APA Financial Model
Oil and Gas Company Financials Example (Free Excel Download)
APA Corporation is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids (NGLs).
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About this model
This model provides a comprehensive equity valuation and cash flow forecast to determine if APA Corporation can internally fund its multi-billion dollar Suriname offshore development while sustaining its stated policy of returning at least 60% of free cash flow to shareholders following the Callon Petroleum acquisition.
APA Corporation is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids (NGLs). The company operates a geographically diverse, asset-heavy business model with a primary focus on conventional and unconventional onshore assets in the United States and Egypt, alongside offshore assets in the United Kingdom North Sea and Suriname.
Geographic production and revenue are split primarily between the United States (roughly 55% of production) and Egypt (roughly 35% of production), with the UK North Sea making up the remainder of current cash-generating operations. Suriname represents a massive future growth engine but is currently in the capital-intensive development phase. The company ranks as a major independent exploration and production (E&P) player, competing with firms like Devon Energy, EOG Resources, and Marathon Oil.
Recent major events include the $4.5 billion acquisition of Callon Petroleum in April 2024, which added 120,000 net acres in the Delaware Basin and significantly boosted US production. Additionally, in October 2024, APA and its partner TotalEnergies reached a Final Investment Decision (FID) on the GranMorgu project in Block 58 offshore Suriname, committing to a $10.5 billion gross investment to achieve first oil by 2028.
The downloadable APA financial model includes SEC-sourced historical financials, forecast assumptions, core operating schedules, and valuation outputs in an Excel workbook built for review and scenario analysis.
A turnkey financial model
Live formulas, no hardcoded values
Outputs are driven by live formulas, so the workbook updates from its assumptions instead of relying on hardcoded results.
All assumptions in one tab
Inputs are clearly marked in the Assumptions tab and separated from calculations, making it clear what to change and what to leave intact.
Statements always balancing
For integrated-statement models, the balance sheet, cash flow, and supporting schedules tie through properly.
Distinct schedules for clarity
Debt, working capital, taxes, and cash flow can get messy quickly. We group calculations in clear schedules, not across disconnected tabs.
No hidden macros or external links
There are no unexplained external workbook links or macros to undermine auditability or portability.
Changes flow through the model
Update a key driver and see the impact carry through the forecast, financing, and return outputs. We never use hardcoded numbers in formulas.
Historicals & AssumptionsAPA financial modelCompany, Historicals & Assumptions used
Source: SEC EDGAR · values in USD
| Line item | FY2021 | FY2022 | FY2023 | FY2024 | FY2025 |
|---|---|---|---|---|---|
| NET INCOME BEFORE INCOME TAXES | $1.89B | $5.73B | $2.88B | $1.53B | $2.79B |
| Lease operating expenses | $1.24B | $1.44B | $1.44B | $1.69B | $1.50B |
| Operating income | $2.86B | $5.57B | $3.70B | $2.44B | $3.09B |
| Net income | $973.0M | $3.67B | $2.85B | $804.0M | $1.43B |
Forecast assumptions
Defaults used in the downloadable model. Forecast horizon: FY2026–FY2030.
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How to build a detailed financial model for APA
A complete walkthrough of every driver, margin, working-capital input, and capital-allocation assumption used in the downloadable model.
Revenue Deep Dive
United States
- Segment name: United States (Permian Basin and other US)
- Revenue driver formula: (Oil Volume x Realised Oil Price) + (Gas Volume x Realised Gas Price) + (NGL Volume x Realised NGL Price)
- Historical growth rate: 15% to 25% CAGR (heavily distorted by the 2024 Callon Petroleum acquisition)
- Key growth levers and headwinds: Drilling efficiency in the Permian Basin, decline rates of existing unconventional wells, and domestic natural gas pricing weakness.
- Pricing dynamics: Spot pricing linked to WTI for oil and Henry Hub for gas, adjusted for regional basis differentials (e.g., Waha hub for Permian gas).
- Revenue recognition notes: Recognised at the point of delivery when control transfers to the purchaser.
- Seasonality: Minimal seasonality in production, though extreme winter weather in Texas can occasionally freeze in infrastructure and cause temporary shut-ins.
Egypt
- Segment name: Egypt
- Revenue driver formula: Gross Production less Tax Barrels less Noncontrolling Interest x Realised Price
- Historical growth rate: Flat to slightly declining (0% to -3% CAGR)
- Key growth levers and headwinds: Rig count (currently operating around 12 rigs), natural field declines, and renegotiation of production sharing contracts (PSCs) with the Egyptian government.
- Pricing dynamics: Brent-linked pricing.
- Revenue recognition notes: Operates under PSCs where APA receives a share of production to recover costs ("cost oil") and a share of the remaining production ("profit oil"). The Egyptian government\'s share of production used to settle APA\'s tax liabilities is reported as "tax barrels" in gross revenue but excluded from adjusted production.
- Seasonality: None material.
United Kingdom (North Sea)
- Segment name: United Kingdom
- Revenue driver formula: Volume x Realised Price
- Historical growth rate: Declining (-5% to -10% CAGR)
- Key growth levers and headwinds: Mature asset base facing steep natural declines, high operating costs, and punitive UK windfall taxes (Energy Profits Levy).
- Pricing dynamics: Brent-linked for oil, UK NBP for natural gas.
- Revenue recognition notes: Standard point of delivery recognition.
- Seasonality: Summer months often see lower production due to scheduled maintenance turnarounds at offshore platforms.
Suriname (Pre-Revenue)
- Segment name: Suriname (Block 58)
- Revenue driver formula: N/A (First oil expected in 2028)
- Historical growth rate: N/A
- Key growth levers and headwinds: Execution of the GranMorgu Floating Production Storage and Offloading (FPSO) vessel construction and subsea tie-backs.
- Pricing dynamics: Will be Brent-linked offshore crude.
- Revenue recognition notes: N/A
- Seasonality: N/A
Cost Structure
Variable Costs / COGS
- Lease Operating Expenses (LOE): The primary direct cost of extracting hydrocarbons, including labour, maintenance, power, and chemicals. Typically runs $9.00 to $11.00 per BOE globally.
- Gathering, Processing, and Transmission (GPT): Costs to move and treat products, primarily in the US. Runs $3.00 to $4.00 per BOE.
- Production and Severance Taxes: Levied by state governments in the US, typically running 5% to 7% of US revenue.
- Gross margin range: E&P companies do not report traditional gross margin. Instead, they focus on cash margin per BOE (Realised Price minus LOE, GPT, and Taxes), which typically ranges from $25.00 to $40.00 per BOE depending on commodity prices.
- Key input costs: Steel (tubulars), pressure pumping services, diesel fuel, and labour.
- How COGS scales: LOE has a high fixed component per well. As production declines, LOE per BOE naturally rises unless offset by cost reduction programmes.
Operating Expenses
- Exploration Expense: Includes unproved leasehold impairments, seismic data costs, and dry hole costs. Highly variable, ranging from $100 million to $300 million annually.
- General and Administrative (G&A): Corporate overhead, running $350 million to $450 million annually.
- Depreciation, Depletion, and Amortisation (DD&A): Calculated using the unit-of-production method. Typically runs $12.00 to $15.00 per BOE.
- Stock-Based Compensation: Non-cash expense typically running $60 million to $80 million annually.
- Restructuring / one-time charges: Frequent in recent years due to the Callon acquisition and subsequent workforce reductions, running $30 million to $50 million in integration costs.
Margin Profile
- EBITDAX margin: 50% to 65% (EBITDAX is the standard E&P metric, adding back exploration costs).
- Operating margin: 25% to 40%, highly sensitive to benchmark oil prices.
- Margin trend: Compressing slightly in 2025 and 2026 due to lower global oil prices and inflationary pressures on oilfield services, offset partially by $350 million in targeted corporate cost savings.
Balance Sheet Structure
- Total assets: Approximately $20 billion to $22 billion.
- Key asset categories: Proved oil and gas properties dictate the balance sheet, representing over 75% of total assets.
- Goodwill & intangibles: Minimal historically, but the Callon acquisition added some goodwill depending on final purchase price allocation.
- Working capital profile:
- Days Sales Outstanding (DSO): 30 to 45 days.
- Days Inventory Outstanding (DIO): Not meaningful for E&P (hydrocarbons are sold immediately).
- Days Payable Outstanding (DPO): 45 to 60 days.
- Net working capital: Typically negative, which is standard for E&P companies that use cash flow to immediately pay down debt or fund capital programmes.
- PP&E: Oil and gas properties accounted for under the successful efforts method. Capitalised costs are depleted over the life of the proved reserves.
- Asset Retirement Obligations (ARO): A massive liability for APA, particularly in the UK North Sea, representing the discounted future cost of plugging wells and decommissioning offshore platforms.
Capital Expenditure & Investment
- Capex as % of revenue: 25% to 35% (E&P companies measure capex against operating cash flow rather than revenue).
- Maintenance capex vs. growth capex: Approximately $1.5 billion is required to hold production flat. The 2026 budget of $2.1 billion includes growth capital for Suriname.
- Major capex programmes: The GranMorgu development in Suriname requires $5.25 billion net to APA over the next four years. The 2026 budget allocates $230 million specifically to this project.
- Capitalised software: Immaterial.
- M&A pattern: Historically organic, but the 2024 Callon Petroleum acquisition ($4.5 billion) marked a transformational shift to consolidate the Permian Basin.
- Typical acquisition multiple paid: Callon was acquired at roughly 3.0x to 3.5x NTM EBITDAX.
Debt & Capital Structure
- Total debt: Approximately $5.0 billion to $5.5 billion, with net debt under $4.0 billion at year-end 2025.
- Debt/EBITDA ratio: Target is below 1.0x at mid-cycle prices. Currently sits around 0.8x to 1.0x.
- Credit rating: Investment grade (BBB- / Baa3).
- Key debt instruments: Unsecured senior notes with staggered maturities and a syndicated revolving credit facility.
- Maturity profile: Well-laddered, with the next major maturity walls typically handled via refinancing 12 to 18 months in advance.
- Interest rate profile: Predominantly fixed-rate bonds with a weighted average cost of debt around 5.0% to 5.5%.
- Covenants: Standard debt-to-capitalisation limits on the revolving credit facility.
- Share repurchase programme: Highly active. The company uses buybacks as the primary mechanism to meet its 60% free cash flow return target.
- Dividend policy: Base dividend of $1.00 per share annually, yielding roughly 2.5% to 3.0%.
Cash Flow Characteristics
- Operating cash flow conversion: OCF typically exceeds Net Income significantly (1.5x to 2.0x) due to massive non-cash DD&A charges.
- Free cash flow margin: 10% to 20% of revenue, generating roughly $1.0 billion in absolute FCF in 2025.
- Major non-cash items: DD&A, deferred income taxes, and dry hole expenses.
- Working capital cash flow impact: Can swing wildly quarter-to-quarter based on the timing of joint interest billing (JIB) payments and royalty distributions.
- Capex intensity: Extremely high. The business requires constant reinvestment just to offset natural reservoir declines.
- Cash tax rate: Often lower than the GAAP effective tax rate in the US due to intangible drilling cost (IDC) deductions, but extremely high in the UK due to the Energy Profits Levy.
Sheet Structure
- Assumptions: Hardcoded inputs for macro pricing (WTI, Brent, Henry Hub), production volumes by segment, LOE rates, and capex budgets.
- Macro & Pricing: Translates benchmark prices into realised prices using regional differentials for the US, Egypt, and the UK.
- Production Model: Builds daily production (BOE/d) by segment, separating oil, gas, and NGLs. Calculates adjusted Egypt production by stripping out tax barrels.
- Revenue Schedule: Multiplies segment production by realised pricing and days in the period.
- Operating Costs: Calculates LOE, GPT, and production taxes based on volume and revenue drivers.
- Income Statement: Consolidated view down to Net Income, including exploration expense and DD&A.
- Cash Flow Statement: Standard indirect method, bridging Net Income to OCF, investing cash flows (capex), and financing cash flows (dividends, buybacks).
- Balance Sheet: Tracks PP&E, working capital, debt, and the critical Asset Retirement Obligation liability.
- Debt Schedule: Tranches of senior notes, revolver drawdowns, interest expense calculations, and cash sweep logic.
- Valuation (NAV & DCF): A Net Asset Value model based on discounted cash flows of proved reserves, plus a corporate-level DCF for terminal value.
Key Financial Relationships
- US Oil Revenue = US Oil Production (MBbls/d) * Days in Period * US Realised Oil Price ($/Bbl)
- Egypt Adjusted Production = Egypt Gross Production - Egypt Tax Barrels - Egypt Noncontrolling Interest
- Total BOE/d = Oil Volume (Bbls/d) + NGL Volume (Bbls/d) + (Gas Volume (Mcf/d) / 6)
- Realised Oil Price = Benchmark WTI or Brent Price + Regional Basis Differential
- Total LOE Expense = Consolidated Production (BOE/d) * Days in Period * LOE per BOE
- Production Taxes = US Revenue * State Severance Tax Rate
- DD&A Expense = Consolidated Production (BOE/d) * Days in Period * DD&A Rate per BOE
- EBITDAX = Net Income + Interest Expense + Income Tax Provision + DD&A + Exploration Expense
- Free Cash Flow = Cash Flow from Operations - Upstream Capital Investment - Distributions to Noncontrolling Interests
- Shareholder Returns Pool = Free Cash Flow * 60% (Target Return Ratio)
- Share Repurchases = Shareholder Returns Pool - Total Base Dividends Paid
- Ending Share Count = Beginning Share Count - (Share Repurchases / Average Share Price)
Cross-Sheet Dependencies
The Assumptions sheet dictates the macro environment (oil prices) and feeds the Macro & Pricing and Production Model sheets. The outputs from these two sheets multiply together to populate the Revenue Schedule. Revenue flows into the Income Statement and drives variable costs in the Operating Costs sheet. The Income Statement generates Net Income, which is the starting point for the Cash Flow Statement. The Cash Flow Statement subtracts capex (driven by the Assumptions sheet) to calculate Free Cash Flow. Free Cash Flow dictates debt paydown or revolver draws in the Debt Schedule, which calculates interest expense. Interest expense flows back to the Income Statement, creating a circular reference that must be managed with an iterative calculation toggle or macro.
Sign Convention
- Income Statement: Revenue is positive. All expenses (LOE, GPT, G&A, DD&A, Interest, Taxes) are negative. Net Income is the sum of these items.
- Cash Flow Statement: Net Income is positive. Non-cash add-backs (DD&A, Exploration) are positive. Increases in assets are negative; increases in liabilities are positive. Capital expenditures are negative. Dividends and share repurchases are negative. Debt issuance is positive; debt repayment is negative.
- Balance Sheet: All assets, liabilities, and equity balances are positive.
Things Most Likely to Go Wrong
- Egypt PSC Mechanics: Failing to exclude "tax barrels" from adjusted production will artificially inflate both revenue and tax expense, distorting margin analysis.
- Callon Integration Stub Period: The Callon acquisition closed on April 1, 2024. Year-over-year growth rates for 2024 and 2025 will look distorted unless the model accounts for the partial-year contribution in 2024.
- Suriname Capex Phasing: The $5.25 billion net capex for GranMorgu will not be spent evenly. The model must back-load this spending closer to the 2028 first oil date.
- Gas-to-Oil Conversion: Natural gas is converted to BOE at a ratio of 6 Mcf to 1 Bbl. Using a different ratio will break the volume reconciliation.
- ARO Cash Settlements: Asset Retirement Obligations are a non-cash liability when incurred, but plugging wells requires actual cash. The cash flow statement must include a line for "Settlement of ARO" which reduces OCF.
- EBITDA vs EBITDAX: Standard models calculate EBITDA. E&P models must calculate EBITDAX by adding back exploration expense, otherwise valuation multiples will not match consensus estimates.
- Windfall Taxes: The UK Energy Profits Levy is highly volatile and politically driven. Applying a standard statutory tax rate to UK income will drastically underestimate cash taxes.
- Share Count Dynamics: APA aggressively buys back stock. Failing to dynamically reduce the share count based on the 60% FCF payout policy will result in understated EPS in the out-years.
Validation Checks
- "Adjusted production should be roughly 15% lower than reported gross production due to the exclusion of Egypt tax barrels and noncontrolling interests."
- "EBITDAX margin should remain between 50% and 65%; flag if outside this band."
- "Total Upstream Capital Investment must equal the stated guidance (e.g., $2.1 billion for 2026)."
- "Free Cash Flow payout ratio (Dividends + Buybacks / FCF) must be >= 60% based on management policy."
- "Balance sheet must balance: Total Assets = Total Liabilities + Equity in every period."
- "Net Debt to EBITDAX should remain below 1.5x; flag if leverage exceeds this threshold."
- "DD&A per BOE should remain relatively stable between $12.00 and $15.00; flag if the implied rate spikes."
- "US oil production should represent approximately 50% to 55% of total adjusted BOE/d."
Key Assumptions (Default Values)
| Assumption | Default Value | Unit | Rationale |
|---|---|---|---|
| WTI Benchmark Price | 75.00 | $/Bbl | Base case mid-cycle pricing assumption |
| Brent Benchmark Price | 80.00 | $/Bbl | Base case mid-cycle pricing assumption |
| Henry Hub Gas Price | 2.50 | $/Mcf | Base case domestic gas pricing |
| 2026 Total Upstream Capex | 2,100 | $ Millions | Management guidance for 2026 |
| 2026 Suriname Capex | 230 | $ Millions | Management guidance for GranMorgu development |
| 2026 Total Adjusted Production | 371 | MBOE/d | Management guidance for 2026 |
| US Oil Production | 121 | MBbls/d | Midpoint of 2026 management guidance |
| LOE per BOE | 9.50 | $/BOE | Historical average adjusted for recent cost savings |
| GPT per BOE | 3.50 | $/BOE | Historical average for US gathering and processing |
| DD&A per BOE | 13.50 | $/BOE | Based on 2024/2025 actuals |
| G&A Expense | 400 | $ Millions | Annual run-rate based on recent filings |
| Target FCF Payout Ratio | 60.0 | % | Stated corporate capital return framework |
| Annual Base Dividend | 1.00 | $/Share | Current dividend policy |
| Effective Tax Rate | 25.0 | % | Blended global rate including UK windfall taxes |
| WACC | 10.0 | % | Standard discount rate for E&P equity valuation |
Data Sources & Benchmarks
- Filings: SEC EDGAR for APA Corporation (10-K, 10-Q, 8-K).
- Investor Relations: apacorp.com for quarterly earnings supplements, which contain the critical reconciliation between reported and adjusted production.
- Key Peers: Devon Energy (DVN), EOG Resources (EOG), Marathon Oil (MRO), Diamondback Energy (FANG).
- Industry Data: Energy Information Administration (EIA) for benchmark pricing history and Permian basin productivity reports.
- Consensus Estimates: Bloomberg or FactSet for forward curve commodity pricing and consensus EBITDAX estimates.
Sources
- APA Corporation Investor Relations: https://www.apacorp.com/investors/
- APA Corporation 2024 and 2025 Earnings Releases and Supplements
- SEC EDGAR Database: APA Corporation Form 10-K filings
- GlobeNewswire: APA Announces Final Investment Decision for First Oil Development Offshore Suriname (October 2024)
- MarketScreener: APA Corporation completed the acquisition of Callon Petroleum Company (April 2024)
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Frequently asked
What does APA Corporation do?+
APA Corporation is an independent energy company focused on exploring for, developing, and producing natural gas, crude oil, and natural gas liquids. It operates a geographically diverse, asset-heavy business with significant operations in the United States, Egypt, and the UK North Sea.
What are the primary revenue drivers for APA Corporation?+
APA Corporation's revenue is primarily driven by the production and sale of crude oil, natural gas, and natural gas liquids from its diverse asset base. Its operations in the United States and Egypt are the largest current contributors to production and revenue.
What is the assumed revenue growth rate in the APA Corporation financial model?+
The financial model for APA Corporation assumes a revenue growth rate of 3% (0.03). This assumption is used to project the company's future top-line expansion over the forecast horizon.
What is the main purpose of the APA Corporation financial model?+
The primary purpose of the APA Corporation financial model is to provide a comprehensive equity valuation and cash flow forecast. It aims to determine if the company can internally fund its multi-billion dollar Suriname offshore development while maintaining its stated policy of returning at least 60% of free cash flow to shareholders.
Can I download an Excel financial model for APA Corporation?+
Yes, an Excel financial model for APA Corporation is available for download. This model provides a forecast horizon from FY2026 to FY2030, offering detailed projections for the company's financials.
What was the significance of APA Corporation's acquisition of Callon Petroleum?+
The $4.5 billion acquisition of Callon Petroleum in April 2024 was a transformational event for APA Corporation, significantly boosting its US production. This strategic move added 120,000 net acres in the Delaware Basin, consolidating its position in the Permian.
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