Annual Report for the year ended December 31, 2024

Calpine Corporation

(A Delaware Corporation)

I.R.S. Employer Identification No. 77-0212977 717

Texas Avenue, Suite 1000, Houston, Texas 77002

Telephone: (713) 830-2000

CALPINE CORPORATION AND SUBSIDIARIES

ANNUAL REPORT

For the Year Ended December 31, 2024

TABLE OF CONTENTS

DEFINITIONS

As used in this report for the year ended December 31, 2024 (this “Report”), the following abbreviations and terms have the meanings as listed below. Additionally, the terms “Calpine,” “we,” “us,” “our,” and "the Company" refer to Calpine Corporation and its consolidated subsidiaries unless the context clearly indicates otherwise. The term “Calpine Corporation” refers only to Calpine Corporation and not to any of its subsidiaries. Unless and as otherwise stated, any references in this Report to any agreement means such agreement and all schedules, exhibits and attachments in each case as amended, restated, supplemented or otherwise modified to the date of the issuance of this Report.

FORWARD-LOOKING STATEMENTS

This Report includes forward-looking statements that reflect our current views with respect to, among other things, our operations and financial performance. Forward-looking statements include all statements that are not historical facts. These forward-looking statements are included throughout this Report, including, without limitation, the “Management’s Discussion and Analysis” section. We have used the words “anticipate,” “assume,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “future,” “will,” “seek,” “foreseeable,” “should,” the negative version of these words or similar terms and phrases to identify forward-looking statements.

The forward-looking statements contained in this Report are based on management’s current expectations and are not guarantees of future performance. The forward-looking statements are subject to various risks, uncertainties, assumptions, or changes in circumstances that are difficult to predict or quantify. Our expectations, beliefs and projections are expressed in good faith, and we believe there is a reasonable basis for them. However, there can be no assurance that management’s expectations, beliefs and projections will result or be achieved. Actual results may differ materially from these expectations due to changes in global, regional, or local economic, business, competitive, market, regulatory and other factors, many of which are beyond our control. We believe that these factors include but are not limited to those described under the “Management’s Discussion and Analysis” section.

The statements we make regarding the following matters are forward-looking by their nature:

Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of the date of this Report. Factors or events that could cause our actual results to differ may emerge from time to time, and it is not possible for us to predict all of them. We may not actually achieve the plans, intentions or expectations disclosed in our forward-looking statements, and you should not place undue reliance on our forward-looking statements. We undertake no obligation to publicly update or review any forward-looking statement, whether because of new information, future developments, or otherwise, except as may be required by any applicable securities laws.

Where You Can Find Other Information

Our website is www.calpine.com. Information contained on our website is not part of this Report. Our historical SEC filings made prior to August 21, 2020, including exhibits filed therewith, are available directly on the SEC’s website at www.sec.gov. As of August 21, 2020, we ceased filing all reports with the SEC. All future financial reports will be posted on our website. In November 2024, we issued our 2023 sustainability report, which is posted on our website and highlights Calpine’s (“Calpine Corporation," "the Company” or “CALPINE CORP”) performance through an environmental, social and governance (“ESG”) perspective. The report content and disclosures were developed with consideration from the Global Reporting Initiative Standards and Sustainability Accounting Standards Board Standard for Electric Utilities and Power Generators.

PART I

Item 1. BUSINESS

Business and Strategy

Calpine is America’s largest generator of electricity from natural gas and geothermal resources, according to S&P Global Market Intelligence. We sell electricity and other related energy products to load-serving entities such as utilities and public power customers, end users such as commercial, industrial and residential customers and to state and regional wholesale market operators. We have a significant presence in the major competitive wholesale and retail power markets in California, Texas and the Northeast and Mid-Atlantic regions of the United States. We own and operate approximately 28 Gigawatts (“GW”) of power facilities, enough to power approximately 27 million homes, consisting of natural gas, geothermal, solar and battery storage assets.

Our business strategy is to deliver long-term value to our stockholders and customers by focusing on operational excellence and a disciplined capital allocation strategy.

Since our inception in 1984, we have led the way in helping America move towards cleaner electricity. We believe our continued investment in sustainable power generation technologies has positioned us as a leader in developing, constructing, owning and operating an environmentally responsible portfolio of flexible and reliable power plants. Data gathered by the EIA show that our Geysers Assets (“Geysers,” or “The Geysers”), located in northern California, represent the largest geothermal power generation portfolio in the United States (“U.S.”), as well as the largest single renewable energy asset in California. Our modern natural gas fleet serves as a key part of the backbone of the U.S. electrical grid, enabling the transition away from coal-fired generation and the growth of intermittent renewable resources while maintaining reliability. We have championed environmental progress in the power sector through our own investments and by supporting government rules and regulations related to air emissions and water use. We have remained committed to these founding principles while expanding our portfolio geographically across the United States and into new, low-emission generation technologies. With one of the largest gas-fired generation fleets in California, Texas, the Mid-Atlantic and New England, we have a significant presence in these markets, which provides us with operational and strategic benefits.

We are pursuing an “inside-out” growth strategy, starting with our people, our capabilities, our sites and our power plants. This strategy includes a major effort to organically grow our retail businesses, a modest expansion of our geothermal footprint at The Geysers, our large-scale energy storage development effort — initially in the West and with expectations to expand in the East and potentially most significantly an industry-leading effort to attempt to develop profitable CCS facilities at natural gas plants.

Our wholesale customers include utilities, municipalities, cooperatives, retail power providers, large industrial companies, power marketers and governmental entities. We manage our portfolio through a combination of long-term customer contracts, forward hedging transactions and spot market participation. Our customer focus and relationships enable mutually beneficial opportunities through customized contract structures. For example, we operate the largest cogeneration fleet in the United States. Our cogeneration fleet is composed of plants that offer not only power but also steam products to our customers. By offering both steam and power, we provide efficient and reliable thermal and power products that are highly customized for our wholesale industrial customers.

Proposed Merger

On January 10, 2025, the Company announced that it entered into an Agreement and Plan of Merger (the "Plan of Merger Agreement") with Constellation Energy Corporation ("Constellation") under which Constellation will acquire Calpine in a cash and stock transaction. See Part II, Item 7. Management Discussion and Analysis and Note 19 to the Consolidated Financial Statements for additional details relating to the Plan of Merger Agreement and 1A. Risk Factors for a discussion of the risks related to the Plan of Merger Agreement.

Reportable Segments

We operate four reportable segments based primarily on region. We assess our business on a regional basis due to the effects that the differing characteristics of these regions have on our financial performance, particularly concerning competition, regulation and other factors affecting supply and demand. Our four reportable segments are:

See Note 18, Segment and Significant Customer Information of the Consolidated Financial Statements, for a discussion of financial information by reportable segment and geographic area and significant customer information for the years ended December 31, 2024, 2023 and 2022.

Our Core Business Functions

We manage our platform through five core business functions: 1) power plant operational excellence; 2) wholesale hedging and optimization and a customer-focused origination effort; 3) new asset development efforts, including power plants, energy storage, and potential carbon capture for sequestration; 4) retail businesses that provide products directly to end customers; and 5) active external engagement with our communities, regulators and governments, including on behalf of our customers. Our business functions leverage relationships and knowledge from each business, employ skilled, cross-functional teams and benefit from our scale to drive development opportunities and make informed commercial decisions. Our ability to leverage the entire Calpine platform allows us to provide innovative and cross-functional solutions to customers. Calpine’s core competencies are complementary, providing the business with a value greater than the sum of each of its individual parts. Our scale and operational expertise across these five functions allow us to proactively pursue growth opportunities, placing us at a competitive advantage over companies only involved in a subset of these five functions.

Our Markets

Calpine operates across eight wholesale power markets in the United States and Canada. Approximately 87% of Calpine’s electrical generation, as measured by our capacity, is concentrated within CAISO, ERCOT, PJM and ISO-NE.

CAISO

CAISO covers customers primarily in California, managing the dispatch of installed capacity to 32 million customers. Approximately 7.2 GW, or 26% of our generation fleet as measured by net interest with peaking operates within CAISO as of December 31, 2024. Our portfolio within CAISO is 11% geothermal, 88% natural gas-fired, and 1% storage. Operating as a fully functioning ISO since 1998, CAISO is a competitive wholesale electricity market with day-ahead and real-time energy markets, ancillary services and congestion revenue rights. The CAISO also operates a real-time imbalance market across much of the West. Although CAISO does not operate a centralized capacity market, it does use mandatory resource requirements supported through bilateral contracts in its Resource Adequacy (“RA”) program.

California is pursuing ambitious climate and energy policies with the goal of transitioning away from carbon-emitting fuels and toward cleaner energy sources. These cleaner energy sources include solar, wind and geothermal. In 2022, Governor Gavin Newsom set benchmarks for the state to reach 90% carbon-free electricity, inclusive of post-combustion carbon capture gas units, by 2035 to keep pace with the state’s previously stated goal of reaching 100% by 2045. To grow the state’s renewable energy portfolio, the RPS required California utilities procure 33% of retail sales from renewable resources by 2020 and will require 60% come from renewable sources by 2030. The state’s aggressive energy transition agenda has come alongside operational challenges as it works through its transition. Rolling blackouts throughout the state forced California officials to delay the retirement of three gas-fired power plants in 2023, extending their lives through 2026. These delays allowed the state to retain essential gas-fired power to maintain grid reliability during extreme weather events like wildfires and heat waves.

ERCOT

ERCOT coordinates the movement of electricity to 27 million customers in Texas. Approximately 9.7 GW, or 35% of our generation fleet, as measured by net interest with peaking, operates within ERCOT as of December 31, 2024. Our portfolio in ERCOT is comprised entirely of natural gas generation. ERCOT is a competitive electricity market that manages approximately 90% of Texas’ load and an electric grid covering approximately 75% of the state. ERCOT oversees transactions associated with Texas’ competitive wholesale and retail power markets and does not operate a capacity market.

ERCOT has seen weather-related disruptions, including extreme cold weather of winter storms Uri in 2021. With electric demand and load forecasted to grow substantially in the coming years, ERCOT President and CEO Pablo Vegas unveiled a comprehensive strategy in April 2024, called the New Era of Planning, designed to ensure all areas of system planning, including generation, load interconnections and transmission development, can meet the state’s growing energy needs. In July 2024, State representatives announced their intent to double the Texas Energy Fund from $5 billion to $10 billion to incentivize the construction of new gas-fired power plants.

PJM

PJM serves a population of 65 million in all or parts of 13 states and the District of Columbia. Approximately 5.3 GW, or 19% of our generation fleet, as measured by net interest with peaking, operates within PJM as of December 31, 2024. Our portfolio within PJM is 86% gas-fired generation and 14% steam as of December 31, 2024. All of our gas-fired generation facilities in PJM are dual-fuel systems that can also run on oil. This enables our fleet to continue operating during periods when gas may be constrained, such as recent winter storms. PJM is a competitive wholesale electricity market that consists of a locationally based energy market, a forward capacity market and ancillary service markets.

PJM is the largest and one of the most advanced power markets in the United States, with a capacity market, intended to ensure the future availability of power supplies three years in advance.

PJM may see a significant retirement of coal in the future due to issues arising from aging assets, competitive gas-fired generation and environmental targets. To offset these retirements and prepare for growing electric demand in the region, the ISO is scheduled to increase renewables. However, a recent report from independent developers in PJM suggested that most new generation is unlikely to come online before 2030 due to barriers in the grid interconnection and transmission planning processes. Additionally, PJM has implemented winter readiness measures to bolster system reliability in reaction to recent extreme weather events like Winter Storm Elliott, which resulted in the temporary shutdown of more than 25% of PJM’s generation fleet and led to load shedding in four nearby states in territories outside of PJM’s footprint.

ISO-NE

ISO-NE manages installed capacity across six states — Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont. Approximately 2.0 GW, or 7% of our generation fleet, as measured by net interest with peaking, operates within ISO-NE as of December 31, 2024. ISO-NE is a competitive wholesale electricity market with broad authority over the day-day operation of the transmission system. ISO-NE operates a day-ahead and real-time wholesale energy market, a forward capacity market and an ancillary services market.

ISO-NE stated in March 2024 that the region’s grid would need up to $1 billion in annual transmission investments until 2050 to support the clean energy transition. Though NERC has forecasted the ISO’s reserve margin level to be approximately 13%, access to fuel can be uncertain during winter when the region’s pipelines run at or near capacity, according to ISO-NE.

Other Markets

Our other markets include SERC, WECC, IESO, MISO and NYISO. As measured by net interest with peaking, Approximately 13% of our generation fleet operates in these markets, with 4% in WECC, 4% in IESO, 3% in SERC, 1% in MISO and 1% in NYISO.

Power Plant Operational Excellence

As of December 31, 2024, our generation fleet had a generating capacity of 27,802 MW and produced 121 Terawatt-hours (“TWh”) of electricity in 2024. As of December 31, 2024, our fleet included 79 operational power plants and facilities, including the newly acquired Quail Run Energy Center. Additionally, our fleet includes four battery storage facilities in operation, where one battery storage facility has four of five phases operational, with the final phase scheduled for commercial operations during the first half of 2025. Our fleet provides dispatchable, intermittent and peak power generation. As of December 31, 2024, our leading generation and battery storage fleet operated in 18 states and Canada, with most of our generating capacity located in the ERCOT, CAISO and PJM. Further details on our generation and battery storage fleet are included below in the section titled “Item 1. Business — Description of our Operations — Table of Operating Power Plants and Projects Under Construction.”

Since Calpine’s inception in 1984, we have focused on excellence in operations, continuously working to meet or exceed our goals. Our employees’ expertise allows us to optimize the value and profitability of our electric facilities, enhance our retail brands, and prudently manage the risks inherent in our business. We consider the proactive management and continuous improvement of safety and health risks crucial to our long-term business success. As a result, Calpine’s world-class safety performance routinely ranks among the best in the industry based on lost-time incidents and total recordable incident rates, the primary indicators of industrial safety performance. Reinforcing our stringent safety principles, several of our power plants have earned Star worksite certification through the Voluntary Protection Programs administered by the U.S. Department of Labor’s Occupational Safety and Health Administration, and others are working toward earning this distinction.

Description of Our Operations

Natural Gas Fleet

Our natural gas-fired power plants primarily use four types of designs: 1,500 MW of simple cycle combustion turbines, or peakers, 17,632 MW of combined cycle combustion turbines, 5,697 MW of cogeneration power plants and a small portion from conventional natural gas/oil-fired boilers with steam turbines. As of December 31, 2024, we own and operate 60 natural gas-fired power plants, making us the owner of the largest natural gas fleet in the United States. Our natural gas portfolio has an average capacity-weighted age of approximately 20 years. The efficiency of natural gas-fired power plants is demonstrated by our 2024 Steam Adjusted Heat Rate of 7,411 Btu/KW, which results in a power conversion efficiency of approximately 46%. Simple cycle combustion turbines burn natural gas or fuel oil to spin an electric generator to produce power. A combined cycle unit combusts fuel like a simple cycle combustion turbine, and boiler, which captures the exhaust heat to create steam, which can then spin a steam turbine. Each of our power plants currently in operation can produce power for sale to a utility, another third-party end user, our retail customers, or an intermediary such as a marketing company. At 13 of our power plants, we also produce thermal energy (primarily steam and chilled water), which can be sold to industrial and commercial users. These cogeneration power plants are also called combined heat and power facilities or cogens.

Geothermal Fleet

At The Geysers, located in the Mayacamas Mountains in northern California, we use a natural, clean energy source, geothermal energy, which is heat from the Earth’s interior, to produce electricity. Calpine’s wholly owned subsidiary, GPC owns and operates our Geysers Assets. Our Geysers Assets include a 725 MW fleet of 13 operating power plants, including steam extraction and gathering assets in northern California. This facility is the world’s largest geothermal power plant complex, and in 2024, our Geysers Assets were responsible for approximately 31% of the country’s total generation of electricity from geothermal sources in the United States. Geothermal energy is classified as clean and renewable as it does not require burning fossil fuel to create electricity. Steam is produced below the Earth’s surface from reservoirs of hot water, both naturally occurring and injected. The steam is piped directly from the underground production wells to the power plants and used to spin turbines to generate power.

We inject water back into the steam reservoir, which extends the useful life of the resource and helps to maintain the output of our Geysers Assets. The water we inject primarily comes from water purchase agreements for reclaimed water and the condensate associated with the steam extracted to generate power. As a result of these recharge projects, MWh production has been relatively constant. We expect that, as a result of the water injection program, the reservoir at our Geysers Assets will be able to supply economic quantities of steam for the foreseeable future.

We lease the geothermal steam fields from which we extract steam for our Geysers Assets. We have leasehold mineral interests in 105 leases comprising approximately 29,000 acres of federal, state and private geothermal resource lands in The Geysers region of northern California. Our leases cover one contiguous area of property that comprises approximately 45 square miles in Sonoma and Lake County. The approximate breakout by volume of steam removed under the above leases for the year ended December 31, 2024, is as follows:

In general, our geothermal leases grant us the exclusive right to drill for, produce and sell geothermal resources from these properties and the right to use the surface for related purposes. Each lease requires the payment of annual rent and royalty payments. In general, lease royalty calculations are based upon its percentage of revenue as calculated by its steam generated relative to the total steam generated by our Geysers Assets as a whole.

Our geothermal leases are generally for initial terms varying from five to 20 years and for so long thereafter as geothermal resources are produced and sold. Most of our geothermal leases were signed more than 30 years ago and continue uninterrupted. Our federal leases typically span an initial ten-year period with renewal clauses for an additional 40 years for a maximum of 50 years. In 2024, four of our federal leases were renewed through 2064. Most of our other leases run through the economic life of our Geysers Assets and provide for renewals so long as geothermal resources are being produced or used, or are capable of being produced or used, in commercial quantities from the leased land or from land unitized with the leased land. Although we believe that we will be able to renew our leases through the economic life of our Geysers Assets on terms that are acceptable to us, it is possible that certain of our leases may not be renewed or may be renewed on less favorable terms.

Unlike other renewable resources, such as wind or solar, which depend on intermittent sources to generate power, geothermal power provides a consistent source of energy, as evidenced by our Geysers Assets’ availability of approximately 91% in 2024. Additionally, many growth projects and new capital expenditures at The Geysers may be eligible for investment tax credits, as provided within the IRA.

Other Technologies

We also have four MW of capacity from solar power generation technology at our Vineland Solar Energy Center in New Jersey and 105 MW of solar power generation under construction at our Pastoria Solar Energy Center. As of December 31, 2024, we have four battery storage projects in California that are fully operational representing 738 MW of capacity, and one facility in California (Pastoria) that is under construction, representing approximately 80 MW of capacity. Among the world's largest battery storage projects is our 680 MW Nova asset. The development is financed and fully contracted. The first four phases of the Nova power battery storage facility came online during the summer of 2024, with phase five expected to be operational in the first half of 2025. We also have 725 MW of conventional steam turbine technology at our Edge Moor Energy Center.

Table of Operating Power Plants, Battery Storage Facilities and Projects Under Construction

Set forth below is certain information regarding our operating power plants, battery storage facilities and projects under construction as of December 31, 2024.

Substantially, all the power plants and battery storage facilities in which we have an interest are located on sites we either own or lease long-term.

Wholesale Hedging, Optimization and Origination Efforts

Our commercial approach and platform allow us to enhance the value of individual power plants and our fleet as a whole. Our hedging program’s goal is to enhance profitability by making informed risk-adjusted decisions around power sales and fuel procurement. We have standing agreements in place that enable us to transact with an extensive number of customers and trading counterparties. This allows efficient access to markets and bilateral commercial opportunities. We also hold extensive natural gas transportation and storage agreements that allow us to source reliable and cost-effective fuel for our facilities and to benefit from fuel price variations across the United States. This participation in the markets yields market knowledge and perspectives that inform our hedging decisions. Starting and replicating a commercial platform of this scale and diversity would be a difficult and costly multi-year effort, if possible.

At any point, the relative quantity of our products hedged or sold under longer-term contracts is determined by the availability of forward product sales opportunities and our view of the attractiveness of the pricing available for forward sales. We have economically hedged a portion of our expected generation and natural gas portfolio as well as retail load supply obligations, where appropriate, primarily through power and natural gas forward physical and financial transactions, including retail power sales; however, we currently remain susceptible to significant price movements for 2025 and beyond. When we elect to enter into these transactions, we are able to economically hedge a portion of our Spark Spread at predetermined generation and price levels.

We have also historically used interest rate derivative instruments to adjust the mix between our fixed and variable rate debt. To the extent eligible, our interest rate derivative instruments have been designated as cash flow hedges. Changes in fair value are recorded in OCI, with gains and losses reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings.

New Asset Development Efforts

We are pursuing a growth strategy that leverages our specific expertise and complements our existing operations. We expect our growth to stem from three broad channels: growth from our existing assets, development of new assets and inorganic growth. Since 1998, Calpine has developed approximately 28 GW of generation across the United States, enough electricity to power approximately 27 million homes. We have successfully developed natural gas, geothermal, battery storage and solar assets, and our experienced development team continually seeks out and evaluates opportunities to grow our businesses organically. We have expertise in all areas of the project development process, from state and federal permitting to interconnection evaluation, equipment procurement, thermal design, project financing and construction management. We have multiple battery storage, geothermal and natural gas assets under development. In addition to new generation facilities, we are working towards potential retrofits of existing natural gas facilities to capture carbon dioxide (“CO2”) from the flue gas for permanent storage in geologic formations.

Battery Storage

We are currently operational on Phases I – IV (out of five total phases) of one of the world’s largest battery storage projects, the 680 MW Nova Power Battery Storage Facilities in Menifee, California, and we have several other battery storage projects under construction or in development. Our pipeline of identified projects is primarily comprised of sites where we have existing land, infrastructure and/or transmission rights, which greatly facilitate the development of new battery storage.

Geothermal

As the owners of the world’s largest geothermal power plant complex, The Geysers, we look for opportunities to both increase the efficiency of our existing fleet and to expand and build new generating assets. We currently have an expansion underway at The Geysers that is expected to increase capacity by 25 MW via additional steam production wells in the northern part of the field. We continue to pursue opportunities to increase the output of our Geysers project as we look to increase the supply of low-carbon, dispatchable power that we are able to provide from our geothermal fleet.

Natural Gas

We believe that natural gas-fired generation will play a critical role in the U.S., given its low air emissions, high reliability and potential for future carbon abatement opportunities. In Texas, we are under construction for the 425 MW Pin Oak Creek Energy Center, LLC project adjacent our existing Freestone facility, and we are advancing the development of a natural gas combined cycle gas turbine (“CCGT”) expansion at the Gregory Facility in Corpus Christi in partnership with an industrial customer. We also have additional gas developments underway in cooperation with our customers. Our development team has significant expertise in developing gas projects, which allows us to successfully develop new gas projects in an environment where others may be challenged.

Carbon Capture

Our fleet includes multiple facilities located proximate to favorable carbon dioxide sequestration geology, and we have identified an initial pipeline of facilities that we believe might be good candidates for the application of post-combustion carbon capture technology. As part of our effort to advance these potential projects, we have completed or commenced front-end engineering design studies at five facilities partially funded by the Department of Energy (“DOE”), have executed the first phase with DOE’s Office of Clean Energy Demonstrations for cost-sharing awards of up to $270 million each for two full-scale demonstration projects — at our Baytown Energy Center east of Houston in Texas and our Sutter Energy Center near Sacramento in California. We are currently operating with a partner, Ion Energy, a DOE-funded pilot-scale carbon capture facility at our Los Medanos facility in California, the only pilot attached to an operating natural gas combined cycle facility in the world. The Baytown and Sutter projects have the potential to sequester up to 3.75 million metric tons of CO2 annually. Decisions to move construction forward on both projects are contingent on successfully completing several remaining milestones, including achieving sufficient returns after executing long-term customer contracts for decarbonized generation facility output.

Our Retail Businesses

Calpine is one of the nation’s largest retail energy providers, supplying electricity, gas and energy solutions to a diverse mix of customers across the United States. Calpine Retail, comprised of Calpine Energy Solutions, LLC and Champion Energy Marketing, LLC (“Champion,” “Champion Energy Services” or “Champion Energy”), engages our retail customers in a consultative sales approach to create innovative, tailored energy management products and services. We offer a wide range of retail power and gas products, both fixed price and index, with tenors varying based on the needs of each customer segment. By design, our retail operations overlap with our generation business, as this facilitates our ability to provide customers with access to clean, flexible and reliable electricity. Our leading retail business has a presence across all competitive retail markets in America, with our service area of 21 states.

Calpine Energy Solutions

Solutions, one of the largest energy suppliers in North America, is a licensed retail energy provider in every deregulated state. Solutions’ customers are mostly large commercial, industrial or institutional entities whose energy needs represent a significant part of their businesses, with a peak load of approximately 6,600 MW. Solutions employs a direct, consultative sales approach, offers bespoke products and leverages a proprietary framework to help customers manage their energy cost, risk and carbon exposure. In 2024, Solutions was re-accredited as a silver renewable energy partner by the Carbon Disclosure Project (“CDP”), which runs the world’s leading disclosure system for environmental impact.

Champion Energy Services

Champion is widely known for its customer service and straightforward and innovative pricing plans in Texas. Its peak load is approximately 1,700 MW and comprises residential, commercial and industrial customers, with coverage in most of the broadly deregulated states, largely Texas for residential customers.

Active External Engagement

Calpine’s business is at the intersection of heavy capital deployment, complex microeconomics and high-profile public policy. Through active external engagement with key stakeholders on behalf of our business and customers, we believe we can support the effective design and operation of the electric markets. As America’s largest generator of electricity from natural gas and geothermal resources, according to S&P Global Market Intelligence, and the owner of one of the nation’s largest retail energy providers, we bring an informed perspective to public policy discussions at the state, regional and national levels. Our Government and Regulatory Affairs personnel have become trusted experts on important issues affecting electric reliability and economics, earning us a seat at the table when key issues are being debated.

Emissions and Our Environmental Profile

The environmental profile of our power plants reflects our commitment to environmental stewardship. We believe we have invested the capital necessary to develop a power generation portfolio with substantially lower air emissions than our major competitors’ power plants that use other fossil fuels, such as coal. In addition, we strive to preserve our nation’s valuable water and land resources. With efficient technology and use of cleaner fuel, our plants have a smaller footprint and less hazardous waste generation compared to coal. In 2023, our GHG emissions from natural gas combustion amounted to approximately 48.9 million metric tons with a net electric generation of approximately 119 million megawatts-hour. In addition, we aim to further reduce our environmental footprint in the future by implementing carbon capture technology at many of our facilities and further developing and using battery storage facilities, which is expected to lower our emissions intensity per kilowatt-hour provided, as the battery storage facilities are expected to primarily be charged by renewable power.

Natural Gas-Fired Generation

Our fleet consumes significantly less fuel to generate power than conventional boiler/steam turbine power plants. It emits fewer air pollutants per MWh of power produced as compared to coal-fired or oil-fired power plants. Our power plants all have air emissions controls, which seek to reduce emissions such as Nitrogen Oxides (“NO_x”), a precursor of atmospheric ozone and acid rain. The table below summarizes approximate air pollutant emission rates from our power plants compared to the average emission rates from U.S. coal, oil and natural gas-fired power plants as a group, based on the most recent statistics available.

Geothermal Generation

As a renewable energy source, our Geysers Assets do not burn fossil fuel and produce power with only negligible emissions of naturally emitted _CO2, NO_x and SO2 from the steam. Our Geysers Assets, which produce 8% of the renewable energy and 49% of the geothermal power in California, are helping to meet the state’s clean energy goals.

Water Conservation and Reclamation

We have also invested substantially in technologies and systems that reduce the effect of our operations on water as a natural resource:

Governmental and Regulatory Matters

As participants in wholesale and retail energy markets and owners and operators of power plants and battery storage facilities in various regions around the country, certain Calpine entities are subject to regulation by various federal and state government agencies. These include the FERC, CFTC, NERC, as well as other public utility commissions, federal and state environmental protection agencies and reliability organizations in states or regions where Calpine’s generation assets are located, or where Calpine provides retail energy services. In addition, Calpine is subject to the market rules, procedures and protocols of the various ISO and RTO markets in which it participates. Federal and state legislative and regulatory actions, including those by ISOs and RTOs, continue to influence our business. We are actively participating in these debates at the federal, regional, state and ISO/RTO levels. Some of the more significant governmental and regulatory matters that affect our business are discussed below.

Since President Trump took office on January 20, 2025, the Trump Administration has issued a series of Executive Orders and agency memoranda generally intended to pause and review Biden-era programs and spending (to include renewable energy and environmental programs, as well as diversity, inclusion, and equity initiatives); reshape the federal government and workforce; and advance new priorities, to include supporting traditional energy exploration and production and ensuring AI dominance. As one example, by executive order, the Trump Administration temporarily paused the disbursement of IRA and Infrastructure Investment and Jobs Act (“IIJA”) funding, subject to future review and approval. We are evaluating impacts of these executive actions to Calpine’s businesses, including to our CCS development projects that benefit from IIJA-funded grants.

Power and Natural Gas Matters

Power Regions

The following is a brief overview of our core power regions – CAISO, ERCOT, PJM, ISO-NE, NYISO and Canadian IESO. The CAISO market is in our West segment. The ERCOT market is in our Texas segment. Our East segment includes the PJM, ISO-NE, NYISO and Canadian IESO markets. These markets are constantly evolving in response to external factors that may disrupt the competitive balance within the wholesale markets.

State and federal actions to provide out-of-market financial subsidies to support the development or continued operation of zero-carbon generation and battery storage resources continue. As these actions grow, they could adversely affect capacity and energy prices in the deregulated electricity markets, which in turn could have a material adverse effect on our business prospects and financial results.

West

Most of our power plants and battery storage facilities in our West segment are in California, in the CAISO region. We also own one power plant in Arizona and one in Oregon. The various wholesale markets in which our subsidiaries operate are subject to various controls, such as price caps and mitigation of bids when transmission constraints arise. The controls and the markets are subject to regulatory change at any time.

CPUC is addressing grid reliability through mandates for more than 15 GW of new capacity (primarily storage) in addition to the 3.3 GW of new capacity ordered in 2019. To the extent these additional resources are successfully procured and begin operation, they could impact pricing in California’s electricity market. We have actively participated in solicitations to meet these mandates with the storage resources we are developing, and capacity uprates to The Geysers. The CPUC is also considering new long-term “programmatic” procurement requirements for capacity and clean energy. In addition, the CPUC recently authorized (but did not mandate) “central procurement” of 10.6 GW of long lead-time resources, including geothermal, offshore wind and long-duration storage, with on-line dates in the 2030s. The Department of Water Resources would procure on behalf of all CPUC-jurisdictional loads with CPUC oversight. This procurement provides an opportunity for Calpine to develop additional geothermal and long-duration storage resources. On the other hand, to the extent that offshore wind is procured and developed, it is likely to depress energy and capacity prices for our portfolio.

The CPUC also administers a Resource Adequacy program, which requires load-serving entities to procure capacity through bilateral contracting. The CPUC recently adopted new rules that entail capacity requirements that vary by hour-of-day. The 2024 calendar year is a test year for these new rules. Full implementation will take place in 2025. The planning reserve margin for the program ultimately determines procurement requirements. The CPUC continues to consider a new and likely higher planning reserve margin for the program and plans to adopt a new planning reserve margin next year. In addition, CAISO is considering changes to the aspects of the RA program it administers, including requirements to replace capacity on planned outages and availability incentives. Further, the CPUC and CAISO continue to express interest in derating the capacity that can be sold from gas generation, such as ours, to reflect its historical forced outage performance.

CAISO administers the spot energy and ancillary service markets for most of California. Important market design changes currently contemplated by CAISO include expanding its day-ahead market outside of California, energy and ancillary service pricing that better reflects scarcity. While better scarcity pricing could increase our energy revenues, it is also likely to be complemented by additional mitigation, which could lower our revenues.

In addition, CAISO manages the interconnection of new resources. CAISO is dealing with a significant backlog of interconnection requests, primarily for new solar and storage resources. To manage the backlog, CAISO recently introduced (and FERC approved) significant changes to its interconnection process to favor resources that are presumed more viable. One of the criteria to determine viability is whether a resource has a long-term contract with a load-serving entity. This change gives more leverage to buyers in negotiations over contracts for new resources, such as the battery storage projects we are developing.

CARB continues to consider changes to California’s carbon emissions cap-and-trade program authorized by AB 32, including lowering the 2030 cap and caps in the intervening years. CARB also plans for the program to continue past 2030. While the program is only authorized in legislation through 2030, CARB has asserted that it is authorized to continue the program post 2030. In addition, legislation may provide clear authorization for the program to continue post 2030. We cannot predict how this will unfold or what the ultimate impact on Calpine will be. For additional details, see “California: GHG — Cap-and-Trade Regulation” below.

In October 2023, California Governor Gavin Newsom signed into law two state Senate Bills and one state Assembly Bill that collectively require certain public and private U.S. companies that perform certain business activities in California to disclose information related to their GHG emissions, climate-related financial risks, Voluntary Carbon Offsets (“VCOs”) and certain climate-related emission claims, these. These laws could impact Calpine.

First, SB 253, the “Climate Corporate Data Accountability Act,” requires CARB to adopt regulations, which would require us to annually disclose our scope 1 and scope 2 emissions from the prior fiscal year beginning in 2026 and scope 3 emissions by 2027. The regulations promulgated by CARB also require various levels of assurance of the reported emissions over time for the different emission scopes. SB 253 would require us to publish emissions data on a public digital platform. Second, SB 261 would require us to (1) prepare a climate-related financial risk report following the Task Force on Climate-Related Financial Disclosures framework and (2) indicate the measures adopted to reduce and/or adapt to these risks on or before January 1, 2026, and to update the report every subsequent two years. The report must be made publicly available on our website. Third, AB 1305, which went into effect on January 1, 2024, requires entities that either market or sell VCOs within California and make certain climate-related emission claims regarding those VCOs to disclose substantiating information about their emissions claims, including whether an independent third-party has verified the company data and claims. The relevant disclosures must all take place on the entity’s website. We do not believe that AB 1305 currently applies to any of our products or services.

On September 27, 2024, SB 219 (Wiener, Statutes of 2024, Chapter 766) amended state law to extend the date for CARB to adopt the regulations specified in SB 253 from January 1, 2025, to July 1, 2025. The first reports by reporting entities will still be due in 2026 on a date to be established by CARB in its rulemaking. Those first reports will cover scope 1 and scope 2 emissions during the reporting entity’s prior fiscal year. On December 5, 2024, CARB issued an enforcement notice notifying entities that it has decided to exercise enforcement discretion for the first reporting cycle and not take enforcement action for incomplete reporting.

To date, CARB has not proposed regulations pursuant to SB 253 and SB 261, which are both now subject to litigation. We believe we are subject to these laws and will continue to assess our reporting and disclosure requirements as the regulations are developed.

Texas

Our subsidiaries that own power plants in Texas have power generation company status at the PUCT and sell at market-based rates in ERCOT. ERCOT generally ensures resource adequacy through an energy-only market design. There is also a market offer price cap for energy and ancillary services purchased to serve customers in ERCOT. Under certain market conditions, the offer cap could be set lower than the maximum offer cap. Our subsidiaries are subject to the offer cap rules, but only for sales of power and ancillary services in ERCOT.

Several bills were passed in the 2023 Texas Legislative session that will impact the competitive wholesale electricity market in Texas, and implementation work is ongoing. First, House Bill 1500 codifies the Performance Credit Mechanism (“PCM”) but caps the cost at $1 billion, potentially limiting the mechanism’s effectiveness to provide reliability without other products. Second, House Bill 1500 requires ERCOT to create a new ancillary service called Dispatchable Reliability Reserve Service (“DRRS”) for dispatchable resources to provide flexibility to address intra-hour operational challenges. ERCOT and the PUCT are currently working on implementing DRRS products. Both changes are generally favorable for Calpine’s fleet.

In November 2023, Texas voters approved a state constitutional amendment to create a Texas Energy Fund (“TEF”), which will provide up to $7.2 billion of 3% loans and completion bonuses for a maximum of ten GW of new dispatchable generation in Texas. While the Texas legislature has only appropriated $5 billion of state funding for the TEF, we believe they will likely appropriate an additional $5 billion during the 2025 legislative session. In Spring 2024, the PUCT finalized rules determining how the TEF funding will be allocated to eligible generation developers and subsequently received applications from 38 GW of new capacity to potentially receive funding. Project awards were announced in Fall 2024, including a 425 MW peaking facility for Calpine. Calpine is undergoing due diligence with the PUCT and expects to be awarded in Mid-2025. Although Calpine applied for funding under TEF for its Peak Oak Creek Energy Center development project, we believe the out-of-market subsidies are unnecessary for a well-functioning, competitive ERCOT market.

ERCOT is continuing to implement changes to its markets to ensure operational reliability and is also conducting a broader examination of all ancillary services, such as frequency regulation, spinning reserves and non-spinning reserves. It is too early to tell whether further changes to the suite of ancillary services will be made and how those changes might impact pricing. Additionally, in February 2024, an appeal was filed challenging PUCT’s approval of ECRS, which was added to support grid reliability. This appeal remains pending, and we cannot predict what the outcome will be or its impact on pricing.

East

PJM

PJM operates wholesale power markets consisting of a locationally based energy market, a forward capacity market and ancillary service markets in all or parts of 13 states and the District of Columbia. PJM also performs transmission planning and operation for the region. The rules and regulations affecting PJM power markets and transmission are subject to change over time.

In January 2024, FERC approved revisions to PJM’s capacity market rules to better reflect winter reliability risk, correlated resource outages, fuel availability and the performance of intermittent and energy-limited resources during the periods of highest system stress. As more intermittent resources are added to an already constrained grid, the reliability and stability our gas assets provide become more critical and, therefore, more valuable. While the most recent PJM capacity auction for Delivery Year 2025/2026 cleared the premium load zones at revenue numbers consistent with the last 8 years, the RTO zone cleared meaningfully higher than the historically low 2024/2025 auction, prompting several complaints to be filed at FERC. These complaints relate in part to how reliability must run ("RMR") resources, i.e., resources kept on-line through out-of-market contracts that would otherwise retire, participate in the capacity market and various aspects of how the demand curves for PJM’s capacity market are determined, and requirements for intermittent and storage resources to participate in the capacity market. In response to these complaints and on its initiative, PJM submitted several FERC tariff filings with changes to the market to be implemented before the next capacity auction to be held in December 2025 for the 2026/2027 delivery year. FERC has since approved PJM’s market changes. While most of the proposed changes are likely to lower prices, their impact is expected to be offset by the robust increase in load and the associated increase in capacity demand. In addition, PJM is continuing to refine its capacity market rules through its normal stakeholder process. A few focus areas include how much historical data is used to determine how resources count towards capacity requirements and whether and how to shift from an annual to a seasonal capacity market construct. At this juncture, we cannot predict how these future changes may impact our portfolio.

In December 2024, Pennsylvania Governor Josh Shapiro filed a FERC complaint against PJM seeking to lower PJM’s capacity market price cap. The complaint drew support from the governors of Delaware, Illinois, Maryland and New Jersey, and joined two other pending FERC complaints seeking a range price-lowering reforms in PJM. In January, PJM and Governor Shapiro announced a settlement to resolve the complaint by implementing a price collar for the next two auctions, effectively a $325/MW-day cap and a $175/MW-day floor. The collar proposal will be filed at FERC in mid-February, joining a suite of pending PJM capacity market reforms—though the collar proposal will be one of the more consequential proposals awaiting FERC action. We can’t predict at this time how FERC will rule on the settlement, or the underlying complaint, so the impact on Calpine is unknown.

Illinois

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 CO2 emissions by EGUs. Under that schedule, privately owned natural gas units that exceed an established level of NO_x and SO_x emissions and are located within three miles of an environmental justice community, or an equity investment-eligible community must permanently eliminate CO2 emissions by January 1, 2030, subject to certain reliability exceptions. Left unchanged, this legislation will impact our Zion Energy Center and could require it to eliminate its CO2 emissions or shut down by January 2030.

Pennsylvania

The Pennsylvania Department of Environmental Protection finalized its CO2 Budget Trading Program regulations in the fall of 2021, establishing Pennsylvania’s participation in the Regional Greenhouse Gas Initiative (“RGGI”). The Senate and House Republicans subsequently filed with the Commonwealth Court claims against the Environmental Quality Board (“EQB”) seeking to permanently block the promulgation of the RGGI regulations because the EQB does not have the authority to implement the regulations. The legislators also filed a Petition for Preliminary Injunction. A second complaint and Petition for Preliminary Injunction were filed on April 25, 2022, by various industry groups, including labor and coal interests. On July 8, 2022, the Commonwealth Court granted the Petitions for Preliminary Injunction and, as a result, the Pennsylvania RGGI regulations, including Calpine’s obligation to purchase allowances for CO2 emissions, were stayed. On November 1, 2023, the Commonwealth Court issued a decision granting the petitions for a permanent injunction, finding EQB’s regulations directing Pennsylvania to join RGGI are void and unenforceable. As a result of this decision, the EQB is barred from enforcing the Pennsylvania RGGI regulations. The EQB and non-governmental organizations appealed the Commonwealth Court’s decision to the Pennsylvania Supreme Court. The appeal is still pending.

We cannot predict at this time whether the Pennsylvania Supreme Court will grant the appeal or, if it did, whether the Commonwealth will continue the process of RGGI participation. While ultimate Pennsylvania participation in RGGI would not be positive for Calpine, we are unable to predict the ultimate effect on our financial condition, results of operations, or cash flows.

New Jersey

The New Jersey Department of Environmental Protection issued final regulations on January 17, 2023, that impose new CO2 emissions limits on certain EGUs in New Jersey, depending on the nameplate capacity of the EGU and whether the EGU is existing or new. Our Carlls Corner and Mickleton facilities were shut down on June 1, 2024. Our Sherman and Cumberland facilities are also expected to be impacted in 2027, and our Cumberland 2 facility is expected to be impacted in 2035.

ISO-NE

In our East segment, we have three power plants located in Massachusetts, Maine and New Hampshire, all of which participate in the regional wholesale market administered by the ISO-NE RTO.

ISO-NE continues to pursue significant changes to its capacity market, including a transition from an annual and 3-year forward market to a prompt/year-ahead seasonal market and the introduction of more accurate resource counting similar to approaches recently adopted in NYISO, MISO and PJM. The ISO plans to implement the changes through multiple tariff filings in 2025 and 2026 for implementation for FCA 19, the capacity auction for the 2028-2029 delivery year. A critical aspect of ISO-NE’s proposed approach for resource counting is the representation of regional gas supply constraints, which ultimately could limit capacity sales from resources without firm fuel. The dual fuel capability of our largest plant in the region, Fore River, could provide firm fuel. We are exploring contractual and other firm fuel options for our other plants. Overall, we cannot predict what impact, if any, these ISO-NE efforts will have on our business.

NYISO

We have five power plants in our East segment located in New York. NYISO is the RTO which manages the transmission system in New York and operates the state’s wholesale power markets. NYISO manages both day-ahead and real-time energy and a forward capacity market where capacity prices are determined through auctions.

NYISO recently implemented significant changes to resource accreditation in its capacity market. As in New England and PJM, these changes attempt to accurately capture how different resources contribute to reliability under a range of weather and resource performance conditions. Also, like New England, NYISO continues to develop additional accreditation changes that reflect regional gas supply constraints. We continue to monitor how these changes might ultimately impact the capacity we can sell from our resources in New York.

Regulation of Transportation and Sale of Natural Gas

Since most of our power generating capacity is derived from natural gas-fired power plants, we are broadly affected by federal regulation of natural gas transportation and sales. We own two Texas pipelines that are subject to Texas Railroad Commission regulation as Texas gas utilities. We also operate a proprietary pipeline system in California, regulated by the U.S. Department of Transportation and the Pipeline and Hazardous Materials Safety Administration. Additionally, some of our power plants own and operate short pipeline laterals that connect the natural gas-fired power plants to the North American natural gas grid. Some of these laterals are subject to state and/or federal pipeline safety regulations.

Federal Regulation of Futures and Other Derivatives

The CFTC has regulatory oversight of futures markets, including trading on NYMEX for energy and licensed futures professionals such as brokers, clearing members and large traders. In connection with its oversight of the futures markets and NYMEX, the CFTC regularly investigates market irregularities and potential manipulation of those markets. Specific laws also give the CFTC certain powers with respect to broker-type markets referred to as “exempt commercial markets” or (“ECMs,”) including the ICE. The CFTC monitors activities in the OTC, ECM and physical markets that may be undertaken for the purpose of influencing futures prices. With respect to ECMs, the CFTC exercises only light-handed regulation primarily related to trade reporting, price dissemination and record retention (including retention of fraudulent claims and allegations).

Environmental Matters

The environmental profile of our power plants reflects our commitment to environmental leadership and stewardship. We have invested the capital necessary to develop a power generation portfolio with substantially lower air emissions than our major competitors’ power plants that use other fossil fuels, such as coal.

Federal Air Emissions Regulations

Clean Air Act

The CAA provides for the regulation of air quality and air emissions, mainly through state implementation of federal requirements. We believe that all our operating power plants comply with existing federal and state performance standards mandated under the CAA. In addition to regulating air emissions at the federal level, several states where we conduct business have implemented regulations that go beyond current federal environmental requirements. We continue to monitor and actively participate in federal and state initiatives that further our environmental and business objectives and where we anticipate an impact on our business.

The CAA requires the EPA to regulate emissions of harmful pollutants to public health and the environment. The EPA has set NAAQS for six “criteria” pollutants: carbon monoxide, lead, NO2, particulate matter, ozone and SO2. In addition, the CAA regulates many air pollutants known to cause or may reasonably be anticipated to cause adverse effects to human health or adverse environmental effects, known as Hazardous Air Pollutants (“HAPs”). The EPA must issue technology-based National Emissions Standards for Hazardous Air Pollutants (“NESHAPs”) to limit the release of specified HAPs from specific industrial sectors. The EPA also regulates emissions of certain pollutants that affect visibility in national parks and wilderness areas through the Regional Haze Program (“Regional Haze”). Finally, the EPA has begun regulating GHG emissions from various industries, including the power sector.

These CAA regulations primarily affect higher-emitting units in the national power-generating fleet. Our commitment to environmental stewardship is reflected in our history of investing in lower-emitting power plant technologies. As a result, these regulations generally do not have a significant direct adverse effect on our generating fleet, although they may impose substantial costs on the power industry overall.

GHG Emissions

On May 9, 2024, the EPA issued a final rule to regulate GHG emissions from existing coal-fired power plants and new natural gas turbines under Sections 111(b) and 111(d) of the CAA. If implemented, the new 111(b) rule would require all new gas plants built in the United States to either capture the carbon produced or significantly limit the number of hours per year that any new plant could operate, which could impact the ultimate operations of our development projects based on the CO2 emissions limitations contained within the rule. However, multiple parties have filed petitions for review of the rules in the D.C. Circuit Court of Appeals. Multiple parties filed requests to stay the rule pending litigation, but the D.C. Circuit and the U.S. Supreme Court denied such requests for a stay. Oral argument before the D.C. Circuit Court was held on December 6, 2024. The timing for the court’s action is unclear, and the current presidential Administration is expected to significantly change course by seeking to revise, replace or reverse the rule.

NAAQS — Ozone

As part of its ongoing CAA obligation to periodically review NAAQS to ensure that air quality is protective of human health and the environment, on October 1, 2015, the EPA set a new standard for ground-level ozone of 70 parts per billion, down from the standard set in 2008 of 75 parts per billion. This requirement is significant to the power sector because ground-level ozone is a product of complex chemical reactions contributed by NO_x, one of the primary emissions of concern from power plants.

Air quality in Houston, where six of our power plants are located, has improved over the last two decades. As a result, the Houston area was determined by the EPA to be attaining the 1-hour ozone standard, effective November 19, 2015, and the 1997 8-hour ozone standard, effective January 29, 2016. The Houston area remains in nonattainment relative to the 2008 ozone standard and was downgraded in overall status relative to that standard effective September 23, 2019. The area’s status is also in nonattainment under the 2015 ozone standard, which could lead to further, more stringent regulation of NO_x emissions from mobile sources and several industry sources, particularly the power industry.

Under authority granted under the CAA, the Texas Commission on Environmental Quality adopted regulations to attain the earlier NAAQS for ozone, including the establishment of a Cap-and-Trade program for NO_x emitted by industrial sources in the Houston-Galveston-Brazoria ozone nonattainment area, including power plants. Our six power plants participating in this program received free NO_x allowances based on historical operating profiles. Our Houston-area power plants have sufficient NO_x allowances to meet forecasted obligations under the program. Due to the ongoing noncompliance of the Houston-Galveston-Brazoria area with the 2008 and 2015 standards, allowable NO_x emissions could be reduced in the future under this program, which could cause us to incur additional compliance costs.

On June 5, 2023, the EPA published the final “Federal Implementation Plan Addressing Regional Ozone Transport for the 2015 Ozone National Ambient Air Quality Standard” in the Federal Register, and the rules went into effect on August 4, 2023. The EPA adopted this action under the “good neighbor” or “interstate transport” provision of the CAA. As adopted, 23 states are subject to tighter emissions budgets for fossil fuel-fired power plants, including some plants owned by Calpine, in the NO_x Ozone Season Group 3 Trading Program. However, multiple states have challenged the rule. In June, the U.S. Supreme Court upheld a stay of the rule implementation in its entirety, pending a decision from the D.C. Circuit Court of Appeals on the merits of the various legal challenges. We do not expect this further litigation to be resolved in the next several years and will continue to monitor the litigation and its impact on Calpine as it proceeds through the courts.

Regional Haze

The EPA first issued the Regional Haze rule in 1999, focusing on emissions of SO2, NO_x and particulate matter, particularly PM2.5. The Regional Haze program includes two major components: demonstration of Reasonable Further Progress, and installation of Best Achievable Retrofit Technology (“BART”). States submit State Implementation Plans (“SIP”) to the EPA for approval. These SIPs delineate all relevant emission control programs in the state and demonstrate that the state is making reasonable progress toward the Regional Haze program visibility goals.

In the eastern United States, regional NO_x and SO2 programs are relied upon in Regional Haze SIPs to achieve much of the required emission reductions. EPA policy also allows them to substitute for the installation of BART. If the EPA does not approve a SIP, it may instead issue a Federal Implementation Plan, which will specify the control requirements for sources in a state.

On July 1, 2024, the EPA agreed to issue final agency actions for over 30 outstanding state plan revisions under the Regional Haze program between July 30, 2024, and December 31, 2026. The consent decree ends a suit by environmental groups alleging that the agency had impermissibly delayed the approvals or denials of state plan revisions.

Hazardous Air Pollutants

In 2012, the EPA adopted MATS for coal- and oil-fired power plants.

After multiple court challenges and rule modifications by different EPA administrations, in April 2024, the EPA finalized strict standards for non-mercury HAP metals and mercury emissions from lignite-fired power plants. The new mercury limit aligns with the existing limit for all other coal-fired EGUs set in 2012; for lignite-fired power plants, this represents a 70% reduction in their allowable mercury emissions. EGUs must reduce their non-mercury HAP emissions by 66% compared to the 2012 MATS standard. The 2024 final rule has now been challenged in the D.C. Circuit Court of Appeals by various states and industry groups.

If the MATS were invalidated because of the pending litigation challenging the EPA’s decisions in 2016 or 2020 in the development of the rule or as a result of any litigation concerning the EPA’s finalized rule, then coal-fired power plants would no longer be required to operate their emissions controls, which could disadvantage our cleaner gas-fired power plants in markets where they compete directly with coal-fired power plants.

State Air Emissions Regulations

In addition to federal GHG rules, several states and regional organizations have developed state-specific or regional initiatives to reduce GHG emissions through mandatory programs. The most advanced programs include California’s suite of GHG policies promulgated pursuant to AB 32, including its Cap-and-Trade program, Massachusetts’ CO2 reduction program and RGGI in the Northeast. The evolution of these programs could have a material effect on our business.

In these programs, a cap is established defining the maximum allowable emissions of GHGs emitted by sources subject to the program. Affected sources must hold one allowance for each ton of CO2 emitted (and, in the case of California’s program, other GHGs) during the applicable compliance period. The California and RGGI programs also contain provisions using qualified offsets instead of allowances. Allowances are distributed through auctions or allocations to affected companies. In addition, there are functional secondary markets for allowances. We obtain allowances in various ways, including through bilateral or exchange transactions and under the terms of PPAs.

California: GHG — Cap-and-Trade Regulation

California’s climate policies and GHG reduction targets are among the most ambitious and aggressive in the world. AB 32, as amended by Senate Bill (“SB”) 32 in 2016, requires California to reduce statewide GHG emissions to 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. AB 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.

Northeast GHG Regulation: RGGI

As of December 31, 2024, 11 states in the Northeast participate in RGGI, a Cap-and-Trade program, which affects our power plants in Maine, Massachusetts, New Hampshire, New Jersey, New York and Delaware. Virginia participated but exited participation in RGGI in 2023 through a regulatory, not legislative, process. Due to a legal challenge, a Circuit Court Judge in Virginia ruled in November that legislation is required for Virginia to exit RGGI and struck down the attempted RGGI repeal. Governor Younkin has indicated he will appeal the decision. Unless the Circuit Court decision is stayed pending an appeal, the Virginia Department of Environmental Quality must move forward to allow Virginia RGGI participation. Virginia's participation in RGGI will not have a material impact on Calpine, regardless. Conversely, as discussed more fully in the PJM section above, Pennsylvania joined RGGI in 2022, but that action is being challenged in state court. The court has issued a preliminary injunction prohibiting Pennsylvania from participating in RGGI while litigation continues.

We receive annual allocations from New York’s long-term contract set-aside pool to cover some of the CO2 emissions attributable to our PPA at the Stony Brook Power Plant.

Massachusetts: Global Warming Solutions Act

In addition to participating in RGGI, on August 17, 2017, the Massachusetts Department of Environmental Protection promulgated regulations establishing an annually declining cap on CO2 emissions from in-state electricity generators. The program became effective on January 1, 2018, and established an allowance trading system and auction platform. This program covers CO2 emissions from our Fore River Energy Center, and we will continue to comply with its provisions.

Other Environmental Regulations

Renewal Portfolio Standard ("RPS")

We are subject to RPS in multiple states where we conduct business. Generally, RPS requires each retail electricity seller to include in its resource portfolio (the resources procured by the retail seller to supply its retail customers) a certain amount of power generated from renewable or clean energy resources by a certain date.

California SB 100, passed in 2018, sets the California RPS mandating that by 2030, retail power providers generate or procure 60% of the power they sell to retail customers from renewable resources. Further, beginning in 2021, retail power providers must meet 65% of their compliance obligations for contracts with terms of ten years or longer. Finally, per the legislation, all the state’s electricity must come from carbon-free resources by 2045. Behind-the-meter solar generally does not count towards California’s RPS requirements, and there are limits on different “buckets” of procurement that can be used to satisfy the RPS. Load-serving entities must satisfy a growing fraction of their compliance obligations with renewable power from resources located in California or delivered into California within the hour, such as our Geysers Assets.

Additionally, California SB 1020, passed in 2022, establishes interim clean electricity targets of 90% and 95% for 2035 and 2040. As discussed above, the CPUC is implementing “programmatic” procurement requirements to meet the targets. While the RPS (and associated clean energy requirements) generally depress wholesale energy prices, the intermittency of many renewable resources raises operational flexibility challenges that present opportunities for natural gas-fired generation to provide capacity and ancillary services products. In addition, the RPS could result in the retirement of less efficient, non-renewable generating units, creating opportunities for our fleet. Further, California’s clean energy goals continue to encourage our battery development pipeline. They could, subject to additional measures to support recognition of carbon sequestration within the California RPS, eventually support carbon capture retrofits to our existing gas fleet.

Several additional states have RPS in place. Existing state-specific RPS requirements may change due to regulatory and/or legislative initiatives, and other states may consider implementing an enforceable RPS in the future. Our retail subsidiaries operate in states with RPS in place. They must procure a certain amount of power from renewable sources or purchase renewable energy credits to comply with the RPS requirements.

Clean Water Act

The federal Clean Water Act establishes requirements relating to the discharge of pollutants into United States waters, including from cooling water intake structures. Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of cooling water intake structures reflect the best technology available for minimizing environmental adverse effects. We are required to obtain wastewater and storm-water discharge permits for wastewater and runoff, respectively, for some of our assets. We are subject to the requirements for cooling water intake structures at many of our power plants. In addition, we are required to maintain spill prevention control and countermeasure plans for some of our assets. We do not use once-through cooling technology at any of the power plants in our fleet. We believe that our facilities, subject to the Clean Water Act, comply with applicable discharge requirements of the Clean Water Act.

Safe Drinking Water Act

Part C of the Safe Drinking Water Act establishes the underground injection control program that regulates the disposal of wastes by means of deep well injection. Although geothermal production wells, which bring steam to the surface, are exempt under the Energy Policy Act of 2005, we use geothermal re-injection wells to inject reclaimed wastewater back into the steam reservoir, which is subject to the underground injection control program. We believe that we are in compliance with Part C of the Safe Drinking Water Act and its implementing regulations.

Comprehensive Environmental Response, Compensation and Liability Act

CERCLA, also referred to as the Superfund, requires the clean-up of sites from which there has been a release or threatened release of hazardous substances and authorizes the EPA to take any necessary response action at Superfund sites, including ordering potentially responsible parties liable for the release to pay for such actions. Potentially responsible parties are broadly defined under CERCLA to include past and present owners and operators of a site, as well as generators of wastes sent to a site, and liability under CERCLA can be strict, joint and several. As of the filing of this Report, we are not subject to any material liability for any Superfund matters. However, we generate certain wastes, including hazardous wastes, and send such wastes to third-party waste disposal sites. As a result, there can be no assurance that we will not incur a liability under CERCLA in the future.

Changing Governmental and Regulatory Environment

In addition to controls on air emissions, our power plants and battery storage facilities and the equipment necessary to support them are subject to other extensive federal, state and local laws and regulations adopted for the protection of the environment and to regulate land use. The laws and regulations applicable to us primarily involve the discharge of wastewater and water use. Still, they can also include wetlands protection and preservation, protection of endangered species, hazardous materials handling and disposal, waste disposal and noise regulations. Noncompliance with environmental laws and regulations can result in the imposition of administrative, civil, or criminal fines or penalties. In some instances, environmental laws may also impose clean-up or other remedial obligations in the event of a release of pollutants or contaminants into the environment. The federal laws listed above are among the more significant environmental laws that apply to us. In most cases, analogous state laws also exist that may impose similar and, in some cases, more stringent requirements on us than those discussed above. We believe the environmental profile of our portfolio affords us some advantage over our competitors in complying with these laws.

The IRA was signed into law on August 16, 2022. This legislation provides energy tax credits for the development of renewable resources, nuclear, CCS, hydrogen, and electric vehicles and introduces new tax provisions, including the CAMT, as a means to fund continued renewable energy investment. While we cannot currently quantify the long-term effect of this legislation on Calpine, nor can we predict future legislative changes to the IRA, to the extent the IRA stays in place in whole or in part in the future, the IRA’s energy tax credit provisions could have a lasting effect on the power markets in which Calpine operates and provide opportunities for the continued development of renewable resources in the Calpine fleet. Further, the expanded 45Q tax credits benefit our efforts to reduce carbon dioxide emissions from power generation assets by pursuing CCS. While we are not currently subject to the CAMT, we continue to monitor and evaluate the effect of CAMT provisions on Calpine.

In June 2024, the U.S. Supreme Court issued decisions in Loper Bright Enterprises v. Raimondo and Corner Post, Inc. v. Board of Governors, both of which could change the landscape of administrative law in the United States. In Loper, the Court cut back on the deference that courts provide to federal agencies to interpret ambiguous laws they administer, ruling that courts should rely on their own interpretation of ambiguous laws. In Corner Post, the Court made certain agency rules vulnerable to legal challenges under the Administrative Procedure Act years after they were finalized. It is still too early to tell exactly how these decisions may impact the agencies with which Calpine interacts.

Human Capital

We are a commercially focused asset-based organization. We are guided by our stated set of values (“ASPIRE values”). Our ASPIRE values are embedded in our Company’s policies, practices and business decisions. We are successful because of our people. Our employees bring a wealth of talent, experience, intelligence and resourcefulness to us. Our people use these skills to deliver reliable electricity and energy products to our customers. Our people's knowledge base and expertise allow us to optimize the value and profitability of our electric facilities and our retail power provider brands and prudently manage the risks inherent in our business. Our employees are committed to working safely, securely and responsibly.

We provide our employees with a challenging and rewarding performance-based work environment that values diversity, equity and inclusion and allows for professional development and opportunities for advancement. We focus on attracting and retaining talented individuals to manage our operations and provide key support in executing our business strategy.

Health and Safety

Occupational health and safety are core values and are foundational to our culture. Best-in-class health and safety practices mitigate risks to our business and enable us to protect our employees, our environment, our communities and our assets.

Our Executive Safety Committee provides leadership and oversight surrounding health and safety and meets quarterly, focusing on lessons learned from fleet events. At the plant level, each plant location has a safety committee. Importantly, we believe safety is everyone’s responsibility and strive to instill accountability, engagement and continuous learning at all levels of our organization to drive risk recognition and mitigation.

All employees and contractors working on our sites are required to abide by our health and safety policies, procedures and protocols. Our "Three Safety Tenants,” “Event-Free Operations Guidelines,” and “Six Cardinal Rules of Hazard Recognition & Mitigation" inform day-to-day safety practices across our plants and offices. Further, our “Stop Work Obligation Policy” provides that all employees, contractors and visitors have the obligation and right to stop work if a job cannot be done safely.

As of December 31, 2024, we employed approximately 2,500 full-time employees, of whom 184 were represented by collective bargaining agreements. Two collective bargaining agreements, representing a total of 29 employees, will expire within one year. We have never experienced a work stoppage or a strike. While we believe that we have excellent depth throughout all levels of management and in all key skill levels of our employees, the loss of the services of one or more members of our senior management or numerous employees with critical skills could have a negative effect on our business, financial conditions and results of operations and future growth. For a discussion of the risk relating to employees with critical skills, see the section titled “Item 1A. Risk Factors.”

Item 1A. RISK FACTORS

The following summarizes the principal factors that make an investment in our company speculative or risky, which are more fully described in the section below. This summary should not be relied upon as an exhaustive summary of our business's material risks. The following factors could result in harm to our business, financial condition, results of operations, cash flows and prospects, among other impacts:

Risk Related to the Proposed Merger between Calpine and Constellation

Calpine will be subject to business uncertainties while the Plan of Merger is pending, which could adversely affect our respective businesses.

Uncertainty about the effect of the Plan of Merger on employees, industry contacts and business partners may have an adverse effect on Constellation and Calpine. These uncertainties may impair Calpine’s ability to attract, retain and motivate key personnel until the Plan of Merger is completed and for a period of time thereafter and could cause industry contacts, business partners and others that deal with Calpine to seek to change their existing business relationships with Calpine. Employee retention at Calpine may be particularly challenging during the pendency of the Plan of Merger, as employees may experience uncertainty about their roles with Constellation following the Plan of Merger. In addition, the Plan of Merger Agreement requires Calpine to follow certain interim operation covenants until completion of the Plan of Merger. These restrictions may negatively affect the businesses, operations and financial results during the pendency of the Plan of Merger.

Risks Related to Our Business

Power Operations

Our power operations performance involves significant risks and hazards and may be below expected levels of output or efficiency.

The operation of power plants and battery storage facilities involves risks, including the breakdown or failure of power generation or storage equipment, transmission lines, pipelines or other equipment or processes, performance below expected levels of output or efficiency and risks related to the creditworthiness of our contract counterparties and the creditworthiness of our counterparties’ customers or other parties, such as steam hosts, with whom our counterparties have contracted. From time to time, our power plants and battery storage facilities have experienced unplanned outages, including extensions of scheduled outages due to equipment breakdowns, failures or other problems, which are inherent risks to our business. Unplanned outages typically can result in lost revenues, inability to perform and potential recognition of liquidated damages owed and/or termination of existing long-term PPAs, increase our maintenance expenses and may reduce our profitability, which could have a material adverse effect on our financial condition, results of operations and cash flows.

Our power operations are inherently hazardous and may lead to catastrophic events, including loss of life, personal injury and property destruction. These events may also subject us to future claims, litigation and enforcement.

Our power plants and battery storage facilities operations are inherently hazardous. They may lead to catastrophic events, including loss of life, personal injury and destruction of property and subject us to litigation. Natural gas is highly explosive, and power generation and energy storage operations involve hazardous activities, including acquiring, transporting and delivering fuel, operating large pieces of rotating equipment and delivering power to transmission and distribution systems. These and other hazards include, but are not limited to, the risk of events such as wildfires, other natural disasters or extreme weather events, that may affect the ability for our power plants and battery storage facilities to operate, can cause severe damage to and destruction of property, plant and equipment and suspension of operations. In the worst circumstances, catastrophic events can cause significant personal injury or loss of life. Further, any of these events may result in us being named as a defendant in lawsuits asserting claims for substantial damages. We maintain an amount of insurance protection that we consider adequate; however, we cannot provide any assurance that the insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we are subject.

We rely on power transmission and fuel distribution facilities owned and operated by other companies.

We depend on facilities and assets that we do not own or control for the transmission to our customers of the power products from our power plants and battery storage facilities and the distribution of natural gas or fuel oil to our power plants. If these transmission and distribution systems are disrupted or the capacity of those systems is inadequate, our ability to sell and deliver power products or obtain fuel may be hindered. ISOs that oversee transmission systems in regional power markets have imposed price limitations and other mechanisms to address volatility in their power markets. Existing congestion, as well as the expansion of transmission systems, could affect our performance, which in turn could adversely affect our business.

Our project development and construction activities may not be completed on schedule or within budget and may not be successful.

As of December 31, 2024, we are developing additional battery storage capacity, various natural gas and renewable power generation facilities and carbon capture facilities. We expect to continue to develop and construct other facilities in the future. The development and construction of power plants and battery storage facilities are subject to substantial risks. In connection with the development of a project, we must generally obtain:

To the extent that our development and construction activities continue or expand, we may be unsuccessful on a timely and profitable basis. Although we may attempt to minimize the financial risks of these activities by securing a favorable PPA and arranging adequate financing prior to the commencement of construction, the development of a battery storage facility or power project may require us to expend significant cash sums for preliminary engineering, permitting, legal and other expenses before we can determine whether a project is feasible, economically attractive or financeable. The process for obtaining governmental permits, approvals and/or grants is complicated and lengthy, often taking more than one year, and is subject to significant uncertainties. These permits and approvals are usually subject to litigation, prolonging the development timeline by several years. We may be unable to obtain all necessary licenses, permits, approvals and certificates for proposed projects and completed battery storage facilities or power plants may not comply with all applicable permit conditions, statutes or regulations. In addition, regulatory compliance for the construction and operation of our facilities can be costly and time-consuming. Intricate and changing environmental and other regulatory requirements may necessitate substantial expenditures to obtain and maintain permits. A project may be unable to function as planned due to changing requirements, loss of required permits or regulatory status or local opposition. In that case, it may create expensive delays, extended periods of non-operation or significant loss of value in a project, resulting in potential impairments and loss of PPAs.

We are dependent on third-party contractors for the successful completion of our construction projects, and these contractors may not be able to complete these projects on time, within budget and in accordance with agreed-upon specifications.

Our construction projects could be subject to delays, cost overruns, reduced performance outcomes and other factors that could have a material adverse effect on our business, financial condition, operating results, cash flow, liquidity and prospects. The timely and cost-effective completion of our projects in compliance with agreed specifications is central to our business strategy. It is highly dependent on several factors, including the performance of third-party equipment suppliers as well as engineering, procurement and construction (“EPC”) contractors pursuant to their agreements with us.

We have not yet entered into definitive agreements with all the contractors and suppliers necessary for our projects' development and construction. We may not be able to successfully enter into such supply and construction contracts on terms or at prices that are acceptable to us, including because skilled EPC contractors (particularly those with experience in solar, battery storage and carbon capture facilities) and significant items of equipment are in high demand and equipment supply chains continue to be constrained.

The ability of our EPC contractors to perform successfully under their agreements with us is dependent on several factors, including, but not limited to, their ability to:

Our EPC contracts and equipment supply contracts are also subject to a number of other risks that may result in delays, price overruns and reduced performance outcomes, including equipment and materials availability and changes in laws, including import tariffs. Although some of our EPC contracts may provide for liquidated damages to be paid to us if the contractor is delayed in completing a project or if the project fails to achieve certain performance standards, any liquidated damages that we receive may be delayed, capped or otherwise insufficient to cover the damages that we suffer because of any such delay or reduced performance outcome.

Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts that increase the cost of the applicable facility or result in a contractor’s unwillingness to perform further work. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason, we would be required to engage a substitute contractor, which could be particularly difficult as demand for skilled and experienced EPC contractors increases. This substitution would likely result in significant project delays and increased costs and the damages provided under the applicable EPC contract may be inadequate to compensate us for the cost of such substitution fully.

Since some of our projects will be developed and constructed using an EPC contractor and one or more equipment suppliers, the different contractors may attribute equipment or project defects or damages to the other contractor. In this event, there may be disputes between us and one or more contractors regarding which contractor is responsible for project or equipment defects and damage. Further, one contractor or supplier could damage or delay the work of another, forcing us to grant relief to the aggrieved contractor. This could result in delays and/or additional project costs.

Delays in completing a project may require us to pay liquidated damages under our customer contracts under certain circumstances, result in contract terminations, or otherwise have a material adverse effect on our financial condition and results of operations. Delays may also cause costs to bring a project to completion to be greater than expected, which could reduce the project’s profitability and/or result in damages payable by us.

In addition, delays in completing a project could result in a default under the financing agreement for the project. In such an event, there is no assurance that we will be able to obtain waivers from lenders or refinance loan agreements on acceptable terms or at all. We may be required to post additional security under any such loan agreements and agree to additional covenants that could restrict our ability to finance our future operations and capital needs.

We may be unable to obtain an adequate fuel supply in the future or face transmission constraints.

We obtain substantially all our physical natural gas and fuel oil supply from third parties under arrangements that vary in terms of pricing structure, firmness and delivery flexibility. Our physical natural gas and fuel oil supply arrangements must be coordinated with transportation agreements, balancing agreements, storage services, financial hedging transactions and other contracts so that the natural gas and fuel oil are delivered to our power plants at times, in the quantities, and otherwise in a manner that meets the needs of our generation portfolio and our customers. We must also comply with laws and regulations governing natural gas transportation.

Additionally, the PJM and ISO-NE power markets have recently experienced an increase in natural gas-fired generation assets that supply electricity to the area. As a result, there has been a corresponding increase in the need for natural gas transmission assets to supply the generation assets with fuel to generate power. When extreme cold temperatures rapidly increase the demand for natural gas for residential heating, it can also create constraints on natural gas pipelines that serve power generation assets. When these conditions exist, they could interrupt the fuel supply to our natural gas-fired power plants in these power markets. However, some of our natural gas-fired power plants in this region are dual-fuel and benefit from the ability to operate on both natural gas and fuel oil.

Adequate supplies of natural gas and fuel oil are currently available to us at prices we believe are reasonable for each of our power plants. Availability of supply is generally not an issue; localized shortages (especially in extreme weather conditions in and around population centers), transportation availability and supplier financial stability issues can and do occur. We are exposed to increases in the price of natural gas and fuel oil, and it is possible that sufficient supplies to operate our portfolio profitably may not continue to be available to us. In addition, we face risks regarding the delivery to and the use of natural gas and fuel oil by our power plants, including the following:

If we were to experience a significant reduction in our expected revenues and operating cash flows for an extended period, our power plants, battery storage facilities and construction projects could be subject to impairments.

If we were to experience a significant reduction in our expected revenues and operating cash flows for an extended period due to a prolonged economic downturn or advances or changes in technologies, we could experience future impairments of our power plant and battery storage assets. There can be no assurance that any such losses or impairments to the carrying value of our financial assets would not have a material adverse effect on our financial condition, results of operations and cash flows.

For example, during the year ended December 31, 2022, we recorded impairment losses of approximately $46 million related to our Carlls Corner Energy Center, Mickleton Energy Center, Sherman Avenue Energy Center and Cumberland Energy Center because of legislation signed into law in January 2023. The Company recorded no impairment losses during the year ended December 31, 2023, and no impairment losses during the year ended December 31, 2024.

Our geothermal resources may be inadequate for our operations.

In connection with each geothermal power plant, we estimate the productivity of the geothermal resource and the expected decline in productivity. The productivity of a geothermal resource may decline more than anticipated, resulting in insufficient reserves being available for sustained generation of the desired power capacity. In addition, we may not be able to successfully manage the development and operation of our geothermal reservoirs or accurately estimate the quantity or productivity of our steam reserves. An incorrect estimate, an inability to manage our geothermal reserves, or a decline in productivity could adversely affect the results of our operations or financial condition. In addition, the development and operation of geothermal power resources are subject to substantial risks and uncertainties. The successful exploitation of a geothermal power resource ultimately depends upon many factors, including the following:

Significant events beyond our control, such as natural disasters, weather-related events or acts of terrorism, could damage our power plants, battery storage facilities or corporate offices, cause a loss of system load and may affect us in unpredictable ways.

Certain of our geothermal and natural gas-fired power plants and battery storage facilities, particularly in the West, have been in the past and remain subject to frequent low-level seismic disturbances. More significant seismic disturbances are possible. In addition, extreme weather events, including winter storms such as Winter Storm Uri, tornadoes, tropical storms or hurricanes and bouts of extreme temperature, may impact areas in which we operate. A hurricane, tropical storm or other severe wind or rain event could substantially affect operations at our corporate offices in Houston, Texas. Any significant loss of system load resulting from a weather-related event could negatively impact our wholesale business and retail subsidiaries. Such events could damage or shut down our power plants, battery storage, power transmission or the fuel supply facilities upon which our wholesale business and retail subsidiaries depend. We have also experienced damage and outages at other facilities due to extreme weather events such as hurricanes and winter storms, including fuel supply disruptions. Our existing power plants and battery storage facilities are built and maintained to reduce exposure to severe weather events and/or relatively significant seismic disturbances. We believe our insurance policies are adequate to cover damage caused by most natural disasters, weather-related events, acts of terrorism or earthquakes. However, our property damage or business interruption insurance may be inadequate to cover all potential losses sustained in the event of extensive damage to multiple power plants and battery storage facilities or large-scale disruptions to our wholesale and retail operations due to natural disasters. Moreover, as insurance companies adjust their approaches to reflect changing risk patterns, there can be no guarantee that such insurance policies will continue to be available in the future on terms we find acceptable.

Periodic wildfires, particularly in California, could damage our power plants and battery storage facilities, cause a loss of system load and affect us in unpredictable ways.

Our geothermal and natural gas-fired power plants and battery storage facilities in the West have been in the past and remain subject to an ongoing risk of wildfires. Severe drought conditions, unseasonably warm temperatures and stronger winds have increased the severity and prevalence of wildfires in various areas where we operate, particularly California. For example, our Geysers Assets have been adversely affected by wildfires several times in the last ten years, including damage sustained by the Kincaid and Valley wildfires. Wildfires and other extreme weather events may materially and adversely affect our operations in the future. Such events could damage or shut down our power plants, battery storage, power transmission or the fuel supply facilities upon which our power plants or battery storage facilities are dependent or cause serious injuries, fatalities, property damage or service interruptions, which could expose us to liabilities that could be material. We believe our insurance policies adequately cover damage caused by most wildfires. However, our property damage or business interruption insurance may be inadequate to cover all potential losses sustained in the event of extensive damage to multiple power plants and battery storage facilities or large-scale disruptions to our operations due to wildfires. Wildfires in California and other areas may exacerbate these insurance risks by leading to adverse changes in insurance deductibles, premiums, coverage and/or limits. If we incur substantial liability and the damages are above our estimates for self-insured claims, or such damages are not covered by our insurance policies or exceed policy limits or if we incur liability at a time when we do not have liability insurance, our results of operations and cash flows could be materially and adversely affected.

In addition, electric utilities in many states within our West segment may shut down power for public safety reasons, such as during periods of extreme fire hazard, if the utility reasonably believes that there is an imminent and significant risk that strong winds may topple power lines or cause vegetation to make contact with power lines leading to increased risk of fire. We have previously experienced shutdowns for public safety reasons at The Geysers. Any shutdown of power for public safety reasons may reduce our revenues by halting operations at our power plants and battery storage facilities and/or reducing the market for power.

Our business is subject to physical, market and economic risks relating to the potential effects of climate change. Policies at the national, regional and state levels to regulate greenhouse gas emissions and mitigate climate change could adversely impact our results of operations, financial condition and cash flows.

Fluctuations in weather and other environmental conditions, including temperature and precipitation levels, may affect customer demand for electricity or natural gas. In addition, the potential physical effects of climate change, such as increased frequency and severity of storms, floods and other climatic events, could disrupt our operations and supply chain and cause us to incur significant costs in preparing for or responding to these effects. These or other climate changes could increase operating costs or capital expenses. Our customers may also experience the potential physical impacts of climate change. They may incur significant costs in preparing for or responding to these efforts, including changing the fuel mix and resiliency of their energy solutions and supply.

Climate change's contribution to the frequency or intensity of weather-related events could affect our operations and planning process. Climate change could also affect the availability of a secure and economical water supply in some locations, which is essential for the continued operation of our generation plants. If it is determined that extreme weather events could impact projected generation levels at any plant, risk mitigation efforts are identified and evaluated for implementation; however, there can be no guarantee that such efforts will be successful.

Further, demand for our energy-related services could be similarly impacted by customers’ preferences or market or regulatory factors favoring energy efficiency, lower-carbon energy sources or reduced electricity or natural gas usage. To the extent markets prefer alternative energy technologies different from those we operate, it may impact our ability to retain or attract additional customers or otherwise adversely affect our business.

Our operations depend on the availability of sufficient water resources.

Various forms of power generation, including natural gas and geothermal and energy-intensive activities, such as data centers, depend on water access to function. Certain of our assets in the West and Texas Regions, including The Geysers, have experienced drought conditions in the recent past. Disruptions in water availability — whether natural, such as droughts, or artificial, such as curtailment or high prices — may impact our ability to generate energy or serve customers, adversely impacting our operations and financial condition. Further, disruptions in water availability at The Geysers may affect the water injection program, steam production and generation levels at The Geysers.

We are subject to a series of risks regarding various sustainability and related “environmental, social and governance” (“ESG”) matters.

Companies across industries face increasing scrutiny from various stakeholders regarding environmental sustainability, climate change, water, natural capital, diversity, equity and inclusion (“DEI”), human rights and other ESG matters. Stakeholder actions and increased regulatory activity regarding such matters could adversely impact our operations, costs of or access to capital, demand for our products/services and otherwise impact or limit business plans. Our management of ESG matters may require us to incur additional costs and may not have the desired effects.

Additionally, there are and may continue to be, increasing levels of regulation, disclosure-related and otherwise, concerning ESG matters. For example, policymakers such as the SEC and the State of California have adopted, and other policymakers are considering adopting, requirements for significant additional disclosures of climate- or other sustainability-related information, which may require us to incur costs for compliance. Various stakeholders also use ESG considerations in their decision-making. Unfavorable perceptions of our ESG profile may negatively impact our business, whether from a reputational perspective or our attractiveness to capital providers, employees, customers and business partners. Simultaneously, some stakeholders have attempted to reduce companies’ efforts on certain ESG-related matters. Both advocates and opponents of certain ESG matters increasingly resort to various forms of activism, including media campaigns and litigation, to advance their perspectives. To the extent we are subject to such efforts, we may incur costs or otherwise adversely impact our business. Such risks may also affect certain of our suppliers or customers, resulting in indirect impacts, including those that may not be known to us.

Our business, financial condition and results of operations could be adversely affected by strikes or work stoppages by unionized employees or by our inability to replace key employees.

As of December 31, 2024, approximately 7% of our employees are subject to collective bargaining agreements. If our union employees participate in a strike, work stoppage or other forms of labor disruption, we would be responsible for procuring replacement labor. We could experience reduced power generation or outages.

In addition, our success largely depends on our people's skills, experience and efforts. The market for highly skilled workers in our industry is extremely competitive, particularly where many of our key personnel are located. The loss of the services of one or more members of our senior management or numerous employees with critical skills could harm our business, financial condition, results of operations and future growth if we could not replace them. We also do not currently maintain any key person life insurance policies.

Our operations are subject to hazards and risks that require significant and continuous oversight. If one or more such risks occur and we cannot respond quickly or adequately, it could affect our results of operations and financial condition.

Our operations are subject to various hazards and risks that require significant and continuous oversight, many of which are described in more detail in Item 1A. Risk Factors section, including explosions, fires, severe weather, geological events, global health crises, such as epidemics and pandemics, labor disputes, geopolitical tensions, terrorist attacks, sabotage, civil unrest or cyberattacks. Our business and operations may be disrupted if we do not respond, or are perceived not to respond, in an appropriate manner to any of these hazards and risks or any other major crisis or if we are unable to restore or replace affected operational components and capacity efficiently. Countermeasures to address global health crises, epidemics or pandemics may result in disruptions to our supply chain, the global economy or financial or commodity markets; disruptions in our contractual arrangements with our service providers, suppliers and other counterparties; failures by our suppliers, contract manufacturers, contractors, joint venture partners and external business partners, to meet their obligations to us; reduced workforce productivity; and voluntary or involuntary curtailments. Further, our insurance may not be adequate to compensate us for all resulting losses described above, and the cost to obtain adequate coverage may increase for us in the future or may not be available. Any of these factors could materially increase our costs, negatively impact our revenues and damage our financial condition, results of operations, cash flows and liquidity position.

Negative publicity may damage our reputation or brand and negatively impact our business, financial condition and results of operations.

Our reputation and brand could be damaged for numerous reasons, including negative views of our environmental impact, sustainability goals, supply chain practices, product and service offerings and public statements made by our officials. Additionally, we are sometimes named in investigations, claims and lawsuits arising in the ordinary course of business, and customers have in the past communicated complaints to consumer protection organizations, regulators or the media. Negative claims or publicity regarding us or our operations, offerings, practices or customer service may damage our brands or reputation, even if such claims are untrue. We may also experience criticism or backlash from media, customers, employees, government entities, advocacy groups and other stakeholders who disagree with positions taken by us or our executives. If our brand or reputation is damaged, it could negatively impact our business, financial condition, results of operations and ability to attract and retain highly qualified employees.

Commercial Operations

Our financial performance is affected by commodity price fluctuations in the wholesale and retail power and natural gas markets and other market factors beyond our control.

Market prices for power, generation capacity, ancillary services, natural gas, fuel oil and RECs are unpredictable and tend to fluctuate substantially. Electric power generally must be produced concurrently with its use. As a result, power prices are subject to significant volatility due to supply and demand imbalances, especially in the day-ahead and spot markets. Depending upon the price risk management activity we undertake, a decline in market prices for power, generation capacity and ancillary services may adversely affect our financial performance. Long- and short-term power and natural gas prices may also fluctuate substantially due to other factors outside of our control, including:

These factors have caused our operating results to fluctuate in the past and will continue to cause them to do so in the future.

We may not be able to pass through price fluctuations and other changes in our costs to our end-user customers due to the following factors, which are beyond our control:

Accounting for derivative hedging activities and trading may increase the volatility in our quarterly and annual financial results.

We engage in commodity-related marketing and price-risk management activities to economically hedge our forward commodity market price risk exposure using both physical and financial commodity purchases and sales commitments. Some of these contracts are accounted for as derivatives under U.S. GAAP, which requires us to record the fair value of the commitment on the balance sheet with changes in the fair value of all derivatives reflected within current period earnings if hedge accounting is not applied. We also engage, to a substantially lesser extent compared to our hedging activities, in proprietary derivative transactions that are not intended to hedge our own risk but are instead intended to make a profit by capitalizing on arbitrage opportunities with basis, time, quality or geographic spreads related to the energy products we sell. Proprietary derivative transactions, by their nature, expose us to changes in the underlying commodity prices of the proprietary positions taken. Any adverse changes could result in losses, which can be further exacerbated in the financial and other markets. As current period earnings are impacted by non-cash mark-to-market gains/losses associated with price risk management hedges of future period activity that are accounted for as derivatives, we are unable to accurately predict the effect that our risk management decisions may have on our quarterly and annual financial results prepared in accordance with U.S. GAAP.

The use of hedging agreements and trading may not work as planned or fully protect us and could result in financial losses.

In accordance with internal policies and procedures designed to monitor hedging activities and positions and proprietary trading, we enter into hedging agreements and proprietary derivative transactions, including contracts to purchase or sell commodities at future dates and at fixed prices, to manage our commodity price risks. As part of this, the portfolio may be positioned net long or net short power or gas at any given time. Although intended to mitigate price volatility and enhance portfolio value, these activities expose us to risks related to commodity price movements, deviations in weather and other risks. When we sell power forward, we may be required to post significant amounts of cash collateral or other credit support to our counterparties, and we give up the opportunity to sell power at higher prices if spot prices are higher in the future. Further, if the values of the financial contracts change in a manner that we do not anticipate, or if a counterparty or customer fails to perform under a contract, it could harm our financial condition, results of operations and cash flows.

We do not typically hedge the entire exposure of our operations against commodity price volatility. To the extent we do not hedge against commodity price volatility, our financial condition, results of operations and cash flows may be diminished based upon adverse movement in commodity prices.

Our ability to enter into hedging agreements and derivative transactions and manage our counterparty and customer credit risk could adversely affect us.

Our wholesale counterparties, retail customers and suppliers may experience deteriorating credit. These conditions could cause counterparties in the natural gas and power markets, particularly in the energy commodity derivative markets we rely on for our hedging activities, to withdraw from participating in those markets. If multiple parties withdraw from those markets, market liquidity may be threatened, adversely affecting our business, and creating more earnings volatility. Additionally, these conditions may cause our counterparties or customers to seek bankruptcy protection under Chapter 11 or liquidation under Chapter 7 of the U.S. Bankruptcy Code. Our credit risk may be exacerbated to the extent that collateral held by us cannot be realized or is liquidated at prices insufficient to recover the full amount of the exposure due to us. There can be no assurance that any such losses or impairments to the carrying value of our financial assets would not materially and adversely affect our financial condition, results of operations and cash flows.

Extensive competition in our wholesale and retail businesses could adversely affect our performance.

The power industry is characterized by intense competition, including from utilities, industrial companies, marketing and trading companies and other independent power producers. This competition may pressure power utilities to lower their costs, including the cost of purchased power. In addition, construction during the last decade has created excess power supply and higher reserve margins in certain power trading markets, putting downward pressure on prices.

Other companies we compete with may have greater liquidity, greater access to credit and other financial resources, lower cost structures, greater ability to incur losses, longer-standing relationships with customers, greater potential for profitability from ancillary services, or greater flexibility in the timing of their sale of generation capacity and ancillary services than we do.

Additionally, extensive competition exists in the retail power markets in which our retail subsidiaries operate. Competitors may offer lower prices or other incentives to attract customers away from our retail subsidiaries. We may also face competition from several other energy service providers, other energy industry participants or nationally branded providers of consumer products and services who may develop businesses that will compete with our retail subsidiaries.

In certain situations, the counterparty or customer may terminate our PPAs and other contractual arrangements, including construction agreements, commodity contracts, maintenance agreements and other arrangements and/or allow the counterparty or customer to seek liquidated damages.

The counterparty or customer may terminate our PPAs, construction agreements, commodity contracts, maintenance agreements and other contractual arrangements. They may also seek to enforce the liquidated damages provisions contained in such agreements.

The situations that could allow a counterparty or customer to terminate the contract and/or seek liquidated damages include:

Revenue may be reduced significantly upon expiration or termination of our PPAs.

A material portion of the capacity or energy from our existing portfolio is sold under long-term PPAs that expire at various times. We seek to extend contracts or sell any capacity not sold under long-term PPAs on a short-term basis as market opportunities arise. Our non-contracted capacity is generally sold on the spot market at current market prices as merchant energy. When the terms of each of our various PPAs expire, it is possible that the price paid to us for power generation under subsequent arrangements or in short-term markets may be significantly less than the price paid to us under the PPA. Without the benefit of long-term PPAs, we may not be able to sell any or all of the capacity from these power plants or battery storage facilities at commercially attractive rates, and these power plants and battery storage facilities may not be able to operate profitably. Certain of our PPAs have values above current market prices. If a counterparty to a PPA were to seek bankruptcy protection under Chapter 11 or liquidation under Chapter 7 of the U.S. Bankruptcy Code, they may be able to terminate the PPA. We risk losing margins to the extent that these contracts expire or are terminated, and we cannot replace them on comparable terms.

The introduction or expansion of competing technologies for power generation and demand-side management tools could adversely affect our performance.

The power generation business has substantially changed the technologies used to produce and store power. With federal and state incentives for developing and producing renewable power sources, we have seen market penetration of competing technologies, such as wind, solar and commercial-sized power storage. Additionally, the development of demand-side management tools and practices can affect peak demand requirements for some of our markets at certain times during the year. The continued development of subsidized, competing power generation and storage technologies and significant development of demand-side management tools and practices could alter the market and price structure for power and negatively affect our financial condition, results of operations and cash flows.

Supplier Concentration Risk

Supplier concentration, suppliers' inability to meet their obligations and dependence on third-party service providers may expose us to performance and cost risks and adversely affect our results of operations, cash flows and financial condition.

We often rely on a single contracted supplier or a few suppliers for turbines and other key parts and services required to operate our facilities. We will be forced to use the marketplace if these or any other suppliers cannot perform these services. There can be no assurance that the marketplace can provide these services as, when, and where required or at comparable prices. The failure of any supplier to fulfill its contractual obligations to us, our inability to source products and services on acceptable terms, if at all, and the failure of third parties to provide services to its customers that are necessary for our operations could have a material adverse effect on our financial results. As a result, our facilities' financial performance depends on the credit quality and continued performance by suppliers, which cannot be guaranteed.

Risks Related to Capital Resources and Liquidity

We have substantial liquidity needs and could face liquidity pressure.

As of December 31, 2024 and 2023, our consolidated debt outstanding was $12,162 million and 11,829 million, respectively, of which approximately $7,646 million and $7,735 million was outstanding under our First Lien Term Notes, First Lien Notes and Senior Unsecured Notes. In addition, as of December 31, 2024 and 2023, we had 2,052 million and $2,051 million, respectively issued in letters of credit. We also have agreements, such as accounts receivable monetization facilities, which assist in managing our working capital liquidity needs. Although we significantly extended our maturities during the last several years, we could face liquidity challenges as our business operations require substantial debt and liquidity requirements. Our ability to make payments on our indebtedness, meet margin requirements and fund planned capital expenditures and development efforts will depend on our ability to generate cash from our operations and access the capital markets. This, to a certain extent, is dependent upon industry conditions and general economic, financial, competitive, legislative, regulatory and other factors beyond our control, as discussed further in Item 1A. Risk Factors above.

We also have exposure to many different financial institutions and counterparties, including those under our credit and financing arrangements, as we routinely execute transactions in connection with our hedging and optimization activities, including brokers and dealers, commercial banks, investment banks, wholesale counterparties, ISOs, retail customers and other institutions and industry participants. Many of these transactions expose us to credit risk if any of our lenders or counterparties cannot honor their commitments or otherwise default under a financing agreement. For example, our wholesale business currently has contracts with investor-owned California utilities, which could be affected should they be found liable for recent wildfires in California and, accordingly, incur substantial costs associated with the wildfires. See additional discussion regarding our capital resources and liquidity in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations.

Our indebtedness could adversely affect our financial health and limit our operations.

Our indebtedness has important consequences, including:

We may be unable to obtain additional financing or access the credit and capital markets in the future at prices that are beneficial to us or at all.

If our available cash, including future cash flows generated from operations, is insufficient in the near term to finance our operations, post collateral or satisfy our obligations as they become due, we may need to access the capital and credit markets. Our ability to arrange financing (including any extension or refinancing) and the cost of the financing depends upon numerous factors, including general economic and capital market conditions. Market disruptions such as those experienced in the United States and abroad in recent years may increase our borrowing costs or adversely affect our ability to access capital. Other factors include:

While we have used non-recourse or lease financing when appropriate, market conditions and other factors may prevent us from completing similar financings in the future. We may be unable to obtain the financing required to develop, construct, acquire or expand power plants, battery storage facilities or new ventures, including battery storage projects, on terms satisfactory to us. We have financed our existing power plants and battery storage facilities using a variety of leveraged financing structures, including senior secured and unsecured indebtedness, construction financing, project financing, term loans and lease obligations. In the event of a default under a financing agreement that we do not cure, the lenders or lessors would generally have rights to the power plant and any related assets. In the event of foreclosure after a default, we may not be able to retain any interest in the power plant or other collateral supporting such financing. In addition, any such default or foreclosure may trigger cross-default provisions in our other financing agreements.

Our debt instruments impose restrictions on us, and any failure to comply with these restrictions could have a material adverse effect on our liquidity and operations.

The restrictions under our debt instruments could adversely affect us by limiting our ability to plan for or react to market conditions or to meet our capital needs and, if we were unable to comply with these restrictions, could result in the event of default under these debt instruments. These restrictions require us to meet certain financial performance tests quarterly and limit or prohibit our ability, subject to certain exceptions to, among other things:

Our debt instruments contain events of default customary for financings of their type, including a cross-default to debt other than non-recourse project financing debt, a cross-acceleration to non-recourse project financing debt and certain change of control events. If we fail to comply with the covenants and are unable to obtain a waiver or amendment, or a default exists and is continuing under such debt, the lenders, holders or trustee, as applicable, could give notice and declare outstanding borrowings and other obligations under such debt immediately due and payable.

Our ability to comply with these covenants may be affected by events beyond our control, and any material deviations from our forecasts could require us to seek waivers or amendments of covenants or alternative sources of financing or to reduce expenditures. We may not be able to obtain such waivers, amendments or alternative financing, or if obtainable, it could be on terms that are not acceptable to us. If we are unable to comply with the terms of our debt instruments, if we fail to generate sufficient cash flows from operations, or if it becomes necessary to obtain such waivers, amendments or alternative financing, it could adversely affect our financial condition, results of operations and cash flows.

Our credit status is below investment grade, which may restrict our operations, increase liquidity requirements and restrict financing opportunities.

Rating agencies evaluate several factors to arrive at credit ratings for us and our subsidiaries, including regulatory framework, ability to recover costs and earn returns, diversification, financial strength and liquidity. If one or more rating agencies downgrade us, borrowing costs would increase, the potential pool of investors and funding sources would likely decrease, and the terms of a number of commodity contracts, leases and other agreements may trigger cash or letter of credit collateral demands.

Our corporate and debt credit ratings are below investment grade. The table below shows our corporate and debt credit ratings as of December 31, 2024. There is no assurance that our credit ratings will improve, which may restrict the financing opportunities available to us or increase the cost of any available financing. Our current credit rating has resulted in the requirement that we provide additional collateral in the form of letters of credit or cash for credit support obligations, which may adversely affect our subsidiaries, our financial position and the results of our operations.

We may not have sufficient liquidity to hedge market risks effectively or secure certain of our obligations by letters of credit or cash, which increase our costs. If we cannot provide such security, it may restrict our ability to conduct our business.

We face significant market and liquidity risks due to our use of derivatives and commodity contracts our involvement in purchasing and selling power, capacity, fuel, transmission services and emission allowances. Our hedging activities and commodity procurement necessitate posting cash collateral or issuing letters of credit to support our obligations, which can substantially increase our costs and adversely affect our liquidity.

We hedge commodity price risk through various contracts, including futures exchanges, which necessitate two types of cash collateral: initial margin and variation margin. The exchange requires an initial margin to transact, and these requirements can be substantial during high market volatility. Variation margin addresses daily changes in the value of our derivative instruments based on their fair value. The level of required collateral could rise as our hedging activities increase, commodity prices fluctuate or our credit ratings change. As of December 31, 2024 and 2023, we had $223 million and $673 million, respectively in cash collateral posted related to our commodity hedging activity. Additionally, we have $2.1 billion issued in letters of credit under our Corporate Revolving Facility and other facilities, at both December 31, 2024 and 2023, with $5.4 billion and $4.2 billion, respectively remaining available for borrowing or for letter of credit support. In addition, we have ratably secured our obligations under certain power and natural gas agreements that qualify as eligible commodity hedge agreements with the assets subject to liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility.

We use cash margin deposits, prepayments, surety bonds and letters of credit for commodity procurement and risk management. Many collateral agreements mandate that financial institutions issue letters of credit with a minimum “A” credit rating. Our financial institutions issuing credit facilities meet or exceed this criterion. However, if they fail to maintain this rating, we may need to post collateral from our cash and cash equivalents, negatively impacting our liquidity.

Additionally, we undertake purchase and sale activities through agreements with various counterparties, many of which require us to provide guarantees, offset or netting arrangements, letters of credit, a second lien on assets and/or cash collateral to protect the counterparties against the risk of our default or insolvency. The amount of such credit support typically is based on the difference between the commodity's price in a given contract and the commodity's market price. Significant movements in market prices can result in our being required to provide cash collateral and letters of credit in very large amounts. Without sufficient working capital to post as collateral, we may be unable to manage price volatility effectively or implement our strategy.

If any of our power plants or battery storage facilities experience unplanned outages, we may be required to procure replacement power at spot market prices to fulfill contractual commitments. Without adequate liquidity to meet margin and collateral requirements, we may be exposed to significant losses, miss significant opportunities and be more exposed to the volatility of spot markets.

Further, changes in market regulations can increase the use of credit support and collateral. These requirements increase our cost of doing business. They could adversely affect our overall liquidity, particularly if there is a call for a large amount of additional cash or letter of credit collateral due to an unexpected large movement in the market price of a commodity.

Our ability to receive future cash flows generated from the operation of our subsidiaries may be limited.

Almost all of our operations are conducted through our subsidiaries and other affiliates. As a result, we depend almost entirely upon their earnings and cash flows to service our indebtedness, post collateral and finance our ongoing operations. Certain project debt and other agreements restrict our ability to receive dividends and other distributions from our subsidiaries. Additionally, the financing agreements of certain of our subsidiaries and other affiliates generally restrict their ability to pay dividends, make distributions or otherwise transfer funds to us before the payment of their other obligations, including their outstanding debt, operating expenses, lease payments and reserves or during the existence of a default.

Risks Related to Government Regulation

We are subject to complex governmental regulations, including the rules and regulations of FERC, CFTC, DOJ, EPA, numerous state agencies, which could adversely affect our operations.

In the United States, our operations are regulated by FERC concerning wholesale service terms and the sale and transportation of natural gas, as well as by state agencies regarding the physical aspects of power plants and battery storage facilities. Most of our electricity generation is sold at market prices under the market-based rate authority granted by FERC. If we fail to meet specific conditions, FERC has the authority to revoke this and require sales to be made at cost-of-service rates, which could materially impact our business. Additionally, FERC can impose fines or other restrictions under certain conditions.

We are also subject to additional rules and regulations due to foreign investors in our securities, including those promulgated by the Committee on Foreign Investment in the United States (“CFIUS”), the U.S. Department of Energy or the states we operate in. Compliance with these rules and regulations may affect how we do business, may impose added costs on our business, could delay or deter any particular investment or could also affect the price that some investors are willing to pay for our common stock.

The construction and operation of power plants and battery storage facilities necessitate numerous permits, approvals and certificates from foreign, federal, state, tribal and local agencies, along with adherence to extensive environmental regulations and permitting requirements. Failure to comply with these regulations and requirements could force us to install costly pollution control measures, limit activities or even retire generating plants. Non-compliance could result in administrative, civil or criminal liabilities and fines and regulatory agencies could curtail our operations. Moreover, certain environmental laws hold us strictly liable for costs to clean up and restore sites contaminated by hazardous substances, regardless of when the contamination occurred or whether previous owners or third parties caused it. We are generally responsible for environmental liabilities for our facilities, including known and unknown soil or groundwater contamination.

We currently have several government awards for geothermal and carbon capture projects involving cost-share agreements with the U.S. Department of Energy, which could be affected by our failure to comply with certain laws, rules and regulations.

At five facilities, we have completed or commenced front-end engineering design studies for post-combustion carbon capture technology. We have executed the first phase with DOE’s Office of Clean Energy Demonstrations for cost-sharing awards of up to $270 million each for two full-scale demonstration projects. In addition, we have installed a pilot-scale carbon capture facility at our Los Medanos facility in California. The DOE partially funded the engineering design studies for post-combustion capture technology and the pilot-scale carbon capture facility. We have also received funding from the DOE for certain geothermal drilling technologies at The Geysers facilities. As a recipient of federal funds under grants and cooperative agreements, in addition to our ordinary contractual obligations, we must comply with various rules and regulations applicable to entities that perform awards in support of government entities. Many of these additional obligations are contained in the terms of the awards themselves and in federal regulations, which regulate the formation, administration and performance of non-procurement federal financial assistance awards, which are subject to change. We must also comply with various national policy requirements prescribed by statute, executive order, policy guidance issued by the Executive Office of the President or other regulations subject to change.

Additionally, our contractors must also comply with these federal requirements, and any non-compliance by our contractors or their subcontractors could similarly affect our grant status and expose us to additional risks and liabilities. While we will continue to implement strong audits and monitor contractual rights for our contractors, failure by our contractors' requirements to comply with all regulatory requirements fully could materially affect our business and prospects.

Our performance under our U.S. government awards and our compliance with the terms of those awards and applicable laws and regulations are subject to periodic investigation audits, reviews and investigations by various U.S. government agencies. The current environment may lead to increased regulatory scrutiny and sanctions for non-compliance by such agencies.

Compliance with these laws and regulations affects how we do business and may impose added costs on our business. Failure to comply may lead to penalties, including whole or partial suspension or termination of our U.S. government awards and/or suspension or debarment from contracting with federal agencies.

Federal and state tax regulations, current incentives for renewable sources of power, existing and proposed state RPS and energy efficiency standards and economic support for renewable sources of power under federal or state legislation could adversely affect our operations.

Renewables have the potential to take market share from us and offer lower wholesale power prices, which could negatively impact our operations. The IRA represents the largest investment in U.S. history to address clean energy and climate change, including approximately $400 billion in federal funding to address clean energy and climate change. Among other things, incentives for low-carbon resources were significantly bolstered by the IRA, including an investment tax credit for battery storage, an extended production tax credit for wind and solar resources, a tax credit for clean hydrogen production, investment tax credits for eligible geothermal projects and increases in the tax credit for eligible carbon sequestration projects. While the IRA supports our battery storage and geothermal and carbon capture development efforts, we also expect the IRA to drive continued renewables growth across many of our regional markets, which could decrease the demand for power generated by our natural gas-fired plants. The IRA is subject to future guidance and implementing regulations to be issued by the U.S. Department of the Treasury, as well as potential legislative changes. Legislative changes and final regulations (or interpretations thereof) could adversely impact us, our ability to use the tax credits for which we are currently eligible or the markets in which we operate.

Several states have established RPS, mandating that a certain percentage of energy come from renewable sources, thus reducing reliance on fossil fuel generation. California is aiming for 100% CO2-free electricity by 2045, and states including Maine, New York, Texas, Illinois and Wisconsin have various RPS in place. Changes to these standards or the introduction of enforceable RPS in other states could increase the supply of wind and solar power, potentially affecting the dispatch of our natural gas-fired power plants, especially in Texas and California.

Energy efficiency or future technology initiatives in some states could also decrease demand for power, negatively affecting our natural gas-fired plants. For example, New Jersey’s new emissions limits on certain generators led to the shutdown of our Mickleton Station and Carlls Corner facilities in June 2024. They could lead to further shutdowns of our fossil fuel generation facilities, including our natural gas-fired power plants, in the future.

We may be subject to additional taxes, adversely impacting our business and financial results.

Tax laws, regulations and administrative practices in the jurisdictions in which we or our subsidiaries are organized or operate may be subject to significant change. For example, the United States enacted the IRA. The IRA imposes, among other things, a 15% corporate alternative minimum tax on the adjusted financial statement income (“AFSI”) of certain taxpayers (“CAMT”) and a 1% excise tax on certain corporate stock repurchases occurring after December 31, 2023. While we are not currently subject to the CAMT, we continue to monitor and evaluate the effect of CAMT provisions on us and future guidance to be issued by the U.S. Department of the Treasury and potential legislative changes.

Our ability to use our net operating loss carryforwards and certain other tax attributes may be limited, potentially resulting in increased tax liabilities to us in the future.

In prior years, we have suffered losses for tax and financial statement purposes that generated significant federal and state net operating loss carryforwards. As of December 31, 2024, our NOL carryforwards consisted primarily of federal NOL carryforwards of approximately $3.0 billion, of which the majority expire between 2028 and 2037, and apportioned NOL carryforwards in 21 states and the District of Columbia totaling roughly $1.5 billion, which expire between 2025 and 2043. Although these net operating loss carryforwards may be used against taxable income in future periods, we will not receive any tax benefits from the losses we incurred unless, and only to the extent that we have taxable income during the period before their expiration. If earnings are insufficient to use carryforwards before expiration, this could result in recognition of future losses and increased tax payments at both state and federal levels. In addition, our ability to use the net operating loss carryforwards could be severely limited if we complete a transaction that results in an ownership change under Section 382 of the Internal Revenue Code of 1986, as amended.

Changes in the regulation of the power markets in which we operate could negatively affect us.

We have a significant presence in the major competitive power markets of California, Texas and the Northeast and Mid-Atlantic regions of the United States. While these markets are largely deregulated, they continue to evolve. Existing regulations within the markets in which we operate may be revised or reinterpreted, and new laws or regulations may be issued, including by FERC, ISOs, RTOs and other market regulators. We cannot predict the future development of regulation or legislation nor the ultimate effect such changes in these markets could have on our business; however, we could be negatively affected.

Additionally, state PUCs can set policies that either enhance or limit customer choice. Each state that has adopted retail electric choice creates its own laws, regulations and compliance requirements, which evolve over time and could negatively affect our ability to maintain or expand retail operations and our retail business.

State legislative and regulatory action could adversely affect our competitive position and business.

Certain states have taken or are considering taking anti-competitive actions by subsidizing or otherwise providing economic support to new and/or existing uneconomic power plants in a manner that could have an adverse effect on the deregulated power markets. In addition, certain states in which we have retail operations are taking actions that we believe limit customer choice, as well as other actions that we believe are anti-competitive and could negatively affect our retail operations. We are actively participating in many of the legislative, regulatory and judicial processes challenging these actions at the state and federal levels. If these anti-competitive actions are ultimately upheld and implemented, they could adversely affect capacity and energy prices in the deregulated electricity markets or impede our ability to maintain or expand our retail operations, which in turn could have a material adverse effect on our business prospects and financial results.

Existing and future anticipated GHG/Carbon and other environmental regulations could cause us to incur significant costs and adversely affect our operations generally or in a particular quarter when such costs are incurred.

Environmental laws and regulations have generally become more stringent over time. There is a potential that new or expanded carbon taxes or limits on carbon, CO2, GHG emissions and other emissions could be implemented at the federal, state or regional levels. We continue to monitor and actively participate in initiatives and rulemaking proceedings where we anticipate a material effect on our business.

For example, 11 states in the Northeast are required to comply with a Cap-and-Trade program, RGGI, to regulate CO2 emissions from power plants. California has implemented AB 32, which places a statewide cap on GHG emissions and requires the state to reduce emissions to 40% below 1990 levels by 2030. The California Climate Crisis Act was enacted in 2022 and further establishes the policy of the state 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. The Massachusetts Department of Environmental Protection issued a final rule in August 2017 that imposes new GHG limits on power plants and other sources.

Environmental regulations could also affect the availability and price of natural gas used in our generation facilities. Permitting new natural gas transportation pipelines has become more difficult in some regions, such as the Northeast, and restrictions on natural gas production have been implemented or proposed in some locations.

If we were deemed to have market power in certain markets as a result of common ownership by certain significant investors, we could lose FERC authorization to sell power at wholesale market-based rates in such markets or be required to engage in mitigation in those markets.

Certain of our significant ownership groups currently, or in the future, may own power generating or battery storage assets or own significant equity interests in entities with such assets in markets where we currently own power plants or battery storage facilities. We could be determined to have market power if these existing significant owners or future owners acquire additional significant ownership or equity interest in other entities with such assets in the same markets where we generate, store and sell power.

If the FERC determines that we have market power, the FERC could, among other things, revoke market-based rate authority for the affected market-based companies or order them to mitigate that market power. If market-based rate authority were revoked for any of our market-based rate companies, those companies could be required to make wholesale sales of power based on cost-of-service rates, which could negatively affect their revenues. If we are required to mitigate market power, we could be required to sell certain power plants or battery storage facilities in regions where we are determined to have market power. A loss of our market-based rate authority or required sales of power plants or battery storage facilities, particularly if it affected several of our assets or was in a significant market, could have a material negative effect on our financial condition, results of operations and cash flows.

Risks Related to Insurance

We rely primarily on third-party insurance policies to insure our operations-related risks. If our insurance coverage is unavailable or insufficient for our business's needs or our insurance providers are unable to meet their obligations, we may not be able to mitigate the risks facing our business, which could adversely affect our business, financial condition and results of operations.

We procure third-party insurance policies to cover various operations-related risks, including property damage, automobile liability, employment practices liability, workers’ compensation, business interruptions, errors and omissions, cybersecurity and data breaches, crime, directors’ and officers’ liability and general business liabilities. For certain operations-related risks or future risks related to our new and evolving offerings, we may not be able to acquire insurance. In addition, we may not obtain enough insurance to mitigate such risks adequately, and we may face high premiums, co-insurance, self-insured retentions or deductibles for the coverage we do obtain. We rely on a limited number of insurance providers. If such providers discontinue or increase the cost of coverage, we cannot guarantee securing replacement coverage on reasonable terms or at all. If our insurance carriers change the terms of our policies unfavorably, our insurance costs increase. If the coverage we maintain is not adequate or if we are required to purchase additional insurance, we could incur significant costs. Additionally, if any of our insurance providers become insolvent, they will be unable to pay any claims.

If operations-related claims exceed our aggregate coverage limits, we would bear the excess in addition to amounts incurred with deductibles, self-insured retentions or co-insurance. Insurance providers have raised premiums and deductibles and may do so in the future. As a result, our insurance costs could increase, coverage could be reduced or we may decide to raise our deductibles or self-insured retentions. Our business, financial condition and results of operations could be adversely affected if: (1) costs, premiums, the severity of claims or the number of claims significantly exceeds our historical experience and coverage limits; (2) we experience a claim in excess of our coverage limits; (3) our insurance providers fail to pay on our insurance claims; (4) we experience a claim for which coverage is not provided or (5) the number of claims under our deductibles or self-insured retentions differs from historical averages.

We are also subject to contractual requirements, including financing requirements, to obtain insurance. If we are unable to obtain and maintain such insurance, we would violate these contractual requirements, which could lead to a default under such agreements. Additionally, we are subject to local laws, rules and regulations relating to insurance coverage, which could result in actions against us. Compliance with these rules and any related lawsuits or actions may require us to increase our insurance coverage, amend our insurance policy disclosure, increase our costs and disrupt our business.

Item 1B. UNRESOLVED STAFF COMMENTS

Not applicable.

Item 2.    PROPERTIES

Our principal offices are located in Houston, Texas with the principal offices of our retail affiliates located in Houston, Texas and San Diego, California.

We either lease or own the land upon which our power plants and battery storage facilities are built. We believe that our properties are adequate for our current operations. A description of our power plants is included under Item 1. Business — Description of our Operations.

Item 3.    LEGAL PROCEEDINGS

For a description of our legal proceedings, see Note 16, Commitments and Contingencies of the Notes to Consolidated Financial Statements.

Item 4.    MINE SAFETY DISCLOSURES

Not applicable.

PART II

Item 5.    MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

As of December 31, 2024 and 2023, 952,153 and 952,153 shares of Class A common stock and 48,651 and 47,847 shares of Class B common stock were issued and outstanding, resulting in a total of 1,000,804 and 1,000,000 common shares issued and outstanding, respectively.

Item 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Information

This Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our accompanying Consolidated Financial Statements and related Notes to Consolidated Financial Statements. See the cautionary statement regarding forward-looking statements at the beginning of this Report for a description of important factors that could cause actual results to differ from expected results. See also Item 1A. Risk Factors.

Introduction And Overview

Calpine is America’s largest generator of electricity from natural gas and geothermal resources, according to S&P Global Market Intelligence. We produce and sell electricity, capacity and other related energy products to our customers. We serve commercial and industrial end users, utilities, retail customers and state and regional wholesale market operators. We have a significant presence in major competitive wholesale and retail power markets in California, Texas and the Northeast and Mid-Atlantic regions of the United States. We own approximately 28 GW of power facilities, enough to power approximately 27 million homes, consisting of natural gas, geothermal, solar and battery storage assets. Our Company employs approximately 2,500 people.

We operate four reportable segments:

Significant Events

The following significant events occurred during 2025, 2024 and 2023, as further described within this Management’s Discussion and Analysis and the Consolidated Financial Statements:

2025

Proposed Merger:

On January 10, 2025, the Company announced that it entered into a Merger Agreement with Constellation. The Merger Agreement provides for a series of Reorganization related transactions on terms set forth in the Merger Agreement. As a result of the Reorganization and Merger, Calpine will become an indirect, wholly owned subsidiary of Constellation. Subject to the terms and conditions of the Merger Agreement, Constellation will acquire Calpine in a cash and stock transaction valued at an equity purchase price of approximately $16.4 billion, composed of 50 million shares of Constellation stock and $4.5 billion in cash plus the assumption of approximately $12.7 billion of Calpine net debt. After accounting for cash that is expected to be generated by Calpine between signing and the expected closing date, as well as the value of tax attributes at Calpine, the net purchase price is $26.6 billion. See Note 19 of the Consolidated Financial Statements for additional details relating to the Merger and Item 1A. Risk Factors for a discussion of the risks related to the Merger.

2024

Acquisitions:

Strategic Growth and Operations:

Balance Sheet Management:

2023

Acquisitions:

Strategic Growth and Operations:

Balance Sheet Management:

Market Trends

The power market represents one of the largest industries in the United States and affects nearly every aspect of our economy and lives. The EIA estimated approximately $491 billion in power sales in the United States in 2023. Despite its centrality to the economy, United States power demand has been relatively flat for the past 20 years, growing at a low compounded annual growth rate. However, power demand in the United States is now expected to increase rapidly. This expected increase in power demand can be attributed primarily to three independent factors:

With this expected increase in power demand, we believe that power prices and demand for our products will also increase.

In addition to demand growth, the power industry is undergoing a dramatic shift as the United States increases its focus on lower emissions sources of electricity. Over the past 20 years, the share of electricity generated using coal has fallen from 51% to 16%, while the share generated using gas has increased from 17% to 43% and the share generated by renewables (including hydro, geothermal, wind and solar) has increased from 9% to 21%. These shifts have enabled reductions in power sector carbon dioxide emissions over the same period. The share of electricity from nuclear resources has remained steady at approximately 20%.

Key Operating Metrics

We monitor the following key operating metrics to help us evaluate our business, identify trends affecting our business, formulate business plans and make strategic decisions. We believe the following key metrics provide insight into our generation and battery storage fleet’s ability to provide efficient and reliable power to the market.

MWh Generated — MWh Generated represents the generation and capacity of power plants and battery storage facilities that we consolidate and operate.

Average Availability — Average Availability represents the total hours during the period that our plants were in-service or available for service as a percentage of the total hours in the period.

Average Total Megawatt Hours in Operation — Average Total MWh in Operation indicates the total MWhs of our generation fleet that are operational and available to provide energy to the market.

Average Capacity Factor (excluding peakers) — Average Capacity Factor (excluding peakers) is a measure of total actual power generation and storage as a percent of total potential power generation and storage. It is calculated by dividing (1) total MWh Generated and stored by our power plants and battery storage facilities, excluding peakers, by (2) the product of multiplying (a) the average total MW in operation, excluding peakers, during the period by (b) the total hours in the period.

Steam Adjusted Heat Rate — Heat Rate is a measure of the amount of fuel required to produce a unit of power. Steam Adjusted Heat Rate is the adjusted Heat Rate for our natural gas-fired power plants, excluding peakers. It is calculated by dividing (1) the fuel consumed in Btu reduced by the net equivalent Btu in steam exported to a third party by (2) the KWh generated. We exclude our battery storage facilities from this metric because they do not generate energy. We also exclude our Geysers Assets from this metric because they use steam as a fuel source. Steam Adjusted Heat Rate is a measure of fuel efficiency, so the lower our Steam Adjusted Heat Rate, the lower our cost of generation. The following table presents the operational performance of our retail and generation segments for the years ended December 31, 2024 and 2023.

Market Pricing

Non-GAAP Financial Measures

This Report contains “non-GAAP financial measures," which are numerical measures of financial performance or cash flows that exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with U.S. GAAP. Specifically, we make use of the non-GAAP financial measure “Commodity Margin.” We believe these non-GAAP measures, together with our U.S. GAAP financial measures such as Net income (loss), Gross margin, cash provided by operating activities, are useful to assess our historical and prospective operating performance, to provide meaningful comparisons of operating performance across periods and to better understand trends in our business. These metrics are not necessarily comparable to similarly titled measures reported by other companies.

Commodity Margin is presented as a supplemental measure of operating performance. It is calculated as Commodity revenue less Commodity expense, adjusted to exclude non-recurring and non-cash U.S. GAAP-related items, including, but not limited to, levelization adjustments to revenues required on long-term PPA contracts and non-cash amortization of intangible assets/liabilities associated with contracts recorded at fair value.

Results of Operations December 31, 2024 and 2023

Below are our results of operations for the years ended December 31, 2024 and 2023, respectively, (in millions, except for percentages and operating performance metrics). A discussion regarding our results of operations for the years ended December 31, 2023 and 2022, respectively, can be found under Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations in our Annual Report for the fiscal year ended December 31, 2023, posted on our website at www.calpine.com on March 10, 2024. In the comparative tables below, increases in revenue/income or decreases in expense (favorable variances) are shown without brackets, while decreases in revenue/income or increases in expense (unfavorable variances) are shown with brackets.

We evaluate our Commodity revenue and Commodity expense on a collective basis because the price of power and natural gas tends to move together as the price for power is generally determined by the variable operating cost of the next marginal generator to be dispatched to meet demand. The spread between our Commodity revenue and Commodity expense represents a significant portion of our Commodity Margin. Our financial performance is correlated to how we maximize our Commodity Margin through the management of our portfolio of power plants, as well as our hedging and optimization activities. See additional segment discussion in the section titled Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations: Reportable Segment Results.

Commodity revenue, net of Commodity expense, increased $902 million for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily due to (favorable variances are shown without brackets while unfavorable variances are shown with brackets):

Mark-to-market gain (loss), net from hedging, fuel supply and retail activities had an unfavorable variance of $746 million primarily driven by the mark-to-market gains recognized in 2023 associated with the reversal of unrealized losses recognized in prior periods. This unfavorable variance was partially offset by the increase in value of open positions due to changes in forward market pricing, along with the execution of new transactions.

Other revenue increased $20 million for the year ended December 31, 2024, as compared to the year ended December 31, 2023, primarily due to increased revenues associated with power plant maintenance services provided to third parties and recognition of proceeds received related to a historical sale of legacy wind development projects during the second quarter.

Our normal, recurring operating and maintenance expense, after excluding the effect of scheduled maintenance costs, portfolio changes, performance-based employee compensation and stock-based compensation costs, increased $55 million for the year ended December 31, 2024, as compared to the year ended December 31, 2023. This increase was primarily related to higher salaries and wages related to annual compensation adjustments and backfilling residual open pandemic positions, as well as increased activity related to our ongoing development and construction efforts.

Depreciation and amortization expense increased by $35 million for the year ended December 31, 2024, compared to the year ended December 31, 2023. This change primarily results from newly installed parts associated with normally scheduled maintenance events, depreciation related to the consolidation of Greenfield Energy Center in September 2023, the Quail Run Energy Center acquisition in September 2024, partial completion of the Nova Power Battery Storage Facilities and other ongoing development and construction efforts.

Our normal, recurring general and other administrative expense, after excluding non-recurring compensation costs, increased $14 million for the year ended December 31, 2024, compared to the year ended December 31, 2023. This increase was primarily related to higher consulting and legal costs associated with development and growth project initiatives, as well as higher information technology costs.

(Income) loss from unconsolidated subsidiaries increased $7 million for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily due to gains recognized through September 2023 at our Greenfield Energy Center where we completed the acquisition of the remaining 50% equity ownership interest in Greenfield LP, resulting in the consolidation of the entity effective September 2023.

Interest expense, excluding the effect of non-cash mark-to-market gains and losses, increased $17 million for the year ended December 31, 2024, compared to the year ended December 31, 2023, partially driven by interest expense recognized on the newly executed Nova Power Battery Storage Facilities construction and bridge loan facilities and increased interest expense resulting from the purchase of the remaining 50% ownership interest in our Greenfield Energy Center. Additionally, the unfavorable period-over-period change in non-cash mark-to-market activity of $11 million associated with previously undesignated interest rate swaps that are economic hedges of our interest rate exposure is also recognized within interest expense.

Loss on extinguishment of debt increased $36 million for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily from the refinancing of our First Lien Term Loans in January 2024 and December 2024, and the repricing of our CCFC Term Loan in June 2024.

Other expense, net, decreased $34 million for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily due to higher interest income earnings and a one-time legacy legal reserve recognized during the second quarter of 2023.

During the year ended December 31, 2024, we recorded an income tax expense of $460 million compared to an income tax expense of $542 million for the year ended December 31, 2023. This change is primarily due to lower income from operations in 2024 compared to the prior period.

Results of Operations: Reportable Segment Results

We use Commodity Margin to assess reportable segment performance. Commodity Margin includes revenues recognized on our wholesale and retail power sales activity, electric capacity sales, REC sales, steam sales, realized settlements associated with our marketing, hedging, optimization and trading activity less costs from our fuel and purchased energy expenses, commodity transmission and transportation expenses, environmental compliance expenses and ancillary retail expense. We believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure of profit reviewed by our chief operating decision-maker.

Commodity Margin by Segment for the years ended December 31, 2024 and 2023.

The following tables show our Commodity Margin by segment and related operating performance metrics by regional segment for our wholesale business for the years ended December 31, 2024 and 2023. A discussion of our Commodity Margin by segment for the year ended December 31, 2023, as compared to the same period in 2022, can be found under Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations: Reportable Segment Results for the Years Ended December 31, 2023 and 2022 in our Annual Report for the fiscal year ended December 31, 2023, issued and posted on our website at www.calpine.com on March 10, 2024. In the comparative tables below, favorable variances are shown without brackets, while unfavorable variances are shown with brackets. The MWh generated by the regional segment below represents generation from power plants that we both consolidate and operate. Generation, Average Availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive.

West — The Commodity Margin in our West segment increased by $577 million, or 41%, for the year ended December 31, 2024, compared to 2023. The increase was primarily driven by increased resource adequacy capacity revenues and higher contribution from hedging activity associated with favorable hedged price levels compared to the previous year. Tolling contracts at our Nova Power Battery Storage Facilities also contributed to the increase, particularly in the second half of 2024.

Texas — The Commodity Margin in our Texas segment increased by $163 million, or 16%, for the year ended December 31, 2024, compared to 2023. This increase was primarily driven by higher contribution from hedging activity associated with favorable hedge price levels during the summer period compared to the previous year. These favorable hedging activities mitigated commodity margin from lower market spark spreads compared to the previous year. Additionally, our purchase of the Quail Run Energy Center during September 2024 contributed to higher results.