Constellation Energy (CEG), Financial Analysis

1 Revenue & Business Model

• Storyline: in 2026 Constellation added a gas fleet and a second retail book to the largest US nuclear fleet, and signed long term contracts with data center operators. Calpine explains most of the growth in 2026 figures; the legacy regions show the change in the existing business. Chapters 2 to 4 cover the three drivers: nuclear generation and data center contracts, the Calpine gas fleet, and retail and commercial supply.
• Business model: Constellation generates power from about 22 GW of nuclear capacity (14 stations, 25 units) and, since Jan 2026, about 23 GW of Calpine gas and geothermal plants, and sells it with purchased power and gas to about 2.5m customer accounts. Segments are US regions: Mid‑Atlantic, Midwest, New York, ERCOT, Other Power Regions and, from Q1 2026, Calpine. Management measures segments on revenue net of purchased power and fuel (RNF).
• Operating revenues FY2021 $19.6bn to FY2025 $25.5bn; TTM Q3 2026 $34.3bn incl. three quarters of Calpine. Revenue includes pass through retail power and gas sales and hedge marks, so it moves with commodity prices: unrealized hedge gains added $1.32bn to Q1 2026 revenue.
• 9M 2026: revenue $28.18bn, +44.8%, of which Calpine $7.93bn; legacy five regions $16.80bn, +1.1%, and their RNF $8.46bn, +4.0%. Pro forma revenue as if Calpine had been owned from 1 Jan 2025 was $28.41bn against $27.25bn (Form 10-Q).
• Geography: all segments are US regions; Canada and UK activity is not reported separately, so no regional revenue split beyond the segments is shown.

2 Nuclear Generation and Data Center Contracts: 97.2% Capacity Factor and 8,500 MW of New Agreements

• Nuclear output 46,677 GWh in Q3 2026, +0.4%, after 44,666 GWh in Q1 and 44,160 GWh in Q2 2026 when refueling outages ran to 99 and 86 days. Capacity factor 97.2% against 96.8%; FY2025 94.7% on 182,690 GWh.
• Legacy regions, Q3 2026 against Q3 2025: revenue $5.70bn, (3.1%); RNF $2.98bn, (0.5%). Mid‑Atlantic RNF +15.1%, Midwest (1.2%), New York +3.3%, ERCOT (16.9%). In 9M 2026 legacy RNF rose +4.0% to $8.46bn.
• Data center and hyperscaler agreements as filed: Microsoft (Crane restart, 835 MW, 20 years), Meta (Clinton, 1,121 MW, 20 years from Jun 2027), Amazon (Calvert Cliffs, 690 MW, 20 years), Google (about 890 MW of uprates, 20 years, plus a 15 year 2,700 MW load following agreement) and CyrusOne (1,160 MW at Calpine gas sites). The Q3 2026 presentation counts about 4,560 MW contracted with three customers in Q3, incl. 270 MW through Peak+ (Ex 99.2).
• Contracted volumes: expected generation under long term agreements rises from 60m MWh in 2029 to 91m MWh in 2032, about 45% of the clean baseload fleet; 1,165 MW of uprates (about $4.3bn) are planned, 110 MW in 2027 to 2028, 605 MW in 2029 to 2030 and 450 MW in 2031 to 2032.
• Nuclear tax credit: revenue from the credit fell to $44m in Q3 2026 from $175m, and from about $2.08bn in FY2024 to about $320m in FY2025, as power prices rose above the phase out range of $26.00 to $44.75/MWh.
• PJM capacity auctions: Constellation cleared 18,025 MW for 2026/27 at $329/MW per day, 17,950 MW (15,525 MW nuclear) for 2027/28 at $333 and 18,875 MW (15,700 MW nuclear) for 2028/29 at $325, excluding plants held for sale.

How the nuclear and data center power market is changing

• Co located load: in Dec 2025 FERC found the PJM tariff unjust and unreasonable and ordered new transmission services for co located load; in Jun 2026 it pressed PJM to act before the proposed Jun 2029 date (Form 10-Q, Q3 2026).
• Capacity price collar: in Apr 2026 FERC accepted an extension of the PJM collar of about $175 to $325/MW per day to the 2028/29 and 2029/30 auctions; PJM filed a one time reliability backstop procurement for 1 to 28 Mar 2027 with results due 10 May 2027 (Form 10-Q, Q3 2026).
• Power prices: PJM West day ahead power averaged $69.97/MWh in Q3 2026 against $46.77, +49.6%; the Illinois carbon mitigation credit averaged ($26.54)/MWh, paid to ComEd, against ($17.11) (Form 10-Q, Q3 2026).
• Federal financing: the DOE guaranteed a $1.0bn loan for Crane (Nov 2025) and gave a conditional commitment of up to $5.0bn for uprates (Oct 2026), both at Treasuries plus 0.375%.
• Other nuclear contracts in filings: Vistra signed a 20 year 1,200 MW PPA with AWS at Comanche Peak (Sep 2025), deliveries from Q4 2027 (Vistra Form 10-Q, Q3 2026).

3 Calpine Gas Fleet: New Segment From Jan 2026 With $1.93bn of Q3 RNF

• Calpine segment Q3 2026: revenue $3.38bn and RNF $1.93bn on 38,387 GWh; Q1 $2.40bn and $1.13bn, Q2 $2.15bn and $1.03bn. The segment started on 7 Jan 2026, so there is no prior year comparison; management states that Calpine earnings since closing cannot be isolated because financing was combined.
• Share of the group: Calpine was 35.4% of Q3 2026 revenue and 37.4% of RNF; total supply and sales volume rose to 108,674 GWh from 70,635 GWh.
• Deal terms: $21.8bn of consideration (50m shares and $4.3bn cash), $12.6bn of debt assumed and $11.1bn of provisional goodwill. On a pro forma basis, 9M 2026 net income was $3.94bn against $2.67bn.
• Required sales: DOJ cleared the deal with seven divestitures: Gregory (sold Jan 2026, $136m), Brazos Valley (sold Oct 2026, $860m) and five PJM plants of about 4.4 GW to LS Power for $5.0bn, expected by end 2026. Constellation also agreed to buy the 609 MW Rhode Island State Energy Center for $715m.
• Data center use of gas sites: CyrusOne agreements cover 380 MW at Freestone, an exclusive 380 MW second phase and 400 MW at Thad Hill; the company cites $0.20 to $0.50 of EPS per 1,000 MW of such deals (Ex 99.2 of 9 Nov 2026). Pin Oak Creek (460 MW gas peaker, ERCOT) achieved commercial operation on 30 Apr 2026 (Ex 99.1 of 11 May 2026).

How the gas generation market is changing

• Consolidation: Constellation closed Calpine ($21.8bn, Jan 2026), NRG closed the LS Power portfolio (about 13 GW, Jan 2026) and Vistra closed Cogentrix (about 5,500 MW, Oct 2026) (company filings).
• Cost of new plants: Constellation puts the levelized cost of a new combined cycle plant in eastern PJM at about $110 to $130/MWh, assuming about $3,000/kW (Ex 99.2 of 9 Nov 2026).
• Gas prices: Henry Hub averaged $2.87/MMBtu in Q3 2026 against $3.03, while Q1 2026 averaged $4.90 with Algonquin at $14.08 during winter weather; ERCOT North day ahead power averaged $34.41/MWh against $35.05 (Forms 10-Q, Q1 and Q3 2026).
• Emission rules: in Sep 2026 the EPA repealed its 2024 power plant greenhouse gas standards except efficiency standards for new gas plants, removing carbon capture requirements from 2032 (Form 10-Q, Q3 2026).
• Spark spreads: Constellation models a base ERCOT gas spark spread of $21/MWh on 71m MWh in 2026 and $22 on 68m MWh in 2027, and $25 on 25m MWh in the West in both years (Ex 99.2 of 9 Nov 2026).

4 Retail and Commercial Supply: 245m MWh of Load Without a Separate Revenue Line

• No retail revenue line: Constellation reports retail power inside the five regional segments and Calpine, and gas and other products in the unallocated line, so this chapter uses filed proxies: changes in retail load revenue, gas revenue, purchased power volumes and modelled commercial margins.
• Retail load revenue in the Q3 2026 Form 10-Q: +$160m in Mid‑Atlantic and +$130m in Midwest against Q3 2025 on higher contracted energy prices, and ($185m) in Other Power Regions; for 9M 2026 +$630m, +$455m and ($285m).
• Other and gas revenue: unallocated other revenue (wholesale and retail gas, UK and other products) $829m in Q3 2026, (1.8%); gas revenue from contracts with customers $322m, +25.8%, and $1.59bn in 9M 2026, +17.1%.
• Commercial modelling inputs for 2026 (Ex 99.2 of 9 Nov 2026): power margin of $4.25 to $4.35/MWh on 245m MWh, against $3.70 to $3.80/MWh on 200m MWh before Calpine (Ex 99.2 of Nov 2025); gas margin $0.40 to $0.45/dth on 835m dth (850m dth in 2027).
• Customers and contracts: about 2.5m customer accounts incl. 80% of the Fortune 100; fixed price contract obligations of $12.12bn remaining at 30 Sep 2026; purchased power 17,015 GWh in Q3 2026, (5.4%).
• Weather: the Form 10-Q links most of a $565m rise in Midwest purchased power in 9M 2026 to higher costs from a weather event in Jan 2026 and to net transmission costs.

How the retail and commercial supply market is changing

• Contract prices: retail load revenue rose on higher contracted energy prices, by $630m in Mid‑Atlantic and $455m in Midwest in 9M 2026 (Form 10-Q, Q3 2026).
• Competitors: NRG retail power volume rose 6.1% to 47,190 GWh in Q3 2026 after it adopted an integrated generation and retail model in the East; Vistra retail cooling degree days were 121% of normal against 95% (Forms 10-Q, Q3 2026).
• Large loads: in Aug 2026 PJM filed an interim resource adequacy proposal to curtail new loads over 50 MW without new capacity; FERC largely rejected it (Form 10-Q, Q3 2026).
• New products: Peak+ combines new capacity, incl. generation and demand response, with energy products; the first deal is 20 years and 270 MW from 2028 (Ex 99.1 of 9 Nov 2026).

5 Financial Analysis & Ratios

• Operating margin TTM 17.5% against 12.1% in FY2025 and 18.5% in FY2024; Q3 2026 26.1% against 16.5%. GAAP results include unrealized hedge marks and nuclear decommissioning trust gains and losses, so margins move between quarters: Q2 2026 operating margin was 7.7%.
• Net income TTM $4.37bn (12.8% of revenue); 9M 2026 $3.94bn against adjusted operating earnings of $3.68bn. The Q3 2026 effective tax rate was 18.2%, incl. a $108m deferred tax benefit from apportionment changes.
• Gross profit in this report equals revenue net of purchased power and fuel (RNF): TTM $15.88bn, 46.4% of revenue; Calpine contributed $4.08bn in 9M 2026.
• Balance sheet at 30 Sep 2026: total debt $23.39bn (short term $3.99bn, long term $19.40bn); cash $0.60bn; goodwill $11.50bn; assets held for sale $5.66bn; nuclear decommissioning trust funds $20.38bn against asset retirement obligations of $12.89bn; equity $32.71bn after $17.60bn of shares issued for Calpine.
• Liquidity and ratings: about $7.2bn available under credit facilities of about $14.5bn; ratings BBB+ and Baa1; target debt to EBITDA of 2.00x to 2.25x. A downgrade below investment grade would require about $3.6bn of collateral (Form 10-Q).

Cost structure and cash flow

• Purchased power and fuel is the largest cost: 57.5% of FY2025 revenue against 71.4% in FY2022 and 48.5% in FY2024; it moves with power and gas prices and with hedge results. Operating and maintenance cost was 24.1% of revenue in FY2025 against 20.0% in FY2021; guidance for adjusted operating and maintenance cost is $7.08bn in 2026 and 2027 incl. Calpine.
• Q3 2026 total operating expenses $7.07bn, +28.9%, against revenue +45.4%; operating income also includes a $12m gain on asset sales; operating margin 26.1% against 16.5%.
• GAAP and adjusted earnings: adjusted operating earnings exclude unrealized hedge gains and losses, decommissioning related items (trust fund results and asset retirement changes), amortization of Calpine commodity contracts acquired, Calpine merger and integration costs and some tax items. In 9M 2026 these items lowered adjusted earnings by $254m against GAAP: unrealized gains $508m and decommissioning gains $339m were removed, and contract amortization $342m and Calpine costs $276m were added back.
• Free cash flow as reported was negative from FY2021 to FY2024: (2.67bn), (4.04bn), (7.72bn) and (5.03bn). Collections on the deferred purchase price of receivables sold under the securitization facility ($3.9bn, $5.0bn, $7.3bn and $10.2bn) were reported as investing cash flows. Including them, free cash flow was $1.24bn, $0.92bn, ($0.38bn) and $5.19bn. There were no such collections in FY2025, when reported free cash flow was $1.29bn. FY2024 operating cash flow also includes $1.57bn from selling nuclear tax credits.
• 9M 2026 cash: operating cash flow $4.98bn, capital expenditure $3.46bn, free cash flow $1.52bn; repurchases $3.0bn and dividends $0.46bn, funded partly with new debt.
• Debt after Calpine: total debt $23.39bn at 30 Sep 2026 against $8.99bn at FY2025, after $12.55bn assumed at closing, $4.95bn of notes issued in Jan and May 2026 and $5.15bn of Calpine debt repaid. Long term debt split at 30 Sep 2026: $14.5bn Constellation and $4.9bn Calpine (Ex 99.2).

6 MD&A & Management Commentary

Q3 2026 results: Form 8-K Ex 99.1 and 99.2 and Form 10-Q of 9 Nov 2026

• Q3 2026: operating revenues $9.55bn against $6.57bn; GAAP net income $1.84bn ($5.19 per share) against $0.93bn ($2.97); adjusted operating earnings $1.79bn ($5.06) against $0.95bn ($3.04). GAAP exceeded adjusted earnings by $43m in Q3; the largest items removed were unrealized hedge gains of $127m and a $108m income tax benefit.
• Drivers in the 10-Q: Calpine contributed segment revenue of $3.38bn and RNF of $1.93bn; PJM capacity prices averaged $329.17/MW per day against $269.92; PJM West day ahead power averaged $69.97/MWh against $46.77. Nuclear tax credit revenue fell to $44m from $175m as higher prices reduced the credit.
• Operations: nuclear capacity factor 97.2% (99.2% for the summer months per Ex 99.2) with 20 refueling outage days; gas, oil and hydro fleet equivalent forced outage factor 5.9%; renewable energy capture 96.4% against 96.8%.
• New agreements in the release: Amazon 20 year 690 MW PPA plus retail supply, supporting more than $3bn of investment at Calvert Cliffs incl. a 190 MW expansion for 2030 to 2032; Google 20 year PPA enabling about 890 MW of uprates at 11 units, first in 2028, plus a 15 year 2,700 MW load following agreement; first Peak+ deal, 20 years and 270 MW from 2028; purchase of the 609 MW Rhode Island State Energy Center for $715m.
• Financing: conditional DOE loan guarantee of up to $5.0bn for uprates, 30 years at Treasuries plus 0.375%; the Q3 2026 presentation puts the potential saving at about $40m a year before tax, based on current CEG 30 year bond spreads (Ex 99.2).
• Q2 2026 (8-K of 6 Aug 2026 and Form 10-Q): GAAP EPS $1.42 against $2.67; adjusted operating EPS $2.55 against $1.91; guidance raised to $11.50 to $12.50 on higher realized customer margins and portfolio optimization, partly offset by performance related compensation; 86 refueling outage days against 41 cut the capacity factor to 93.0%; 920 MW of 15 to 20 year nuclear PPAs signed incl. 176 MW with Walmart.
• Q1 2026 (8-K of 11 May 2026 and Form 10-Q): GAAP EPS $4.49 against $0.38, incl. $1.32bn of unrealized hedge gains in revenue; adjusted operating EPS $2.74 against $2.14 on the Calpine addition and market and portfolio conditions, partly offset by nuclear outages; the Form 10-Q cites higher capacity revenue and higher costs from a weather event in Jan 2026; guidance of $11.00 to $12.00 affirmed.

Management and CFO commentary

• CFO Shane Smith, Q3 2026 release (9 Nov 2026): adjusted operating EPS $5.06 against $3.04; the guidance midpoint raised for the second time in 2026; capital allocation named nuclear uprates, the Rhode Island State Energy Center purchase and repurchases; about $3.0bn of buybacks in 2026.
• CFO, Q2 2026 release and presentation (6 Aug 2026): guidance raised to $11.50 to $12.50 on 357m expected diluted shares; about $2.2bn of buybacks to that date; $5.9bn of gross proceeds expected from the required divestitures; priorities: Calpine integration and returns on the larger fleet.
• 2026 Business and Earnings Outlook (31 Mar 2026, finance section): base earnings 60% to 70% of the total and enhanced earnings 30% to 40%; buyback authorization raised to $5.0bn; $3.9bn of growth capital.
• CFO, Q4 2025 release (24 Feb 2026): FY2025 adjusted operating EPS $9.39 against $8.67, above the guidance midpoint for a fourth year; 2026 guidance deferred to the 31 Mar 2026 outlook.
• CEO Joe Dominguez, Q3 2026 release: the Q3 agreements add more than 1,000 MW of new emission free generation, with no costs borne by existing customers; Peak+ introduced.
• CEO, Q1 2026 release (11 May 2026): execution priorities named as operations, Calpine integration, new resources and a changing regulatory environment.

7 Sector & Competitor Analysis

• Sector: US competitive power generation and retail supply. Independent power producers sell output into wholesale markets such as PJM and ERCOT, and under long term contracts; capacity auction prices, power prices and data center contracts drove 2026 results, while acquisitions of gas fleets changed company size.
• Size, TTM Q3 2026: Constellation revenue $34.25bn, NRG $34.96bn, NextEra Energy $28.83bn (incl. its regulated utility), Vistra $20.59bn and Talen $3.95bn.
• Margins, US GAAP TTM: operating margin Constellation 17.5%, Vistra 20.6%, NRG 7.7%, Talen 2.0%; net margin 12.8%, 13.1%, 3.4% and (6.4%). NextEra Energy margins are left out: its Q3 2026 net income was $4.78bn against $2.44bn, and the cause was outside the scope of this report.
• Valuation, US GAAP P/E TTM: Constellation 22.1x, Vistra 18.0x, NRG 17.0x; EV/Sales 3.5x, 3.1x and 1.2x. On adjusted operating EPS Constellation trades at 21.7x.
• Q3 2026 by company measure: Vistra ongoing operations adjusted EBITDA $2.38bn, +50.4%; NRG economic gross margin $2.98bn, +30.7%; Talen adjusted EBITDA $669m, +84.3%; PSEG Power & Other nuclear output 8,172 GWh, +3.4%; NextEra Energy Resources net income $1.49bn, +16.9%; Constellation adjusted operating earnings $1.79bn, +88.2%. Every figure includes acquisitions made since Q3 2025.

8 Material Events & Contracts

• 23 Forms 8-K in the twelve months to 9 Nov 2026 (the two of 9 Dec 2025 share one row below): four results releases (Item 2.02), the 2026 Business and Earnings Outlook, the Calpine closing and related financings, two PJM auction results, officer and director changes and the annual meeting results.
• Calpine (8-K of 7 Jan 2026): acquisition completed; former Calpine holders received 50m shares, about 13.8% of CEG, with registration rights; Calpine notes of $2.29bn were exchanged into Constellation notes and the Calpine indentures stripped of most covenants.
• Financing: $2.75bn of senior notes in Jan 2026 incl. $800m of 40 year notes; the DOE guaranteed $1.0bn loan for Crane (Nov 2025); a conditional DOE commitment of up to $5.0bn for uprates (Oct 2026, reported 9 Nov 2026).
• Buybacks and the Calpine sellers: former Calpine holders sold 11m shares in a Jun 2026 secondary offering; Constellation bought 2m of them for about $558m. Q3 2026 repurchases were about $1.0bn for 3.8m shares (Form 10-Q).
• PJM auctions (Forms 8-K of 17 Dec 2025 and 14 Jul 2026): 17,950 MW cleared at $333/MW per day for 2027/28 and 18,875 MW at $325 for 2028/29.
• Board: Robert Lawless retired as Chair in Aug 2026; CEO Joe Dominguez became Chair and Charles Harrington Lead Independent Director; Roger Crandall joined the board; Alan Armstrong joined in Jan and resigned in Mar 2026.

9 Ownership, Voting Power & Annual Meeting

• One share class, one vote per share; no controlling holder. 351.6m shares outstanding at 31 Oct 2026. Schedules 13G: Vanguard Capital Management 6.39% (31 Mar 2026), ECP ControlCo (former Calpine owners) 4.0% (30 Jun 2026, down from 6.1% at closing) and Capital International Investors 3.3% (31 Mar 2026, down from 5.5%). Half of the Calpine merger shares stay locked up until 30 Jun 2027.
• 2026 annual meeting (28 Apr 2026): all 11 directors elected, with support from 89.8% (Charles Harrington) to 99.0% (Nneka Rimmer) of votes cast; say on pay 94.7%; PricewaterhouseCoopers ratified; a shareholder proposal for a report on DEI initiatives received 1.2%.
• Insiders, twelve months to Oct 2026: no open market sales; one open market purchase. Director Roger Crandall bought 1,500 shares at $278.62 on 11 Aug 2026 (about $0.42m). Feb 2026 transactions were share award settlements: CEO Joe Dominguez had 191,817 shares vest, 83,104 withheld for tax and 92,993 disposed to the company at $272.15. Andrew Novotny received 298,853 shares on 7 Jan 2026 in connection with the Calpine merger.
• Officers: Shane Smith became CFO and Dan Eggers Senior EVP, Finance and Data Economy at the Calpine closing; Calpine CEO Andrew Novotny became Senior EVP, Constellation Power Operations; Kathleen Barron retired as Chief Strategy and Growth Officer.

Annual meeting of 28 Apr 2026

• Virtual only meeting, record date 4 Mar 2026: no transcript, prepared remarks or presentation for the meeting was filed with the SEC; the vote results above come from the Form 8-K Item 5.07 of 1 May 2026.

10 Risk Factors

• Item 1A of the FY2025 Form 10-K holds 43 risk factors against 44 in FY2024: 6 were added, incl. AI use in company processes and the risk that data center and AI demand grows more slowly than expected; 7 were removed, incl. six on the Calpine merger process after closing; 12 were materially reworded. The Forms 10-Q for Q1 to Q3 2026 report no change.

How risk factors changed

• Comparison: 10-K FY2025 filed 24 Feb 2026 acc 0001868275-26-000032 against 10-K FY2024 filed 18 Feb 2025 acc 0001868275-25-000023.
• AI appears in 4 risk factors (13 mentions) in the FY2025 10-K against 1 factor (1 mention) a year earlier, incl. a new standalone factor on AI use in operations.
• Data centers appear in 3 factors against 1, incl. a new factor that data economy demand may not grow at the pace the market expects.
• Six merger process factors were removed after the Calpine deal closed on 7 Jan 2026, while three Calpine specific operating factors were added (DOE awards, Geysers geothermal, earthquake and wildfire exposure inside the disasters factor).
• Geothermal is named in 4 factors against 1, and the standalone climate change factor was folded into a weather factor that more than doubled in length (197 to 428 words).
• Market design risk widened: the price volatility factor grew 44% in words and the regulation factor adds Federal Power Act 202(c) emergency orders and large load supply mandates.

11 Stock Price, Scenarios & Sensitivity

• CEG last traded at $274.32 on 10 Nov 2026, 27.8% below the 52 week high of $379.69 and 20.0% above the low of $228.63. Monthly closes start in 2022, after the separation from Exelon.
• Valuation on adjusted operating EPS: 21.7x TTM adjusted operating EPS of $12.65 (non GAAP) and 21.7x the FY2026 guidance midpoint of $12.65; 22.1x TTM GAAP diluted EPS of $12.44. Market value $96.5bn on 351.6m shares (31 Oct 2026); enterprise value $119.2bn with net debt of $22.8bn; dividend yield 0.62%.
• Scenario model: revenue grows from TTM Q3 2026 $34.3bn for three years; operating margin as stated; interest of $0.87bn a year deducted; 25% tax; shares fall with buybacks. Year three EPS from this model is read as adjusted operating EPS, and the exit P/E is applied on that basis. The model does not separate RNF, hedge marks or the PJM asset sale. Growth, margin, exit P/E and share count are assumptions of this report; the three scenario prices follow from them and are not company guidance.

Critical factors and core assumptions

• Base year TTM Q3 2026: revenue $34.3bn, operating income $6.0bn (17.5% margin), adjusted operating EPS $12.65; Calpine included for three of four quarters.
• Best case: 8% revenue CAGR, 24% operating margin, 25x P/E, share count (8%); Crane and uprates on schedule, more premium nuclear contracts and power prices above the tax credit phase out.
• Base case: 4% revenue CAGR, 20% margin, 21x P/E, share count (5%); signed PPAs (Microsoft, Meta, Amazon, Google) phase in from 2027 to 2032, capacity prices near the collar and the PJM asset sale closes.
• Worst case: (3%) revenue CAGR, 13% margin, 15x P/E, share count (2%); power prices fall toward the tax credit floor, PJM reforms cap capacity value, delays at Crane or the uprates and narrower gas spark spreads.
• Fixed inputs: 25% tax rate against 26.8% TTM; interest of $0.87bn a year; nuclear capacity factor about 94%; nuclear tax credit in place through 2032.

Scenarios, three years forward

Sensitivity analysis

Disclaimer

This analysis is for information only and is not financial advice. It is derived from public SEC filings retrieved via sec-api.io and is not a publication of the U.S. Securities and Exchange Commission. Scenario values are model outputs under stated assumptions and are not forecasts. Data as of 10 November 2026.

Sources

All company figures are read from SEC filings retrieved through the sec-api.io MCP server, under central index keys 1868275 (Constellation Energy Corporation) and 1168165 (Constellation Energy Generation, LLC). Peer figures come from the Forms 10-K, 10-Q and 8-K of Vistra, NRG Energy, Talen Energy, Public Service Enterprise Group and NextEra Energy. Share prices are monthly closes and the last trade of 10 Nov 2026.