Talen Energy Corp

Earnings in future periods are subject to various uncertainties and risks. See “Cautionary Note Regarding Forward-Looking Information,” the sections entitled “Item 1A. Risk Factors” in this Report and our 2024 Annual Report, as updated by our March 31, 2025 Quarterly Report, and Notes 2 and 9 to the Interim Financial Statements for additional information on our risks.

Commodity Markets

During the second quarter 2025, natural gas prices for Texas Eastern M-3 settled at the ten-year average as natural gas storage levels climbed above the five-year average. In PJM, above average temperatures during June contributed to increased load demand that resulted in higher settled on-peak power prices compared with the prior year.

The weighted average settled on-peak power prices and natural gas prices for the PJM market for the three months ended June 30, were:

The weighted average forward market prices for the periods from July 1 through December 31 as of June 30, were:

(a)Spark spreads are computed based on day-ahead PJM West Hub ATC prices, Texas Eastern M-3 natural gas prices, and a heat rate of 7 MMBtu/MWh.

Capacity Markets

Our generation facilities are located primarily in markets with capacity products, which are intended to ensure long-term grid reliability for customers by securing sufficient power supply resources to meet predicted future demand. Capacity prices are affected by supply and demand fundamentals, such as generation facility additions and retirements, capacity imports from and exports to adjacent markets, generation facility retrofit costs, non-performance risk premium penalties, demand response products, power demand forecasts, reserve margin targets and, in PJM, adjustments to the PJM Market Seller Offer Cap as determined by the PJM Independent Market Monitor.

PJM Capacity Auctions. Under the PJM Reliability Pricing Model, when held on schedule, the PJM BRA is required to be conducted in the month of May three years prior to the start of the applicable PJM Capacity Year in order for PJM to secure commitments from capacity resources. The results of each PJM BRA impact our capacity revenues expected to be earned for the specific PJM Capacity Year.

Recently, PJM has delayed its auctions, which has resulted in less than 3 years between each auction and the start of the relevant PJM Capacity Year. The PJM BRA for the 2026/2027 PJM Capacity Year was held on July 22, 2025. The capacity market construct provides generation owners some opportunity for revenue visibility on a multiyear basis and is intended to provide a price signal for new generation to be built in the future. See Note 9 to the Interim Financial Statements for additional information on the PJM capacity market, systemic risks, auction delays, and related legal actions.

Capacity Prices. The following table displays the cleared capacity prices for completed PJM BRAs for the markets and zones in which we primarily operate:

(a)Displayed prices are from the applicable market publications.

For the 2026/2027 PJM Capacity Year, the Company cleared 6,702 MWs at a price of $329.17/MWd for the MAAC, PPL, and PSEG locational deliverability areas.

Nuclear Production Tax Credit

The Inflation Reduction Act was signed into law in August 2022. Among the Act’s provisions are amendments to the Internal Revenue Code to create a nuclear production tax credit program. The Nuclear PTC program provides qualified nuclear power generation facilities with a transferable tax credit for electricity produced and sold to an unrelated party during each tax year. Electricity produced and sold by Susquehanna to third parties from December 31, 2023 through December 31, 2032 will be eligible for the credit. See Note 3 to the Interim Financial Statements for additional information on Nuclear PTC revenue recognized.

Seasonality/Scheduled Maintenance

The demand for and market prices of electricity and natural gas are affected considerably by weather and, as a result, our operating results may fluctuate significantly on a seasonal basis. In general, below-average temperatures in the winter and above-average temperatures in the summer tend to increase electricity demand, energy prices, and revenues. Alternatively, moderate temperatures tend to decrease electricity demand and may adversely affect resulting energy margins, particularly in PJM. In addition, our operating expenses typically fluctuate geographically on a seasonal basis, with peak power generation and expenses during the winter in the Mid-Atlantic. We ordinarily perform planned facility maintenance during milder non-peak demand periods in the spring and fall to ensure reliability during peak periods. The pattern of fluctuations in our operating results varies depending on the type and location of the facilities being serviced, the capacity markets served, the maintenance requirements of our facilities, and the terms of bilateral contracts to purchase or sell electricity. We serve our fossil generation fleet through a combination of self-service and contracted maintenance activity (including long-term service agreements at certain facilities). Our largest recurring maintenance project is the annual spring refueling outage at Susquehanna.

On March 25, 2025, Susquehanna commenced its planned refueling outage on Unit 2. During the outage, we identified incremental maintenance in the non-nuclear portion of the Unit. As a prudent operator, we elected to complete this scope of work while Unit 2 was already in outage and market prices and demand were relatively low. The outage was completed on June 4, 2025. The incremental maintenance investment during the extended outage was comprised of approxima tely $25 million in operations and maintenance expensesand $6 million of capital expenditures. We expect similar incremental maintenance activities on Unit 1 to be performed during Susquehanna’s Spring 2026 planned outage. While the scope of work and outage schedule has not yet been finalized, we expect our planning activities with respect to the Unit 1 incremental work to result in an outage of shorter duration than the Unit 2 outage as well as for the Unit 1 incremental maintenance costs to be in line with or below the Unit 2 costs.