Constellation Energy Financial Model

Constellation disaggregates revenue primarily by regional power markets.

• Mid-Atlantic
• *Revenue driver formula:* Mid-Atlantic Volumes (TWh) x Average Realised Price ($/MWh) + Capacity Revenues.
• *Historical growth rate:* 4-6% CAGR, driven by rate base and capacity market pricing.
• *Key growth levers and headwinds:* PJM capacity auction clearing prices, data centre load growth in Virginia/Maryland, and transmission congestion.
• *Pricing dynamics:* Highly dependent on PJM wholesale power prices and capacity market auctions, though heavily hedged forward.
• *Seasonality:* Peaks in Q3 (summer cooling) and Q1 (winter heating).

• Midwest
• *Revenue driver formula:* Midwest Volumes (TWh) x Average Realised Price ($/MWh) + Zero Emission Credits (ZECs) / Carbon Mitigation Credits (CMCs).
• *Historical growth rate:* 2-4% CAGR.
• *Key growth levers and headwinds:* State-level nuclear subsidies (ZECs/CMCs) and transition to federal Production Tax Credits (PTCs).
• *Pricing dynamics:* Regulated subsidy floors combined with wholesale market pricing.
• *Seasonality:* Strong winter and summer peaks.

• New York
• *Revenue driver formula:* NY Volumes (TWh) x Average Realised Price ($/MWh) + ZECs.
• *Historical growth rate:* 1-3% CAGR.
• *Key growth levers and headwinds:* NYISO market dynamics and state clean energy mandates.
• *Pricing dynamics:* Spot market pricing supported by state-level ZECs.
• *Seasonality:* Winter heating demand is a significant driver.

• ERCOT (Texas)
• *Revenue driver formula:* ERCOT Volumes (TWh) x Average Realised Price ($/MWh).
• *Historical growth rate:* 5-8% CAGR (highly volatile).
• *Key growth levers and headwinds:* Extreme weather events, population growth, and grid reliability scarcity pricing.
• *Pricing dynamics:* Energy-only market with no capacity payments; highly volatile spot pricing.
• *Seasonality:* Extreme summer peak (Q3).

• Other Power Regions
• *Revenue driver formula:* Volumes (TWh) x Average Realised Price ($/MWh).
• *Historical growth rate:* 2-5% CAGR.
• *Key growth levers and headwinds:* Expansion into New England, South, and West markets.

*Revenue Recognition Notes:* Revenue from power sales is recognised upon delivery to the grid or customer. The company also records significant unrealised mark-to-market gains and losses on economic hedges, which must be stripped out to assess core operating performance.

• *Total assets:* Approximately $50 billion to $55 billion.
• *Key asset categories:* Property, Plant, and Equipment (PP&E) makes up the bulk of assets. Nuclear Decommissioning Trust (NDT) funds are also highly material (often exceeding $10 billion).
• *Goodwill & intangibles:* Historically moderate, but will increase significantly following the Calpine acquisition.
• *Working capital profile:*
• *DSO:* 35-45 days.
• *DPO:* 30-40 days.
• *Net working capital:* Can swing wildly based on collateral postings for hedging activities and derivative mark-to-market positions.
• *PP&E:* Primarily generation assets. Nuclear fuel is capitalised and amortised to fuel expense as it is consumed in the reactor.
• *Asset Retirement Obligations (AROs):* Massive liability representing the future cost of decommissioning nuclear plants, offset by the NDT assets.

• *Capex as % of revenue:* Typically 12-16%.
• *Maintenance vs. growth:* Approximately 35% of capex is dedicated to nuclear fuel acquisition. The remainder is split between base plant maintenance, nuclear uprates, and specific growth projects.
• *Major programmes:* The Crane Clean Energy Center restart (estimated at over $1 billion, supported by DOE loans) and integration of Calpine assets.
• *M&A pattern:* Historically organic and spin-off driven, but the 2025 Calpine acquisition marks a transformational shift to acquire dispatchable natural gas and expand the retail footprint.

• *Total debt:* Approximately $7 billion to $9 billion pre-Calpine.
• *Credit rating:* Investment grade (Baa2/BBB).
• *Key debt instruments:* Senior unsecured notes, term loans, and a revolving credit facility. The DOE loan for the Crane restart will add specific project-level debt.
• *Maturity profile:* Near-term maturities include roughly $1.03 billion in 2025 and $691 million in 2027.
• *Interest rate profile:* Predominantly fixed-rate bonds.
• *Share repurchase programme:* Highly active, returning excess free cash flow to shareholders.
• *Dividend policy:* Base dividend policy targeting approximately 10% annual growth.

• *Operating cash flow conversion:* Very strong; OCF often exceeds Net Income due to heavy depreciation, nuclear fuel amortisation, and non-cash mark-to-market derivative losses.
• *Free cash flow margin:* 10-15% of revenue. In 2024, the company generated over $3.7 billion in free cash flow.
• *Major non-cash items:* Depreciation, amortisation of nuclear fuel, unrealised fair value adjustments on derivatives, and NDT fund investment returns.
• *Working capital impact:* Collateral requirements for hedging can cause significant year-to-year cash flow volatility.
• *Cash tax rate:* Often differs from the GAAP effective tax rate due to the utilisation of PTCs and accelerated depreciation.

1. Assumptions: Hardcoded drivers for macro variables, power prices, capacity factors, and segment growth.
2. Scenarios: Toggles for the Calpine acquisition close date, Crane Clean Energy Center restart timing, and PTC floor pricing.
3. Generation & Fleet Operations: Calculates TWh generated by region, factoring in planned refuelling outage days and capacity factors.
4. Revenue Build: Calculates revenue for Mid-Atlantic, Midwest, New York, ERCOT, and Other based on volumes and realised pricing.
5. Fuel & Purchased Power: Calculates nuclear fuel amortisation, natural gas costs, and wholesale power purchases.
6. Income Statement: Consolidated view from Revenue down to GAAP Net Income and Adjusted (non-GAAP) Operating Earnings.
7. Balance Sheet: Standard assets, liabilities, and equity, with specific breakouts for NDT funds and AROs.
8. Cash Flow Statement: Bridges Net Income to OCF, CFI, and CFF.
9. Debt Schedule: Tranches of senior notes, DOE loan drawdowns, and interest expense calculation.
10. NDT & ARO Schedule: Rolls forward the Nuclear Decommissioning Trust assets and Asset Retirement Obligation liabilities.
11. DCF Valuation: Unlevered free cash flow calculation, WACC, and terminal value.

1. `Mid-Atlantic Revenue = Mid-Atlantic Volume (TWh) x Mid-Atlantic Realised Price ($/MWh) + Mid-Atlantic Capacity Revenue`
2. `Total Generation (TWh) = Total Fleet Capacity (MW) x 8760 hours x Average Fleet Capacity Factor (%) / 1,000,000`
3. `Nuclear Fuel Expense = Beginning Capitalised Nuclear Fuel + Fuel Purchases - Ending Capitalised Nuclear Fuel`
4. `Gross Margin = Total Operating Revenues - Purchased Power - Fuel`
5. `Adjusted Operating Earnings = GAAP Net Income - Unrealised Fair Value Adjustments - Decommissioning-Related Activities - Plant Retirements/Divestitures`
6. `NDT Ending Balance = NDT Beginning Balance + Contributions + Realised/Unrealised Investment Returns - Decommissioning Spend`
7. `ARO Ending Balance = ARO Beginning Balance + Accretion Expense + Revisions in Estimates - Liabilities Settled`
8. `Free Cash Flow = Operating Cash Flow - Capital Expenditures (including nuclear fuel)`
9. `Effective Tax Rate = Income Tax Expense / Income Before Income Taxes` (Adjusted for PTCs)
10. `Interest Expense = Average Long-Term Debt x Weighted Average Interest Rate`

• Generation & Fleet Operations is the foundational sheet. It feeds volumes into the Revenue Build and fuel consumption into the Fuel & Purchased Power sheet.
• The Revenue Build and Fuel & Purchased Power sheets feed directly into the Income Statement to calculate Gross Margin.
• The NDT & ARO Schedule calculates non-cash accretion and investment returns, which feed into the Income Statement (Other Income/Expense) and the Cash Flow Statement (non-cash adjustments).
• The Debt Schedule creates a circularity: Interest expense reduces Net Income, which reduces Cash, which dictates the need for revolver borrowing, which in turn increases Interest Expense. A circuit breaker toggle is required.

• Revenues and income items are positive.
• Expenses and cash outflows (including capex and dividends) are negative.
• Assets are positive.
• Liabilities and Equity are positive.
• In the Cash Flow Statement, an increase in an asset is negative, and an increase in a liability is positive.

• Failing to adjust GAAP Net Income for unrealised mark-to-market gains/losses on economic hedges; this is the most critical adjustment for utility earnings quality.
• Mismodelling the Inflation Reduction Act PTC floor. The model must calculate whether market prices fall below the inflation-adjusted floor to trigger the tax credit.
• Treating nuclear fuel purchases as a standard operating expense rather than capitalising them into PP&E and amortising them based on reactor consumption.
• Ignoring the impact of planned refuelling outage days on both generation volume and O&M costs (outage years have higher O&M).
• Mishandling the tax treatment of NDT funds; qualified and non-qualified funds are taxed at different rates (often resulting in a blended ~54% effective tax rate on NDT returns).
• Failing to include the pro-forma financial impact of the Calpine acquisition, which fundamentally alters the generation mix and debt profile.
• Double-counting capacity revenues and energy revenues in regions like ERCOT, which is an energy-only market with no capacity payments.
• Misaligning the timing of the Crane Clean Energy Center restart (2027) and the associated Microsoft PPA cash flows.

• Adjusted Operating Earnings per share should align with management's 2025 guidance range of $9.05 to $9.45.
• Nuclear fleet capacity factor should consistently model above 94% based on historical operational excellence.
• Free Cash Flow should remain robust, typically exceeding $3 billion annually pre-Calpine integration.
• The NDT fund balance should roughly equal or exceed the ARO liability balance, indicating fully funded decommissioning obligations.
• Total Assets must equal Total Liabilities plus Equity in every period.
• The effective tax rate on core operations should be approximately 25.5%, excluding NDT-specific tax impacts.
• Capex should spike in 2025/2026 to roughly $3.0 billion to $3.5 billion to account for the Crane restart and nuclear fuel purchases.

• Filings: SEC EDGAR (Constellation Energy Corporation - CEG), specifically the 2024 10-K and 2025 10-Q filings.
• Investor Relations: Constellation IR website for the 2025 Business and Earnings Outlook Presentation and Calpine Acquisition Announcement Presentation.
• Peers for Benchmarking: Vistra Corp (VST), Public Service Enterprise Group (PEG), NRG Energy (NRG), and Talen Energy (TLN).
• Industry Data: PJM Interconnection capacity auction results, ERCOT load forecasts, and NRC (Nuclear Regulatory Commission) outage reports.

• Constellation Energy 2024 Form 10-K
• Constellation Energy Q3 2025 Form 10-Q and Earnings Release
• Constellation Energy Investor Relations Presentations (2024/2025)
• World Nuclear News: Constellation seeks regulator's help for 2027 plant restart
• US Department of Energy: Christopher M. Crane Clean Energy Center Restart Project
• Krause Fund Research: Constellation Energy Corporation