Constellation Energy Corp

PJM Market Reform

In January 2026, the National Energy Dominance Council, supported by governors in the PJM territory, urged PJM to propose certain tariff revisions with respect to its capacity auction. PJM subsequently initiated stakeholder discussions regarding potential market reforms, including a reliability backstop auction mechanism, enhancements to large load forecasting and measures to accelerate generator interconnection studies. In February 2026, PJM proposed extending the existing RPM capacity market price collar—approximately $325/MW‑day and $175/MW‑day—for the 2028/2029 and 2029/2030 Base Residual Auctions. FERC accepted the extension in April 2026, citing reliability concerns, significant demand growth, including from data centers, and anticipated market reforms.

In July 2026, PJM proposed a one-time reliability backstop procurement. In September 2026, FERC accepted the proposal and suspended it to become effective February 28, 2027, subject to refund and subject to the outcome of a paper hearing. FERC also encouraged PJM to re-file an updated proposal within 30 days rather than proceeding with the paper hearing. PJM submitted an updated auction filing on October 29, 2026 and proposed that the one-time procurement open March 1, 2027 and close on March 28, 2027, with results announced on May 10, 2027. Many of the proposed auction parameters are the same, with the exception that the load forecast that is used to clear the auction will not be finalized until April 28, 2027. Separately, in August 2026, PJM filed its Interim Resource Adequacy Service proposal, which would have imposed curtailment risk on new large loads over 50 MW coming online after June 1, 2027 that did not contract for new capacity. FERC largely rejected the proposal, finding that it improperly intruded on state jurisdiction over retail rates and that PJM had not established the lawfulness of certain provisions. PJM has indicated that they will make a subsequent filing, but no details are available at this time.

FERC Issues Order in PJM Show Cause Proceeding

In December 2025, FERC issued an order finding the existing PJM Tariff to be unjust and unreasonable and directing PJM to take a number of actions. FERC ordered three new transmission services: an interim interruptible network integration transmission service (IT NITS), which will allow load to take service on an interruptible basis while waiting for the network upgrades required for traditional NITS, and two other services. The IT NITS service allows the load to elect to connect promptly and receive some service from the grid, while avoiding PJM purchases of capacity to serve it, as it will be interruptible. The other services include a firm and non-firm contract demand service for co-located load. FERC also directed several PJM compliance filings and a paper hearing.

In June 2026, FERC ruled on a number of issues presented in the co-location paper hearing and on several PJM compliance filings implementing directives from the December 2025 order. Importantly, FERC pressed PJM to implement changes to accommodate co-located load prior to PJM’s proposed June 2029 effective date. In August 2026, PJM submitted its compliance filing and we are awaiting a FERC order on the filing.

FERC also issued a series of orders in the various RTOs in response to the Advance Notice of Proposed Rulemaking (ANOPR) published by DOE last fall. The orders direct filings by RTOs and their transmission owners that are designed to expedite service to large load (regardless of whether it is co-located) and avoid the expense and delay associated with network upgrades to provide service to these loads. Constellation’s Load Dependent Capacity at Existing Plants (LCEP) proposal, which would expedite connection of new generation when paired with a large load at an existing plant, was flagged in several RTO orders as a proposal to be considered.

Russia and Ukraine Conflict

We are closely monitoring developments of the ongoing Russia and Ukraine conflict, including United States, United Kingdom, European Union, and Canadian sanctions, and legislation that may impact exports and imports of Russian nuclear fuel supply and enrichment activities, as well as the potential for Russia to limit fuel deliveries. The U.S. “Prohibiting Russian Uranium Imports Act” became effective in August 2024, banning the import of low-enriched uranium into the U.S. that is produced in Russia or by Russian entities, absent a waiver from the DOE. Under a corollary bill, in 2026, the DOE began the process of distributing billions of dollars to support expansion of the domestic nuclear fuel cycle within the United States to improve emissions-free energy security. The

Lindsay O. Graham Sanctioning Russia and Iran Act of 2026 (Graham Act) that continued the uranium import waivers but appeared to increase difficulties for shipping fuel from Russia was signed in September 2026. In October 2026, the President issued an Executive Order that waived the application of all the sanctions, restrictions, and tariffs in the Graham Act. Our nuclear fuel is obtained predominantly through long-term uranium supply and service contracts. We work with a diverse set of domestic and international suppliers years in advance to procure our nuclear fuel to support our refueling needs and mitigate the risk of exposure to Russian nuclear fuel supply. Recognizing the potential for the continuing conflict to impact our longer-term security and cost of supply, we have entered into contracts to increase the size of our nuclear fuel inventory. Our fuel procurement activities comply with all U.S. and international trade laws and we continue to take advantage of all available avenues to maintain continuity in our nuclear fuel supply, including working with the U.S. Government and our diverse set of suppliers to secure the nuclear fuel needed to continue to operate our nuclear fleet long-term.

Environmental Regulation

California Assembly Bill 32, as amended by Senate Bill 32 in 2016, directed the California Air Resources Board (CARB) to adopt regulations to achieve the maximum technologically feasible and cost-effective reductions in GHG emissions, targeting statewide GHG emissions at 1990 levels by 2020 and to at least 40% below 1990 levels by 2030. The California Climate Crisis Act was enacted in 2022 and further establishes the state's policy to achieve net zero GHG emissions as soon as possible, but no later than 2045, and to reduce statewide anthropogenic GHG emissions to 85% below 1990 levels by 2045. To achieve these targets, CARB has promulgated complementary regulatory measures, including the Cap-and-Trade Program and Mandatory Greenhouse Gas Emissions Reporting Regulation. Covered entities, such as our power plants, must surrender compliance instruments, which include both allowances and offset credits, in an amount equivalent to their GHG emissions. Assembly Bill 398, enacted in 2017, authorized the extension of the Cap-and-Trade Program through 2030 and required several changes to the program, including establishing a price ceiling and other price mitigative mechanisms and limiting the amount of offsets allowed to comply with the regulation. In September 2025, California Governor Gavin Newsom signed AB 1207 and SB 840 into law, extending the state’s Cap-and-Trade Program through January 1, 2046, and renaming it the “Cap and Invest" Program.

In September 2021, Illinois Governor JB Pritzker signed into law the Climate and Equitable Jobs Act, which, among other things, establishes a schedule for eliminating CO 2 emissions by EGUs. Under that schedule, privately owned natural gas units that exceed an established level of NOx or SO 2 emissions and are located within three miles of an environmental justice community, or an equity investment-eligible community must permanently eliminate CO 2 and co-pollutant emissions by January 1, 2030, subject to certain reliability exceptions, such as a determination by PJM that the unit is needed for reliability. PJM made such a finding with respect to our natural gas generation facility, Zion Energy Center, acquired as part of Calpine, and accordingly Zion plans to operate past January 2030.

Regulation of GHGs from Power Plants under the Clean Air Act. In February 2026, EPA issued a final rule to repeal the 2009 Endangerment Finding underpinning all GHG regulation by EPA. In September 2026, EPA issued a final rule to repeal its 2024 GHG power plant standards, except for efficiency-based standards that apply to new gas power plants. With the repeal, new baseload gas plants will no longer face compliance obligations based on carbon capture and sequestration/storage beginning in 2032. Both the February 2026 and September 2026 rules have been challenged in the D.C. Circuit. EPA also issued a supplemental proposal in September 2026 to repeal its full suite of power plant GHG regulations, including the efficiency-based standards for new gas power plants, based on its reinterpretation of section 111 of the Clean Air Act. EPA recently accepted comments on the proposal. EPA's approach in the supplemental proposal, if finalized and upheld in court, would limit and/or delay options for future action on climate for the power sector by EPA.

See ITEM 1. BUSINESS, Environmental Matters and Regulation of our 2025 Form 10-K for additional information on environmental legislation and regulation we are subject to.