basin (mixed commodities, ~15% of revenue) The company operates exclusively in the United States. Its business model is an asset-heavy E&P, requiring significant upfront capital expenditure to drill and complete wells, which then produce hydrocarbons over a multi-year decline curve. Coterra holds a strong competitive position as a large-cap independent producer known for its fortress balance sheet and ability to shift capital flexibly between oil and natural gas projects based on commodity cycles. Recent major events include the January 2025 closure of a $3.95 billion acquisition of 49,000 net acres in the Delaware Basin (Lea County, New Mexico) and the February 2026 announcement of a transformative all-stock merger with Devon Energy, expected to close in the second quarter of 2026. ## Revenue Deep Dive Coterra reports revenue based on three distinct commodity streams rather than geographic segments. * **Natural Gas Sales** * Revenue driver formula: Natural Gas Production (Mcf) x Realized Price ($/Mcf) * Historical growth rate: Flat to low-single-digit decline (0% to -2% CAGR) as capital was reallocated away from gas during low price environments. * Key growth levers and headwinds: Driven by Marcellus drilling activity and constrained by Appalachian takeaway capacity and low Henry Hub prices. * Pricing dynamics: Spot pricing tied to Henry Hub, heavily discounted by regional basis differentials (e.g., Leidy Hub). * Revenue recognition notes: Recognised at the point of delivery when control transfers to the purchaser. * Seasonality: Higher demand and pricing typically occur during the winter heating season (Q1 and Q4). * **Oil Sales** * Revenue driver formula: Oil Production (Bbls) x Realized Price ($/Bbl) * Historical growth rate: 5% to 8% CAGR, significantly boosted by the 2025 Delaware Basin acquisition. * Key growth levers and headwinds: Driven by Permian Basin rig count and well productivity; headwinds include oilfield service cost inflation and rapid initial decline rates. * Pricing dynamics: Tied to West Texas Intermediate (WTI), adjusted for Midland basin differentials. * Revenue recognition notes: Recognised upon delivery to midstream pipelines or purchasers. * Seasonality: Generally not seasonal, though extreme weather in Texas can temporarily freeze off production. * **Natural Gas Liquids (NGL) Sales** * Revenue driver formula: NGL Production (Bbls) x Realized Price ($/Bbl) * Historical growth rate: 3% to 5% CAGR, tracking alongside Permian and Anadarko oil and wet gas production. * Key growth levers and headwinds: Dependent on the liquids content of the gas stream and processing plant recoveries. * Pricing dynamics: Realised prices typically track a percentage of WTI or Mont Belvieu hub prices. * Revenue recognition notes: Recognised when processed liquids are sold at the tailgate of the processing plant. * Seasonality: Minor seasonality tied to propane and butane winter demand. ## Cost Structure ### Variable Costs / COGS * Line-by-line breakdown: Lease Operating Expense (LOE), Gathering, Processing and Transportation (GP&T), and Production and Ad Valorem Taxes. * Gross margin range: E&P companies typically look at operating margin per BOE rather than traditional gross margin. Cash operating margins range from 60% to 75% depending on commodity prices. * Key input costs and commodity exposures: Electricity, water disposal, chemicals, and midstream tariffs. * How COGS scales with revenue: LOE and GP&T scale linearly with production volumes. Production taxes scale directly with unhedged revenue (typically 6% to 8% of wellhead value). ### Operating Expenses * R&D: Not applicable for this E&P company. * SG&A: General and administrative expenses cover corporate overhead, IT, and management. It is largely headcount-driven and relatively fixed. * Depreciation & Amortisation: Depletion, Depreciation, and Amortisation (DD&A) is calculated on a unit-of-production basis. It typically runs at $10.00 to $13.00 per BOE. * Stock-Based Compensation: Included within SG&A, typically running at $50 million to $70 million annually. * Exploration Expense: Includes dry hole costs, unproved leasehold impairments, and geological/geophysical costs. Highly variable but typically $50 million to $100 million annually. ### Margin Profile * EBITDAX margin (Earnings Before Interest, Taxes, DD&A, and Exploration expense): 55% to 65% historically. * Margin trend: Fluctuates directly with macro commodity prices. Margins expanded in 2025 due to higher oil mix from the Delaware Basin acquisition. * Segment-level margins: Permian Basin generates the highest cash margins per BOE due to its oil weighting, while the Marcellus generates lower margins per BOE but requires less capital to maintain production. ## Balance Sheet Structure * Total assets: Approximately $22 billion to $25 billion. * Key asset categories: Oil and natural gas properties (proved and unproved) account for over 80% of total assets. The company uses the successful efforts method of accounting. * Goodwill & intangibles as % of total assets: Minimal goodwill; historical mergers were largely asset combinations. * Working capital profile: * Days Sales Outstanding (DSO): 30 to 45 days (receivables from oil and gas purchasers). * Days Inventory Outstanding (DIO): Not material (hydrocarbons are sold as produced). * Days Payable Outstanding (DPO): 45 to 60 days (payables to service companies and royalty owners). * Net working capital as % of revenue: Typically negative or near zero. * Working capital dynamic: The company does not fund growth from working capital; fluctuations are driven by the timing of royalty payments and commodity price swings at quarter-end. * PP&E: Consists of capitalised drilling and completion costs, leasehold acquisitions, and surface equipment. Depleted over the proved developed reserves life. * Right-of-use assets / operating leases: Immaterial relative to the asset base (mostly office space and some field equipment). ## Capital Expenditure & Investment * Capex as % of revenue: 40% to 55% (E&Ps measure this as a reinvestment rate of discretionary cash flow). * Maintenance capex vs. growth capex: Approximately 75% maintenance (to offset base decline) and 25% growth. * Major capex programmes underway: 2026 capital programme is guided at $2.175 billion to $2.325 billion, focused heavily on Permian Basin drilling and completion. * Capitalised software / development costs: Immaterial. * M&A pattern: Transformational and bolt-on. Formed via the Cabot/Cimarex merger in 2021, acquired Delaware assets for $3.95 billion in 2025, and agreed to merge with Devon Energy in 2026. * Typical acquisition multiple paid: Usually valued on a $/flowing BOE or $/acre basis rather than traditional EBITDA multiples. ## Debt & Capital Structure * Total debt: Approximately $3.6 billion long-term debt. * Debt/EBITDA ratio: 0.8x Net Debt to Adjusted EBITDAX at year-end 2025. Target is strictly below 1.0x. * Credit rating: Investment grade (Baa2/BBB). * Key debt instruments: $2.0 billion revolving credit facility (undrawn), $300 million remaining term loan (to be paid in Feb 2026), and various senior unsecured notes. * Maturity profile: Well-laddered senior notes maturing between 2026 and 2043. * Interest rate profile: Predominantly fixed-rate senior notes with a weighted average cost of debt around 4.0% to 4.5%. * Covenants: Standard investment-grade covenants; no restrictive financial maintenance covenants on the bonds. * Share repurchase programme: Highly active. Repurchased 4 million shares for $93 million in Q4 2025. * Dividend policy: Base dividend of $0.22 per share quarterly ($0.88 annualised), yielding approximately 2.9%. ## Cash Flow Characteristics * Operating cash flow conversion: OCF is typically 2.0x to 3.0x Net Income due to massive non-cash DD&A charges. * Free cash flow margin: 20% to 30% of revenue ($2.0 billion FCF generated in 2025). * Major non-cash items: DD&A, deferred income taxes, and unrealised gains/losses on commodity derivatives. * Working capital cash flow impact: Minor impact annually, though quarter-to-quarter swings can be $100 million to $200 million based on commodity price timing. * Capex intensity: Extremely high. Drilling and completing wells requires constant capital deployment to fight natural production declines. * Cash tax rate vs. GAAP effective tax rate: Cash taxes are significantly lower than the GAAP rate (23%) due to the immediate deduction of Intangible Drilling Costs (IDCs) under US tax law. ## Sheet Structure 1. **Macro & Assumptions**: WTI and Henry Hub price decks, regional basis differentials, inflation escalators, and corporate tax rates. 2. **Production Forecast**: Daily production volumes (MBbl/d, MMcf/d, MBbl/d of NGLs) broken out by basin (Permian, Marcellus, Anadarko). 3. **Pricing & Revenue**: Calculation of realised prices (benchmark plus/minus differentials) and total revenue by commodity stream, including cash settlements of derivatives. 4. **Operating Costs**: Calculation of LOE, GP&T, and Production Taxes based on unit costs per BOE and revenue. 5. **Income Statement**: Consolidated GAAP income statement from Revenue down to Net Income, including DD&A, Exploration Expense, and SG&A. 6. **Cash Flow Statement**: Operating, Investing, and Financing cash flows. Must include the DD&A add-back, deferred tax adjustments, and detailed shareholder returns (dividends and buybacks). 7. **Balance Sheet**: Standard asset, liability, and equity accounts. PP&E must be driven by the Capex and DD&A schedules. 8. **Debt & Interest Schedule**: Tranche-by-tranche debt build, mandatory repayments (e.g., the 2026 term loan payoff), and interest expense calculation. 9. **Reserves & NAV Valuation**: Net Asset Value calculation based on proved reserves, future development capital, and a discounted cash flow of the producing asset base. ## Key Financial Relationships 1. Total Production (MBOE) = Oil Production (MBbls) + NGL Production (MBbls) + (Natural Gas Production (MMcf) / 6) 2. Realised Oil Price ($/Bbl) = WTI Benchmark Price + Permian Oil Differential 3. Realised Gas Price ($/Mcf) = Henry Hub Benchmark Price + Blended Gas Differential (weighted by Marcellus and Permian volumes) 4. Oil Revenue = Oil Production (MBbls) x Realised Oil Price 5. Gas Revenue = Natural Gas Production (MMcf) x Realised Gas Price 6. NGL Revenue = NGL Production (MBbls) x Realised NGL Price 7. Total Revenue = Oil Revenue + Gas Revenue + NGL Revenue + Cash Settlements of Derivatives 8. Production Taxes = Total Unhedged Revenue x Production Tax Rate (%) 9. Lease Operating Expense (LOE) = Total Production (MBOE) x LOE per BOE 10. DD&A Expense = Total Production (MBOE) x DD&A Rate per BOE 11. Adjusted EBITDAX = Net Income + Interest Expense + Income Tax Provision + DD&A + Exploration Expense + Non-Cash SBC + Unrealised Derivative Losses 12. Free Cash Flow = Cash Flow from Operations - Cash Capital Expenditures ## Cross-Sheet Dependencies * The **Macro & Assumptions** sheet dictates the pricing environment, feeding directly into the **Pricing & Revenue** sheet. * The **Production Forecast** drives both the **Pricing & Revenue** sheet (volumes) and the **Operating Costs** sheet (since LOE and GP&T are calculated per BOE). * **Pricing & Revenue** and **Operating Costs** feed the **Income Statement** to calculate operating income. * The **Income Statement** feeds Net Income to the top of the **Cash Flow Statement**. * The **Cash Flow Statement** calculates capital expenditures, which feeds the PP&E line on the **Balance Sheet** and updates the DD&A rate on the **Income Statement**. * The **Debt & Interest Schedule** uses cash flow deficits/surpluses from the **Cash Flow Statement** to draw/pay down the revolver, feeding interest expense back to the **Income Statement** (creating a potential circularity that must be managed with a toggle). ## Sign Convention * Production volumes, benchmark prices, and revenues are entered and displayed as positive numbers. * Expenses on the Income Statement (LOE, GP&T, SG&A, DD&A) are calculated as positive numbers but subtracted in subtotals. * Capital expenditures, dividends, and share repurchases are displayed as negative numbers on the Cash Flow Statement to represent outflows. * On the Balance Sheet, Assets are positive, and Liabilities/Equity are positive. ## Things Most Likely to Go Wrong * Failing to convert natural gas volumes correctly. Gas is reported in Mcf or MMcf, but must be divided by 6 to calculate Barrels of Oil Equivalent (BOE). * Applying production taxes to hedged revenue. Production and ad valorem taxes are assessed on the physical wellhead value, not the post-hedge financial value. * Ignoring regional basis differentials. Marcellus gas trades at a significant discount to Henry Hub; modelling gas revenue purely on Henry Hub will drastically overstate cash flow. * Including unrealised derivative mark-to-market gains in Adjusted EBITDAX. Only cash settlements of derivatives should impact the cash flow proxy. * Mismodelling the 2025 Delaware Basin acquisition. Historical financials prior to 2025 do not include these assets, making historical growth rates and unit costs incomparable to 2025 and 2026 projections. * Overestimating cash taxes. E&P companies benefit from Intangible Drilling Cost (IDC) deductions, making cash taxes significantly lower than the 23% statutory GAAP rate. * Failing to account for the $300 million term loan maturity in February 2026, which will require a direct cash outflow in Q1 2026. * Modelling the company into perpetuity without flagging the pending Devon Energy merger, which is expected to close in Q2 2026 and will terminate Coterra as a standalone reporting entity. ## Validation Checks * Total Production (MBOE/d) must exactly equal Oil (MBbl/d) + NGL (MBbl/d) + (Gas (MMcf/d) / 6). * Net Debt to Adjusted EBITDAX must remain below 1.0x, reflecting the company's fortress balance sheet policy. * Reinvestment Rate (Capital Expenditures / Discretionary Cash Flow) should sit between 45% and 55% based on management guidance. * DD&A per BOE should remain relatively stable between $10.00 and $13.00; wild fluctuations indicate a broken PP&E or reserves formula. * The Balance Sheet must balance: Total Assets = Total Liabilities + Shareholders' Equity in every forecast period. * Free Cash Flow must be sufficient to cover the base dividend of $0.88 per share annually. * Total shareholder returns (dividends plus buybacks) should represent approximately 70% to 80% of Free Cash Flow. ## Key Assumptions (Default Values) | Assumption | Default Value | Unit | Rationale | |---|---|---|---| | WTI Oil Price | 75.00 | $/Bbl | Standard mid-cycle macro assumption for 2026 | | Henry Hub Gas Price | 3.00 | $/Mcf | Standard mid-cycle macro assumption for 2026 | | Permian Oil Differential | -1.50 | $/Bbl | Historical discount to WTI for Midland delivery | | Blended Gas Differential | -0.75 | $/Mcf | Reflects heavy weighting to discounted Marcellus gas | | Oil Production Growth | 5.0 | % | Management guidance for 2025-2027 CAGR | | Gas Production Growth | 0.0 | % | Management guidance reflecting capital shift away from gas | | LOE per BOE | 4.50 | $/BOE | Based on recent historical averages | | GP&T per BOE | 3.00 | $/BOE | Based on recent historical averages | | Production Tax Rate | 6.5 | % | Historical average percentage of unhedged revenue | | SG&A per BOE | 1.20 | $/BOE | Based on 2025 run-rate | | DD&A per BOE | 12.00 | $/BOE | Based on 2025 actuals | | 2026 Capital Expenditures | 2,250 | $ Millions | Midpoint of management's 2026 guidance ($2.175B - $2.325B) | | Base Dividend | 0.88 | $/Share | Annualised rate declared in Q4 2025 | | Effective Tax Rate | 23.0 | % | Standard corporate statutory rate | | Cash Tax Rate | 10.0 | % | Estimated cash tax rate due to IDC deductions | | Share Count | 759.2 | Millions | Actual outstanding shares as of February 2026 | ## Data Sources & Benchmarks * SEC EDGAR: Coterra Energy (CTRA) 10-K, 10-Q, and 8-K filings. * Investor Relations: Coterra Q4 2025 Earnings Release and 2026 Guidance Presentation. * Key Peers for Benchmarking: Devon Energy (DVN), Diamondback Energy (FANG), EOG Resources (EOG), and Chesapeake Energy (CHK). * Macro Data: Energy Information Administration (EIA) for WTI and Henry Hub historical pricing and storage data. * Industry Data: Baker Hughes Rig Count for basin-level activity tracking. ## Sources * Coterra Energy Inc. Q4 2025 Earnings Release (February 26, 2026) * Coterra Energy Inc. 2025 Annual Report on Form 10-K * Coterra Energy Inc. Q4 2025 Investor Presentation * Devon Energy and Coterra Energy Merger Announcement Press Release (February 2026) --- ## Frequently asked questions ### What kind of company is Coterra Energy and what does it do? Coterra Energy is a premier, diversified independent oil and natural gas exploration and production (E&P) company based in Houston, Texas. It operates across three premier US basins, extracting hydrocarbons and selling them to market purchasers. ### How does Coterra Energy generate its revenue? Coterra Energy generates revenue primarily from natural gas sales and oil sales. Natural gas revenue is driven by production volume and realized price per Mcf, while oil revenue is driven by production volume and realized price per Bbl. ### What are Coterra Energy's typical capital expenditure requirements? Coterra Energy's capital expenditure typically ranges from 40% to 55% of revenue, measured as a reinvestment rate of discretionary cash flow. Approximately 75% of this capital is for maintenance to offset base decline, with the remaining 25% allocated to growth projects. ### What are the key revenue growth assumptions for Coterra Energy's financial model? A financial model for Coterra Energy might incorporate a Revenue_Growth assumption of 0.2, reflecting overall growth expectations. Historically, oil sales have seen 5% to 8% CAGR, significantly boosted by acquisitions, while natural gas sales have been flat to low-single-digit decline. ### What are important financial assumptions for a Coterra Energy valuation model? Key financial assumptions for a Coterra Energy valuation model include a Revenue_Growth of 0.2, COGS_Pct_Revenue at 0.55, and SGA_Pct_Revenue at 0.0579. The model also considers a Tax_Rate of 0.2183 and DA_Pct_Revenue of 0.2264. ### Can I download a financial model for Coterra Energy to analyze its valuation? Yes, a downloadable Excel model is available for Coterra Energy (CTRA) that provides a standalone equity valuation and cash flow forecast. This model evaluates its intrinsic value and capital return capacity ahead of its pending merger with Devon Energy. [Interactive forecast calculator](https://finamodel.com/companies/coterra/forecast)