Constellation Energy When-Issued (CEG) Jun 2026 Filing Analysis

FERC granted the requested waiver in June 2026, within the requested decision window. The transfer is intended to reduce the contingent transmission upgrades needed before Crane is fully deliverable. (1 met across 1 tracked commitment)

The filing confirms that portfolio hedging remains concentrated in the prompt three years and that most economic hedges are expected to settle during 2026–2028. It does not report that the majority have settled; the stated settlement window is ongoing. (1 in progress across 1 tracked commitment)

Management has signed an additional 920 MW of long-term nuclear power purchase agreements with investment-grade customers. — target: 920 MW of additional nuclear PPAs, each with a 15–20-year term, commencing between 2029 and 2032. (+1 more commitment)

The filing reports sharply higher capacity-market prices in several regions in FY2025, including Eastern Mid-Atlantic at $179.79/MW-day versus $51.89 and ComEd at $169.50 versus $31.09. It does not separately disclose annual capacity revenue, so this is evidence of a favorable pricing environment rather than a quantified revenue comparison to Q2 2026. (1 expanding across 1 engine)

Nine-month contract-customer revenue in the five regional electricity segments rose 14.9% year over year, from $14.672 billion to $16.614 billion. It represented about 85.4% of consolidated operating revenue in 2025, versus 80.7% in 2024. This regional total is a useful but not identical proxy for the later baseline’s broader power-and-power-related category. (5 expanding across 5 engines)

The filing reports combined Mid-Atlantic and Midwest regional revenue, not a separate PJM figure comparable with the baseline. Together, those regions generated $12,291 million in FY2025, up 19.0% from $10,327 million in FY2024; they accounted for about 48.1% of total operating revenue in FY2025 versus 43.8% in FY2024. The filing also says roughly 70% of generation resources are in PJM, but that is a capacity footprint measure, not revenue share. (1 expanding, 1 new)

Nuclear reliability improved modestly: the fleet capacity factor rose to 95.3% for the first nine months of 2025 from 94.6% in 2024. A high capacity factor means plants generated close to their potential output; this supports dependable, low-carbon supply, although it does not by itself establish lower costs. (4 expanding, 1 shifted)

The company added a long-term contracted-power example: a 20-year agreement with Meta for Clinton’s output, beginning in June 2027. The deal supports continued plant operation after Illinois’s ZEC program ends and includes a planned 30 MW uprate. This strengthens evidence of long-duration customer commitments, though delivery and uprate execution remain future-dependent. (1 expanding, 1 stable, 1 contracting)

The filing provides a firmer restart timeline and a substantial cost estimate: Crane is targeted for service in 2028, backed by a 20-year Microsoft contract, with approximately $1.6 billion of capital spending. Regulatory reviews and permits remain necessary; the filing does not quantify the grid-upgrade opportunity or report the later FERC waiver or DOE financing described in the earlier signal. (1 accelerating, 4 new trend across 5 signals, 2 leading indicators)

The supplied filing reports Constellation-wide revenue but does not give a Calpine-specific revenue update. The prior Q2 and first-half figures cannot be extended or compared using this filing. (1 new trend across 1 signal)

Capacity prices rose sharply year over year in the reported quarter: the Eastern Mid-Atlantic average was $125.71/MW-day, up 147.2%, and ComEd was $109.25/MW-day, up 237.3%. The six-month averages were also substantially higher than a year earlier, at $89.65/MW-day and $69.09/MW-day, respectively. This confirms a strong upward pricing environment, but the filing's quarterly figures do not establish a multi-quarter acceleration pattern. (3 accelerating, 2 reversing across 5 signals)

The filing does not report the previously described 920 MW of new nuclear contracts or the Walmart agreement. It does show that nuclear output increased 7.5% in the first half versus the same period in 2023, but this is generation performance, not evidence of new long-term customer contracts. (2 discontinued, 2 new trend, 1 accelerating across 5 signals)

This March-quarter filing predates the acquisition closing, so it provides no post-acquisition Calpine revenue result. It does confirm the proposed scale of the business: over 27 GW of generation and about 60 TWh of annual retail load. The deal remains a proposed, regulatory-conditioned expansion rather than realized growth in this quarter. (2 new trend, 1 steady across 3 signals)

At September 2025, the acquisition had not closed, so the company had not yet assumed Calpine’s approximately $12.7 billion of debt. Constellation had $7.387 billion of long-term debt, $1.650 billion of short-term borrowings and $4.0 billion of cash. The filing says the additional $2.5 billion of revolving credit commitments becomes available only after closing. The later baseline reports a sharp rise in debt after acquisition, so this risk worsened from the pre-close state to the later high-severity state. (5 intensifying, 2 high-severity)

In the nine months ended September 2025, operating cash flow was $3.432 billion versus capital expenditures of $1.963 billion, leaving positive cash flow before other investing and financing uses. Cash and equivalents were $4.091 billion, and the company paid $365 million in dividends and repurchased $400 million of stock. The later baseline reports that first-half 2026 operating cash flow fell below capital expenditures and cash declined substantially after the acquisition. On the available comparison, cash-generation pressure worsened materially after this earlier period. (4 intensifying, 1 high-severity)

The acquisition was still pending in Q3 2025: DOJ-related timing and customary closing conditions remained, and the transaction involved 50 million new shares, $4.5 billion cash and assumption of about $12.7 billion debt. The filing records $50 million of acquisition-related costs for the first nine months of 2025. The later baseline confirms that integration remains underway and reports materially higher integration costs and goodwill. This risk intensified from the pending-deal stage to a large, ongoing integration challenge. (3 intensifying, 1 stable, 1 high-severity)

In the older December 2025 filing, the restart was already dependent on NRC safety and environmental review, state and local permits, a renewed operating license, and interconnection construction. The filing also identifies potential penalties for missed contractual timelines and impairment risk if approvals fail. The later baseline still describes significant approval and grid-delivery exposure, so the risk remains material; the baseline's transfer of interconnection rights is a mitigation not reported in this filing. No comparable completion milestone or total project cost is provided here to quantify a change in severity. (1 stable, 1 easing, 1 high-severity)

Costs were already rising in Q3 2025: nine-month purchased power and fuel expense increased $2.255 billion, or 25.5%, year over year, while operating revenue rose 7.0%. The company attributed regional increases to higher energy and transmission costs, lower generation in some regions and higher capacity expense. The later baseline also reports higher supply and capacity costs in Mid-Atlantic and Midwest that were not fully offset by customer revenue, indicating the pressure persisted and became more pronounced. (5 intensifying)