Published
# Constellation Energy Corporation (CEG) — Narrative Baltimore-headquartered owner-operator of electric generation and a competitive retail energy supplier. Sources: the annual report on Form 10-K for the fiscal year ended December 31, 2025 (accession 0001868275-26-000032); the quarterly report on Form 10-Q for the quarter ended June 30, 2026 (accession 0001868275-26-000104); and current reports on Form 8-K filed during 2026, cited individually below. --- ## Business *From the FY2025 Form 10-K, accession 0001868275-26-000032, and updated for the completed Calpine merger as described in the Form 10-Q, accession 0001868275-26-000104.* Constellation generates electricity and sells electricity, natural gas and related energy products and services to wholesale and retail customers across the United States. It makes money in two linked ways: it runs a large owned generation fleet — nuclear first, then natural gas, geothermal, hydro, wind and solar — and it sells the output, plus power it buys in the market, to distribution utilities, municipalities, cooperatives and commercial, industrial, public-sector and residential end users. The gap between what it costs to produce or procure energy and what customers contract to pay for it is the business. Following the January 2026 acquisition of Calpine Corporation, the company describes itself as the largest private-sector power producer in the world and the largest U.S. producer of clean energy, with roughly 55 GW of capacity, output equivalent to powering about 27 million homes, and roughly 10% of the nation's clean energy. It is the largest nuclear operator in the United States and a leading competitive retail supplier, serving approximately 2.5 million customer accounts nationwide, including 80% of the Fortune 100. **The fleet as reported at December 31, 2025 (before Calpine).** Owned generating resources totaled 31,676 MW, plus 4,798 MW of contracted generation procured under unit-specific agreements. Within that: approximately 22 GW of nuclear, which produced 183 TWh in 2025; roughly 7 GW of natural gas and oil; and roughly 2.6 GW of hydroelectric, wind and solar. Nuclear supplied 68% of total electric supply in 2025 (67% in 2024, 65% in 2023), gas and oil 6%, renewables 2%. The company holds interests in 14 nuclear generating stations comprising 25 units, wholly owned except for undivided interests in Quad Cities (75%), Peach Bottom (50%), Salem (42.59%), Nine Mile Point Unit 2 (82%) and South Texas Project (44%). Salem and STP are operated by others. **Segments.** Through fiscal 2025 the company reported five segments organized by geography: Mid-Atlantic (10,386 MW, 33% of net generation capacity), Midwest (11,606 MW, 37%), New York (3,093 MW, 10%), ERCOT (4,742 MW, 15%) and Other Power Regions (1,849 MW, 5%). Beginning in 2026 a sixth reportable segment, Calpine, was added. Natural gas sales and other activities not significant to results are reported under "Other" and not allocated to a segment. **What Calpine added.** After divestitures required for regulatory approval, the merger added approximately 23 GW across 72 generation and battery storage assets, concentrated in Texas, California and the Northeast. Calpine is the largest U.S. generator of electricity from natural gas and geothermal resources: 21 GW of gas-fired generation, predominantly combined-cycle; the Geysers Assets — 13 operating geothermal plants in Northern California with roughly 730 MW of capacity, the largest geothermal portfolio in the U.S.; and roughly 800 MW of battery storage, largely in California. Calpine's retail platform adds approximately 62 TWh of annual load and roughly 2,500 employees. **Customer-facing business.** Constellation is active in all domestic wholesale power and gas markets across the lower 48 states. In 2025 it served approximately 204 TWh through retail sales and wholesale load auctions, of which roughly 147 TWh was retail electric load (primarily commercial and industrial) and roughly 57 TWh was wholesale load across competitive utility procurement and bilateral sales to municipalities and cooperatives. It also served approximately 800 Bcf of gas in 2025. Renewal rates in 2025 were 77% for C&I power customers and 84% for C&I gas customers; average C&I power contract terms run about two years with customer duration of about six years. The company reports over 32% share of the direct C&I market. Product lines include the CORe+ renewable-matching product, Hourly Carbon-Free Energy, energy-efficiency offerings, the Constellation Navigator analytics platform, and Constellation Technology Ventures, its venture investing arm. **Long-term contracting with technology customers.** A 20-year PPA with Microsoft supports the restart of Three Mile Island Unit 1, renamed the Crane Clean Energy Center, retired in 2019 for economic reasons and expected to provide roughly 835 MW of emissions-free capacity. In November 2025 the DOE Office of Energy Dominance Financing issued a guarantee for up to $1.0 billion for an unsecured loan from the Federal Financing Bank to support the restart; the loan matures in 2055 and prices at 37.5 basis points over comparable-maturity Treasuries at each advance. In June 2025 the company signed a 20-year PPA with Meta Platforms for the output of the Clinton Clean Energy Center, beginning June 2027, which supports relicensing and expands Clinton's output by 30 MW through uprates expected to be complete in 2029. **Hedging and price support.** Commodity price risk on the generation portfolio is managed with wholesale and retail load sales, federal and state programs, and derivative and non-derivative contracts. Portfolio hedging concentrates on the prompt three years. Since 2024 the existing nuclear fleet has been eligible for the nuclear production tax credit enacted in the Inflation Reduction Act and maintained under the One Big Beautiful Bill Act: a transferable credit of up to $15 per MWh that phases out as annual gross receipts rise between $26.00 and $44.75 per MWh (2025 and 2026 thresholds), with the credit rising as unit revenues fall. State programs — the New York Clean Energy Standard, the Illinois Zero Emission Standard, the Illinois Clean Energy Law's carbon mitigation credits — provide parallel support; the New Jersey program concluded in May 2025, and in January 2026 the New York Public Service Commission approved a 20-year extension of its ZEC program through 2049. **Regulation.** Subsidiaries that are public utilities under the Federal Power Act are subject to FERC's exclusive ratemaking jurisdiction over wholesale power sales and interstate transmission, including authority over market-based rates. Nuclear operations are licensed and continuously overseen by the NRC, which also requires demonstrated decommissioning funding assurance, met through dedicated nuclear decommissioning trust funds. All nuclear units were originally licensed for 40 years and have received 20-year renewals; Peach Bottom and Dresden have received subsequent renewals extending to 80-year terms. Hydroelectric licensing sits with FERC: a new 50-year Conowingo license issued in March 2021 was vacated in December 2022, and a September 2025 settlement with the Maryland Department of the Environment and two riverkeeper organizations cleared the way to resubmit the application. Spent nuclear fuel is stored on site — approximately 97,600 assemblies (23,900 tons) at December 31, 2025 — because no U.S. repository exists. As of December 31, 2025 approximately 23% of employees participated in collective bargaining agreements. --- ## Risk factors *From the FY2025 Form 10-K, accession 0001868275-26-000032.* The company groups its risks into market and financial, legislative/regulatory/legal, operational, and Calpine-merger categories. The substantive ones: **Commodity price and market design.** Earnings and cash flows are exposed to spot and forward price variability on the unhedged portion of the portfolio and on fuel. Spot power prices are generally set by the marginal fuel, usually natural gas. Supply markets for nuclear fuel, gas and oil are subject to price swings, availability restrictions, tariffs, counterparty default and geopolitical risk — nuclear fuel notably so, given sanctions arising from the Russia-Ukraine conflict and the Prohibiting Russian Uranium Imports Act. Oversupply during some hours can produce negative pricing and revenue loss for baseload plants. Market rules vary by region and can change with little notice; price caps, retirement-deferral orders, requirements that new large loads secure new generation, and policies favoring new resources over existing ones could force premature retirements. **Hedging and portfolio management.** Risk limits and procedures cannot eliminate trading risk, and estimates become less reliable the further out they extend. If the portfolio cannot cost-effectively meet contracted customer load, the shortfall must be purchased in wholesale markets. **Retail competition.** Barriers to entry can be low, and in periods of sustained low gas and power prices with low volatility, competitors pursue share aggressively. Retail competition also depends on continued host-state support, and legislative sessions repeatedly present opportunities for partial or full repeal. **Emerging technologies.** Distributed solar, storage, advanced nuclear, CCUS and advanced geothermal could raise clean baseload supply and depress prices, make parts of the fleet uneconomic before the end of their useful lives, and lower barriers to new entrants. **Trust and benefit-plan asset values.** Declines in nuclear decommissioning trust investments would raise decommissioning funding requirements; declines in pension and OPEB assets, or falling interest rates that inflate those liabilities, would raise contribution requirements. **Capital markets, ratings and collateral.** The company depends on public debt, bank and commercial paper markets. At December 31, 2025 approximately 26%, 8% and 13% of available credit facilities were with European, Canadian and Asian banks respectively. A downgrade below investment grade, or failure to satisfy counterparty credit standards or NRC financial requirements, would require posting significant collateral and raise borrowing costs. Project-specific financing defaults could result in lenders foreclosing on project assets. **Impairment.** Long-lived generation assets are the single largest asset class on the balance sheet, and the Calpine acquisition adds a significant goodwill balance. Changes in discount rates, energy prices, projected operating costs or cash flows could produce future impairments. **Contract expiration and counterparty credit.** A material portion of the portfolio is sold under PPAs that expire at various times; replacement pricing may be materially lower, and without PPAs some facilities may not operate profitably. Bilateral counterparties, retail customers, and RTO/ISO default-sharing mechanisms all create credit exposure. The company has issued indemnities to third parties, including several Exelon utilities, in connection with asset purchases and sales. **Nuclear-specific risks.** Capacity factors drive results directly — lower factors force higher-cost replacement generation or market purchases. Refueling outages are planned every 18 to 24 months; longer or unplanned outages compress margins. NRC rule or license changes could require large capital or operating outlays. The absence of a national spent-fuel repository affects storage costs and DOE reimbursement, and could impair the ability to fully decommission units. Under the Price-Anderson Act the company carries the maximum available nuclear liability insurance, $500 million per operating site, with excess claims covered through a mandatory industry pool; Congress could impose revenue-raising measures on the industry for claims exceeding the $16.3 billion single-incident limit. Actual decommissioning costs may substantially exceed estimates, and shortfalls in trust funding could require letters of credit, parent guarantees or additional cash contributions. **Calpine-specific risks.** The merger may not be accretive as anticipated and may dilute EPS; transaction and integration costs may exceed expectations; anticipated benefits may take longer or cost more to realize. Former Calpine stockholders held approximately 14% of outstanding shares immediately after closing (prior shareholders 86%), diluting existing holders' influence, and sales after lock-up expiration could pressure the share price. Geothermal resource productivity at the Geysers can decline unexpectedly and steam-field leases may not renew on favorable terms. DOE cost-share awards at five Calpine facilities for CCUS front-end engineering and geothermal drilling carry federal compliance, audit, suspension and debarment risk. Calpine's California and Western assets face earthquake and wildfire exposure, including public-safety power shutoffs. **Security and AI.** Physical and cyber threats to grid and information infrastructure are described as increasingly sophisticated; the company relies on third-party managed service providers and cloud hosting and is exposed to their incidents. The company states it has not experienced a material breach or disruption to date. The Calpine acquisition expands the attack surface and, by its visibility, is expected to draw additional attention from threat actors. Separately, internally developed or vendor AI systems may produce inaccurate or biased outputs, and the regulatory landscape for AI is unsettled. **Demand from the data economy.** Recent benefit from data-center and AI-driven demand may not persist: that demand is subject to technological change, shifts in customer behavior, regulatory developments and capital-investment cycles, and may not grow at the pace the market currently anticipates. **Crane restart execution.** The restart requires NRC safety and environmental review, a renewed operating license, state and local permits, and a FERC interconnection agreement. Failure to obtain approvals could impair capitalized amounts; missed contractual timelines could trigger significant penalties; cost overruns or interconnection delays could lower returns. --- ## Management's discussion — fiscal 2025 *From the FY2025 Form 10-K, accession 0001868275-26-000032. Results below exclude Calpine, which was acquired after the balance sheet date.* **Results.** Operating revenues were $25,533 million in 2025 against $23,568 million in 2024, up 8.3%. Total operating expenses rose to $22,447 million from $19,287 million, driven by purchased power and fuel of $14,681 million versus $11,419 million; operating and maintenance was flat at $6,159 million and depreciation and amortization fell to $985 million from $1,123 million. Operating income declined to $3,086 million from $4,352 million. Net income attributable to common shareholders was $2,319 million, or $7.40 per diluted share, down from $3,749 million and $11.89. Adjusted (non-GAAP) operating earnings, the company's preferred internal measure, moved the other way: $2,944 million, or $9.39 per share, against $2,735 million and $8.67. The effective tax rate rose to 33.8% from 17.1%, primarily because fewer non-taxable nuclear PTCs were generated and qualified decommissioning trust income was higher. **Why GAAP earnings fell $1,430 million.** Management attributes the decline to lower nuclear PTC revenues in 2025, unfavorable net unrealized losses on economic hedges, and higher net unrealized losses on equity investments — partly offset by favorable market and portfolio conditions driven by higher capacity revenues and generation-to-load optimization, favorable net ZEC revenues including revenue recognized for Illinois ZECs delivered in prior planning years, and favorable realized and unrealized decommissioning trust investment activity. The PTC mechanics explain much of the swing in both directions: because the credit phases out as gross receipts rise, higher energy and capacity prices in 2025 both lifted market revenue and removed PTC revenue. By segment, Mid-Atlantic lost $515 million of nuclear PTC revenue and Midwest $1,090 million of PTC revenue plus $210 million of net carbon mitigation credit revenue, in each case because energy and capacity prices rose. **Segment revenues (2025 vs. 2024).** Mid-Atlantic $6,487 million vs. $5,522 million (+17.5%); Midwest $5,804 million vs. $4,805 million (+20.8%); New York $2,190 million vs. $2,050 million (+6.8%); ERCOT $1,904 million vs. $1,550 million (+22.8%); Other Power Regions $5,583 million vs. $5,506 million (+1.4%). Reportable segment electric revenues totaled $21,968 million against $19,433 million. "Other" contributed $4,370 million versus $3,819 million, helped by $410 million of favorable retail gas revenue on higher gas prices and $160 million of favorable United Kingdom revenue. Unrealized hedging results swung to a $805 million loss from a $316 million gain. **Operations.** Nuclear capacity factor was 94.7% in 2025 (94.6% in 2024, 94.4% in 2023), roughly four percentage points above the industry average every year since 2013. Average refueling outage duration was 22 days in 2025 against industry averages in the 30s. Dispatch Match on the gas and oil fleet was 97.9%; Renewable Energy Capture was 96.6%. Owned electric supply was 204,944 GWh in 2025 versus 208,434 GWh in 2024; purchased power from spot and bilateral markets was 63,999 GWh versus 60,983 GWh. In Other Power Regions, purchased power expense rose $1,330 million largely because the retirement of Mystic Units 8 and 9 cut generation volumes, partly offset by $835 million of favorable realized hedges. **Cash flow and capital.** Operating activities provided $4,237 million in 2025 against a $2,464 million use in 2024 — a swing driven largely by a December 2024 amendment to the accounts receivable facility, after which receivable collections run through operating rather than investing activities; the improvement was partly offset by higher collateral postings. Investing used $3,198 million, versus $7,428 million provided in 2024 (the same receivables-facility mechanic in reverse). Financing used $420 million versus $2,289 million. At December 31, 2025 the capital structure was 7% commercial paper and notes payable, 31% long-term debt and 62% member's equity, with access to facilities carrying $9.5 billion of aggregate bank commitments. A loss of investment-grade ratings at that date would have required approximately $2.7 billion of incremental collateral and would have taken a three-notch downgrade by S&P or Moody's. During 2025 the revolving credit facility was upsized from $4.5 billion to $7.0 billion, with the incremental $2.5 billion available on closing of the Calpine acquisition. Estimated capital expenditures, inclusive of Calpine, were approximately $5.7 billion for 2026 and $4.7 billion for 2027, roughly 29% of it nuclear fuel. **Critical estimates.** The nuclear decommissioning asset retirement obligation was $12.9 billion at December 31, 2025, built from unit-by-unit cost studies refreshed at least every five years, annually updated escalation factors, and probability-weighted scenarios across DECON, Shortened SAFSTOR and SAFSTOR approaches and four shutdown-timing alternatives. DOE acceptance of spent fuel is assumed to begin in 2040. Discounting all future nominal ARO cash flows at the current prevailing credit-adjusted risk-free rate would reduce the obligation from approximately $12.9 billion to approximately $11.3 billion. The 2025 annual goodwill assessments indicated no impairments. **Policy and market drivers entering 2026.** In December 2025 FERC found PJM's tariff unjust and unreasonable for lacking clarity on service to co-located load, found the existing behind-the-meter netting rules no longer just and reasonable with limited exceptions, and directed PJM to make three new transmission services available to co-located loads. In January 2026 the National Energy Dominance Council, supported by PJM- state governors, urged PJM to file tariff revisions addressing capacity-auction reliability and pricing. The One Big Beautiful Bill Act, signed in July 2025, preserved IRA credits benefiting the nuclear fleet, CCUS commercialization and geothermal investment. In Texas, project selections under the Texas Energy Fund announced in fall 2025 included a $278 million loan for Calpine's 460 MW Pin Oak Creek peaking facility; in Maryland, the Public Service Commission approved an application to advance more than 700 MW of natural gas generation under the Next Generation Energy Act's expedited pathway. --- ## Current quarter — second quarter and first half of 2026 *From the Form 10-Q for the quarter ended June 30, 2026, accession 0001868275-26-000104, and the second-quarter earnings materials furnished on Form 8-K, accession 0001868275-26-000097.* **The Calpine acquisition is the dominant fact of the period.** On January 7, 2026 the company acquired all outstanding equity of Calpine for a purchase price of approximately $21.8 billion — 50 million newly issued shares plus approximately $4.5 billion of cash on hand. (The FY2025 Form 10-K, filed before purchase accounting was finalized, described the price as approximately $22 billion.) Total merger consideration was recorded at $21,835 million: $17,603 million of stock, valued using the $354.58 closing price on January 6, 2026, plus $4,342 million of cash, net of $96 million of stock subject to a vesting period and $14 million for settlement of preexisting relationships. Against $32,788 million of assets acquired and $22,060 million of liabilities assumed — including $12,551 million of long-term debt and $5,603 million of assets held for sale — the transaction produced $10,728 million of net identifiable assets and $11,107 million of goodwill. Purchase accounting may still be adjusted through January 2027. Calpine is reported as a sixth segment. The Calpine segment recorded $2,147 million of operating revenues in the second quarter and $4,541 million in the first half. The 10-Q's acquisition note separately reports operating revenues attributable to Calpine following the acquisition date — a different measure, and a different amount, from the segment figures above. **Results.** Second-quarter operating revenues were $7,504 million against $6,101 million a year earlier, up 23.0%; first-half revenues were $18,626 million against $12,889 million, up 44.5%. Second-quarter operating income fell to $580 million from $951 million, while first-half operating income rose to $2,912 million from $1,402 million. GAAP net income attributable to common shareholders was $513 million, or $1.42 per diluted share, against $839 million and $2.67 in the second quarter of 2025 — a $326 million decline. For the six months, GAAP net income was $2,103 million, or $5.88 per share, against $957 million and $3.05, a $1,146 million improvement. Adjusted (non-GAAP) operating earnings rose in both periods: $920 million, or $2.55 per share, for the quarter against $599 million and $1.91; and $1,893 million, or $5.30 per share, for the half against $1,272 million and $4.05. Diluted share count averaged 360 million in the quarter against 314 million a year earlier. Management attributes the quarterly GAAP decline to unfavorable net unrealized losses on economic hedges, Calpine merger and integration costs, and unfavorable nuclear outage impacts, partly offset by favorable net market and portfolio conditions driven by higher capacity revenues (offset by lower carbon mitigation credit revenue) and the addition of Calpine's operations including purchase-accounting effects. The half-year improvement is attributed to Calpine, market and portfolio conditions, favorable decommissioning-related activity driven by a first-quarter 2026 nuclear ARO update, and a smaller unrealized loss on equity investments, against the same two offsets. Two of the reconciling items are merger-driven: amortization of acquired commodity contracts recorded at fair value, new this year, added back $149 million in the quarter and $303 million in the half, and Calpine merger and integration costs of $84 million and $204 million, sharply higher than the $9 million and $22 million in the same periods of 2025. Depreciation and amortization rose $189 million in the quarter and $384 million in the half, and net interest expense rose $165 million and $272 million, both principally from assumed Calpine debt and related financing. The effective tax rate was 44.2% for the quarter against 34.6%, higher because of greater qualified decommissioning trust income taxed at a higher rate; for the half it was 30.7% against 32.4%. **Operations.** Nuclear generation was 44,160 GWh in the quarter against 45,170 GWh, and 88,827 GWh in the half against 90,753 GWh. Excluding Salem and STP, the nuclear capacity factor was 93.0% against 94.8%, reflecting 86 planned refueling outage days in the quarter versus 41 a year earlier, and 20 non-refueling outage days versus 22. Average refueling outage duration in the quarter was 23 days. Equivalent forced outage factor for the gas, oil and pumped-storage hydro fleet — a metric adopted in 2026 because of the expanded fleet — was 6.2%. Renewable energy capture was 96.0% against 96.1%. **Guidance.** The company raised its full-year 2026 adjusted (non-GAAP) operating earnings guidance range to $11.50–$12.50 per share, from an initial $11.00–$12.00, based on expected average diluted shares of 357 million. Management cites commercial outperformance through higher realized customer margins and portfolio optimization, plus accretive share repurchases, partly offset by higher operating and maintenance expense from performance-related compensation. The company has not reconciled the guidance to GAAP net income, citing the unpredictability of fair-value adjustments on derivatives and decommissioning trust securities. **Liquidity and capital allocation.** Operating activities provided $1,553 million in the first half against $1,584 million a year earlier — first-half 2026 operating cash includes refunds to state programs associated with nuclear PTCs. Investing used $5,101 million against $1,758 million, reflecting cash paid net of cash acquired for Calpine and higher capital expenditures for the Crane restart, Calpine, and co-location infrastructure. Financing provided $877 million against a $893 million use. The company issued $2.75 billion of senior unsecured notes in January 2026 to pay down assumed Calpine debt and $2.2 billion in May 2026 to repay short-term borrowings and for general corporate purposes; it also exchanged $2,290 million of Calpine senior notes for Constellation senior notes. At June 30, 2026 it had access to facilities with $14.5 billion of aggregate bank commitments; senior unsecured ratings were BBB+ from S&P and Baa1 from Moody's, and a loss of investment grade would have required approximately $3.4 billion of incremental collateral. During 2026 the board approved a $4.4 billion increase to the share repurchase program on top of a remaining $0.6 billion authorization; approximately $2.8 billion remained as of the filing date. Roughly 7.1 million shares were repurchased in the first half for approximately $2.0 billion, including open-market purchases and a June secondary offering. In that offering, selling shareholders — former Calpine holders whose lock-up was waived for the purpose — sold 11,000,000 shares; the company itself bought 2,000,000 of those shares for approximately $558.0 million and neither sold shares nor received proceeds (Form 8-K, accession 0001104659-26-069482). Quarterly dividends of $0.4265 per share were declared for each of the first three quarters of 2026. **Divestitures required by the merger.** The final regulatory clearance for the merger was the DOJ resolution, which requires divestiture of five generating assets in PJM, one in ERCOT, and Calpine's minority interest in the Gregory Power Plant, with definitive agreements to be entered within 240 days of closing — by September 4, 2026. The Gregory interest was divested in January 2026. In March 2026 the company agreed to sell five predominantly gas-fired assets in Delaware and Pennsylvania totaling approximately 4.4 GW to LS Power Equity Advisors, LLC for aggregate consideration of $5.0 billion before closing adjustments. **Growth and commercial activity in the period.** The company signed an additional 920 MW of long-term nuclear PPAs with investment-grade customers, 15 to 20 years in duration and beginning between 2029 and 2032, including a 176 MW agreement with Walmart that enables a 30 MW uprate at the Dresden Clean Energy Center. In the first quarter it signed a 380 MW agreement with CyrusOne to connect and serve a data center adjacent to the Freestone Energy Center in Texas, with an exclusive agreement for a further 380 MW in Phase 2, adding to 400 MW of prior Calpine-CyrusOne agreements at the Thad Hill Energy Center. The 105 MW Pastoria Solar Project was commissioned in April 2026, and the 460 MW Pin Oak Creek Energy Center reached commercial operation in April 2026 in ERCOT. **PJM.** In February 2026 PJM filed tariff revisions extending the capacity market price collar — a cap of approximately $325/MW-day and a floor of approximately $175/MW-day — for the 2028/2029 and 2029/2030 Base Residual Auctions, which FERC accepted in April 2026. In June 2026 FERC ruled on issues from the co-location paper hearing and several PJM compliance filings, pressing PJM to accommodate co-located load before its proposed June 2029 effective date. FERC also directed RTO filings intended to speed service to large loads; Constellation's Load Dependent Capacity at Existing Plants proposal was flagged in several orders for consideration. --- ## Subsequent events *Events after June 30, 2026. The Form 10-Q for the quarter (accession 0001868275-26-000104) does not carry a separate subsequent-events note; the items below are drawn from its Note 2, Note 15, Note 16 and management's discussion, and from current reports on Form 8-K as cited.* - **Brazos Valley Energy Center divestiture agreed (August 2026).** The company entered into an agreement with LS Power to divest the Brazos Valley Energy Center, formerly the Jack A. Fusco Energy Center, a 606 MW natural gas-fired plant in ERCOT, for **$860 million before closing adjustments**. This is the last asset sale required to satisfy the regulatory commitments under the Calpine acquisition. Closing is subject to DOJ approval and other customary conditions, and is expected by the end of 2026. Together with the $5.0 billion PJM sale agreed in March, total gross proceeds for the required divestitures are approximately $5.9 billion. The Brazos Valley plant is currently secured under a project financing arrangement. (Form 10-Q, accession 0001868275-26-000104; Form 8-K, accession 0001868275-26-000097.) - **PJM 2028/2029 capacity auction cleared at the cap (July 14, 2026).** Every Constellation plant in PJM cleared. Cleared volumes at ownership, excluding assets held for sale, totaled 18,875 MW — 15,700 MW nuclear and 3,175 MW fossil and other — all at the Capacity Performance price of **$325 per MW-day**, effective June 1, 2028. By zone: ComEd 10,200 MW, EMAAC 6,550 MW, MAAC 1,725 MW, BGE 375 MW and RTO 25 MW. Capacity revenue for nuclear units counts toward the gross receipts calculation for the production tax credit. (Form 8-K, accession 0001868275-26-000080.) - **Crane Clean Energy Center regulatory milestones.** FERC granted a waiver permitting the transfer of existing Capacity Interconnection Rights from the dual-fuel Eddystone Units 3 and 4 in Pennsylvania to Crane, and the NRC approved a fuel license amendment request for the site. The company describes these as clearing critical hurdles toward restarting operations in 2027. (Form 8-K, accession 0001868275-26-000097.) - **License renewal applications for two New York nuclear units.** The company filed applications with the NRC to extend operation of the Ginna Clean Energy Center and Nine Mile Point Unit 1 by 20 years, to 2049. Nine Mile Point Unit 2 is currently licensed to 2046. (Form 8-K, accession 0001868275-26-000097.) - **Pastoria Power Bank online (July 2026).** The 80 MW / 320 MWh battery energy storage system co-located with the Pastoria Solar Project came online, contracted under a 15-year power purchase agreement with Pacific Gas and Electric Company. (Form 10-Q, accession 0001868275-26-000104.) - **Winter Storm Uri litigation (July 2026).** The Supreme Court of Texas denied plaintiffs' motions for rehearing in the five bellwether appeals, following its March 2026 denial of their mandamus petitions. The parties return to the multi-district litigation court to effect dismissal of all remaining Uri tort claims. (Form 10-Q, accession 0001868275-26-000104.) - **Further share repurchases (July 2026).** The company repurchased approximately one million additional shares for approximately **$250 million**. (Form 10-Q, accession 0001868275-26-000104.) - **Board changes (August 4–5, 2026).** Robert Lawless retired from the Board on August 4, 2026, ending his service as its Chair, and the board elected President and Chief Executive Officer Joseph Dominguez as Chair effective the same day. The board also elected Roger Crandall as a director effective August 5, 2026, to serve until the 2027 annual meeting. (Form 8-K, accession 0001868275-26-000089.) - **Third-quarter dividend declared (August 4, 2026).** $0.4265 per share, payable September 4, 2026 to shareholders of record on August 18, 2026. (Form 10-Q, accession 0001868275-26-000104.) - **Full-year 2026 guidance raised (August 6, 2026).** Adjusted (non-GAAP) operating earnings guidance was raised to $11.50–$12.50 per share from $11.00–$12.00. (Form 8-K, accession 0001868275-26-000097.)