CEG Constellation Energy 10-Q 2026-09-30 section summaries

Constellation Energy (CEG) — Q3 and nine months ended September 30, 2026

Consolidated results

Revenue grew about 45% in both periods, with Calpine contributing materially. Financing and other non-operating items partly offset operating gains: Q3 other income (deductions) shifted to a $261M expense from $309M income; “Other, net” was a $44M expense versus $443M income. Nine-month net interest expense rose to $753M from $398M.

Segment results (Q3)

RNF—operating revenue less purchased power and fuel expense—is CEG’s primary segment measure reported to the CODM; it is a company-defined measure, not consolidated operating income.

Consolidated RNF rose 71.5% in Q3 and 60.0% for 9M, to $13.401B from $8.376B. Q3 capacity revenue increased to $496M from $104M, while power and power-related revenue was $5.797B from $5.249B. Derivative mark-to-market movements materially affected comparisons: Q3 unallocated operating-revenue losses of $362M were partly offset by $482M of purchased-power/fuel gains.

Cash flow, balance sheet and shares

Investing included $2.537B paid for Calpine, net of cash acquired. Financing included $3.001B of common-stock repurchases (versus $400M) and $459M of dividends (versus $365M). CEG repurchased 10.9M shares for $3.001B during 9M; approximately $2.0B remained under its repurchase authorization. Cash, restricted cash and equivalents fell to $1.009B from $3.748B at year-end.

Reported debt balances including short-term borrowings and current maturities totaled $23.387B, versus $8.992B at year-end. Common shares outstanding increased from 312.355M to 351.607M; Q3 average diluted shares were 354M versus 313M.

Acquisition, strategy and risks

CEG acquired Calpine on January 7 for $21.837B total consideration: $17.603B fair value of CEG shares and $4.342B cash. The acquisition added roughly 23 GW of generation and a retail platform serving about 62 TWh of annual load; it drove goodwill higher and substantially expanded assets and debt. CEG assumed approximately $12.6B of Calpine debt, repaid $2.5B of term loans shortly after closing and subsequently repaid additional notes. Acquisition-related employee awards excluded from consideration included $94M to be expensed over vesting periods. Purchase accounting remains provisional; Calpine goodwill is not expected to be tax deductible.

DOJ-required sales include Gregory (sold for $136M), Brazos Valley (sold in October for $860M; an approximately $250M Q4 gain expected), and five PJM assets totaling about 4.4 GW, agreed for sale for $5.0B subject to approvals. CEG also agreed to buy a 609-MW Rhode Island gas plant for $715M, subject to approvals and adjustments.

The Crane restart, supported by a 20-year Microsoft PPA, remains subject to NRC review, permits and transmission upgrades; some PJM upgrades extend to 2030. CEG reported $12.120B of fixed, determinable remaining performance obligations: $439M in 2026, $1.873B in 2027, $1.655B in 2028, $1.538B in 2029, $969M in 2030 and $5.646B thereafter.

Debt and collateral needs are significant. Credit-facility capacity was $14.482B, with $7.194B available. A three-notch downgrade below investment grade could trigger $3.649B of additional collateral, up from $2.670B; posted cash collateral was $2.306B versus $1.399B at year-end. Net derivative credit exposure after collateral was $2.109B, including $300M exposure to one investment-grade counterparty. CEG was covenant-compliant and had $1.5B of short-term unsecured borrowings outstanding.

Nuclear production tax credits provided no material benefit in 2026, while state-program pass-throughs reduced revenue by $280M in Q3 and $555M for 9M. A $1.030B refund or offset of prior program obligations reduced related payables to $155M from $1.190B at year-end. CEG also remitted $235M to former parent Exelon in a tax-attribute dispute and recorded a receivable, expecting repayment as Exelon uses the attributes.

Constellation Energy (CEG) — Q3 and nine months ended September 30, 2026

Results

Revenue rose about 45% in both periods, largely because the January 7, 2026 Calpine acquisition substantially expanded the business. Higher earnings reflected Calpine operations and purchase-accounting effects, favorable deferred-tax adjustments, and, year to date, higher capacity revenue and decommissioning-related benefits. Offsets included acquisition integration costs, higher interest expense, nuclear outages and lower nuclear production tax credit (PTC) revenue. The effective tax rate fell to 18.2% from 33.4% in Q3 and to 25.4% from 32.9% for 9M, primarily due to lower proportionate income from qualified nuclear decommissioning trust (NDT) funds and a long-term rate change.

Adjusted earnings are company-defined non-GAAP measures. Significant 2026 adjustments included Calpine merger and integration costs of $73 million in Q3 and $276 million for 9M, acquired commodity-contract amortization expense of $39 million and $342 million, and fair-value gains of $127 million and $508 million, respectively. Decommissioning-related activity was a $56 million Q3 expense but a $339 million 9M benefit.

Segment and other revenue

*9M values shown where year-to-date growth differed from Q3 growth by at least 3 percentage points. Calpine was acquired in January 2026; there is no comparable 2025 segment figure.

Midwest Q3 revenue benefited from higher energy and contracted retail prices, partly offset by lower nuclear PTC and clean-energy program revenues. Other Power Regions revenue declined with lower New England load and Western energy prices. Calpine-related commodity-contract amortization reduced Other revenue by $55 million in Q3 and $475 million for 9M. Nuclear PTC revenue fell to $44 million from $175 million in Q3 and to $69 million from $220 million for 9M; state-program PTC refunds/pass-throughs were net expenses of $280 million versus $220 million in Q3 and $555 million versus $30 million for 9M.

Operating performance and cash flow

Calpine drove much of the increase in total supply/sales. Higher 9M nuclear refueling outage days (205 versus 152) contributed to lower nuclear generation and capacity factor. Operating and maintenance expense increased $480 million in Q3 and $1.351 billion for 9M, reflecting additional Calpine operations, including higher labor, contracting and materials and merger costs. Depreciation and amortization rose $213 million and $597 million, mainly from acquired assets. Interest expense increased with debt assumed and acquisition financing. Q3 unrealized economic hedge gains were $482 million versus $25 million; 9M gains were $109 million versus $70 million, reducing reported purchased power and fuel expense.

For 9M, investing cash outflow was $6.064 billion versus $2.221 billion, chiefly due to the acquisition and higher investment in the Crane restart, Calpine, nuclear uprates and co-location infrastructure. Financing cash outflow was $1.654 billion versus $249 million, reflecting acquisition-related debt transactions and share repurchases. Cash, restricted cash and equivalents declined $2.739 billion, from $3.748 billion at the start of 2026 to $1.009 billion at September 30.

Business developments, financing and risks

CEG’s 55 GW generation fleet serves approximately 2.5 million retail customer accounts and supplies about 10% of U.S. clean energy. The $21.8 billion Calpine acquisition was funded with 50 million newly issued CEG shares and approximately $4.5 billion cash; Calpine added about 23 GW of generation capacity after related divestitures and a retail platform serving about 62 TWh of annual load. CEG agreed to sell five PJM gas plants totaling about 4.4 GW to LS Power for $5.0 billion before adjustments, subject to approvals. After quarter-end, it completed the sale of its 606 MW Brazos Valley plant for $860 million before adjustments and agreed to acquire the 609 MW Rhode Island State Energy Center for $715 million, subject to adjustments and approval.

CEG is pursuing growing data-center and other large-load demand with long-term nuclear supply and generation investments. Announced agreements include a 20-year, 690 MW Amazon PPA and retail agreement supporting more than $3 billion of Calvert Cliffs investment, and a 20-year Google PPA supporting more than $4.3 billion of investment and about 890 MW of incremental nuclear capacity. An additional 2,700 MW PJM financial load-following agreement with Google was also announced. These projects and planned uprates depend on approvals, construction, successful uprates and continued operation/relicensing. CEG also signed nuclear PPAs totaling 920 MW expected to begin in 2029–2032.

A conditional Department of Energy commitment would guarantee up to $5.0 billion for an unsecured Federal Financing Bank loan supporting nuclear uprates; the contemplated 30-year loan would bear a rate set at each advance at 0.375% above comparable-maturity U.S. Treasuries. At September 30, aggregate bank commitments were approximately $14.5 billion, with about $7.2 billion of available capacity and $0.6 billion cash on hand. Ratings were BBB+ at S&P and Baa1 at Moody’s. A three-notch downgrade could require approximately $3.6 billion of additional collateral, potentially exceeding available facilities and cash. CEG also assumed about $3 billion of projected Calpine financial-commitment cash payments, excluding debt service on debt largely refinanced or repaid.

PJM reforms and rapid load growth may affect capacity prices and large-load interconnection; FERC extended capacity-auction price collars and directed changes to accommodate co-located and other large loads, with timing and final rules uncertain. Other risks include volatile hedging and commodity prices, nuclear fuel supply and evolving restrictions involving Russian uranium, and changing environmental rules. NRC funding rules may require financial assurances or additional NDT contributions if decommissioning funds are inadequate. Crane’s NDT was fully funded under its planned SAFSTOR scenario; Zion had adequate funds for remaining radiological decommissioning of its spent-fuel installation, but other Zion decommissioning costs may require company funding.

Market risk, derivatives and liquidity

CEG hedges anticipated generation and load-serving exposures with physical and derivative contracts, generally focused on the prompt three years. Most economic hedges are expected to settle in 2026–2028. As of September 30, 2026, hypothetical decreases of $10/MWh in annual average around-the-clock energy prices and $5/MWh in around-the-clock spark spreads would have had an immaterial earnings impact in 2026 and 2027. The nuclear production tax credit, available to the existing fleet beginning in 2024, provides increasing support when unit revenues fall below statutory thresholds and is adjusted annually for inflation.

Commodity derivative positions

Net commodity derivative contract assets, net of collateral paid to and received from counterparties, rose substantially:

The increase included a $1.395 billion net fair-value gain recorded in results, $652 million reclassified to realized amounts at settlement, and $1.403 billion of contracts acquired with Calpine in January 2026. Offsetting items included $223 million of amortization of acquired contracts and a $43 million decrease in collateral. Other items were $36 million of net option premiums paid, $23 million of option-premium amortization, $15 million of upfront payments and amortizations, and $1 million of foreign-currency translation. The position excludes contracts designated as normal purchases and normal sales (NPNS).

At September 30, 2026, total commodity derivative fair value was $2.429 billion, net of $1.906 billion of collateral.

The large Level 3 component means model-based valuations are a significant feature of the reported derivative position.

Fuel supply and counterparty risks

Nuclear fuel is sourced predominantly through long-term contracts, including contracts involving Russian suppliers. Three suppliers provide approximately 35% of uranium concentrate requirements for the remainder of 2026 through 2031. CEG had not experienced supplier credit issues related to the Russia–Ukraine conflict, but sanctions or other geopolitical developments could disrupt deliveries across the international uranium-processing industry. Replacement uranium is believed available, potentially at unfavorable prices; supplier non-performance could materially adversely affect CEG.

Natural gas is procured through long- and short-term contracts and spot purchases, supported by transportation and storage arrangements intended to promote reliability and capture market-price opportunities. Fuel-oil inventories are managed for winter reliability and favorable-price purchasing.

Counterparty defaults on derivatives, bilateral output sales or within wholesale markets could cause losses. Downgrades—particularly below investment grade—may lead counterparties to demand adequate assurance or collateral. Market movements can require CEG to post collateral to purchasers, while counterparties may owe collateral to CEG when prices fall below contracted levels; CEG relies on bank credit facilities to fund collateral requirements. RTO/ISO rules may also require remaining participants to share losses from a member default, and a major member’s non-performance or non-payment could materially affect CEG. Exchange-cleared trades have comparatively limited counterparty credit risk because clearinghouses intermediate trades and require margin.

Interest-rate and investment exposure

CEG uses fixed- and variable-rate debt and may use interest-rate swaps. A hypothetical 50-basis-point change in rates on unhedged variable-rate long-term debt and swaps had no material earnings impact for the nine months ended September 30, 2026.

Nuclear decommissioning trust (NDT) assets are exposed to equity-price and fixed-income interest-rate changes. Holding other variables constant, a hypothetical 25-basis-point increase in interest rates together with a 10% decline in equity prices would have reduced NDT trust-asset fair value by $1.155 billion as of September 30, 2026.

Disclosure Controls and Internal Control

As of September 30, 2026, the CEO and CFO concluded that the company’s disclosure controls and procedures were effective. No changes in internal control over financial reporting during Q3 2026 materially affected, or were reasonably likely to materially affect, those controls. The filing cautions that controls have inherent limitations, including errors in judgment, mistakes, and the possibility of circumvention or collusion.

As of September 30, 2026, CEG reported no material changes to the risk factors described in its 2025 Form 10-K. Those risk factors include risks related to the Calpine acquisition and its operations. This section reports no new financial metrics or strategic developments.

During Q3 2026, the three months ended September 30, no director or executive officer adopted or terminated a Rule 10b5-1 trading plan or a non-Rule 10b5-1 trading arrangement.