Constellation Energy (Nasdaq: CEG) completes $22B merger with Calpine

Q: How did Calpine perform financially in 2025 before the Constellation merger?

In 2025, Calpine reported operating revenues of $14.3 billion and net income of $1.97 billion . Operating expenses totaled $11.3 billion , and income from operations was $3.13 billion , highlighting a substantial, profitable generation and retail platform prior to acquisition.

Q: What pro forma financial information did Constellation Energy (CEG) file for the Calpine deal?

Constellation filed unaudited pro forma condensed combined financial statements for CEG Parent and Constellation as of and for the year ended December 31, 2025. These statements, in Exhibit 99.2, show how the combined company’s balance sheet and earnings might look after the Calpine acquisition.

Q: What generating capacity and technologies does Calpine add to Constellation Energy (CEG)?

Calpine brings approximately 28 GW of capacity, including natural gas, geothermal, solar and battery storage assets. Its fleet includes 60 gas-fired plants , a 732 MW geothermal complex at The Geysers, and major storage like the 680 MW Nova battery project in California.

Q: Were any asset divestitures required for Constellation’s acquisition of Calpine?

Yes. Regulatory resolutions required divestitures in PJM and ERCOT , including York 2, Jack Fusco Energy Center, a minority interest in the Gregory Power Plant, and several PJM plants such as Hay Road, Edge Moor, Bethlehem and York 1, to address market overlap concerns.

Q: How is Calpine’s business organized and what markets does it serve?

Calpine operates four segments: West, Texas, East and Retail . It serves wholesale and retail power markets in California, Texas, the Northeast and Mid-Atlantic, selling electricity, capacity, steam and related products to utilities, ISOs, industrials, municipalities and retail customers.

Filing Impact

(High)

Filing Sentiment

(Neutral)

Form Type

8-K

Rhea-AI Filing Summary

Constellation Energy Corporation has completed its acquisition of Calpine, making Calpine an indirect, wholly owned subsidiary. On January 7, 2026, Constellation closed the previously announced merger, with total consideration of approximately $22 billion, consisting of 50 million newly issued Constellation shares and $4.5 billion in cash.

Calpine’s 2025 audited statements show operating revenues of $14.3 billion and net income of $1.97 billion, with a large natural gas and geothermal fleet totaling about 28 GW of capacity. The filing also includes unaudited pro forma condensed combined financials for Constellation and Calpine for 2025, giving investors a view of the combined entity’s performance. Required divestitures in PJM and ERCOT, including several plants such as York 2 and Jack Fusco Energy Center, are noted as part of the regulatory approvals tied to the merger.

Insights

Constellation’s $22B Calpine deal is transformative but its financial impact will depend on integration and market conditions.

The acquisition brings together Constellation and Calpine, adding roughly 28 GW of largely gas and geothermal capacity plus growing battery storage. Calpine generated $14.3 billion in 2025 operating revenues and $1.97 billion in net income, so the acquired platform is sizeable and profitable on a standalone basis.

Regulatory approvals required divestitures in PJM and ERCOT, including assets such as York 2, Hay Road, Edge Moor and the Jack Fusco Energy Center, which slightly reduce the combined footprint in overlapping markets. At the same time, the pro forma combined financials for the year ended December 31, 2025 provide a first look at how the two businesses fit together operationally.

Calpine’s portfolio includes geothermal assets at The Geysers, a large Texas CCGT and cogeneration fleet, and 680 MW of the Nova battery storage project, along with additional storage and solar under construction. Future disclosures in company filings will help clarify synergy realization, capital structure evolution after debt repayments and exchanges, and how data-center and electrification demand trends flow through to earnings.

03/20/2026 - 04:39 PM


			UNITED STATES SECURITIES AND EXCHANGE COMMISSION
			Washington, D.C. 20549
			FORM			8-K

			CURRENT REPORT
			Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
			March 20, 2026
			Date of Report (Date of earliest event reported)

Commission
File Number

Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number

IRS Employer Identification Number

001-41137

CONSTELLATION ENERGY CORPORATION

87-1210716

(a Pennsylvania corporation)

1310 Point Street

Baltimore, Maryland 21231-3380

(833) 883-0162

333-85496

CONSTELLATION ENERGY GENERATION, LLC

23-3064219

(a Pennsylvania limited liability company)

200 Energy Way

Kennett Square, Pennsylvania 19348-2473

(833) 883-0162


Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
☐			Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
☐			Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
☐			Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
☐			Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

CONSTELLATION ENERGY CORPORATION:

Common Stock, without par value

CEG

The Nasdaq Stock Market LLC


Indicate by check mark whether any of the registrants are emerging growth companies as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter). Emerging growth company ☐


If an emerging growth company, indicate by check mark if any of the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Item 8.01. Other Events

On January 7, 2026, Constellation Energy Corporation (Nasdaq: CEG) (“CEG Parent”) and Constellation Energy Generation, LLC, a Pennsylvania limited liability company (“Constellation”) completed the previously announced transactions contemplated by the Agreement and Plan of Merger, dated January 10, 2025 (the “Merger Agreement”), by and among Calpine Corporation, a Delaware corporation (“Calpine”), certain wholly-owned direct and indirect subsidiaries of Calpine and CEG Parent, and Volt Energy Holdings GP, LLC, a Delaware limited liability company, solely in its capacity as the representative of the stockholders of Calpine (the “Merger”). As a result of the transactions contemplated by the Merger Agreement, Calpine was converted into a limited liability company, Calpine LLC, and became an indirect, wholly owned subsidiary of Constellation. In connection with the completion of the Merger, the following financial statements are filed as exhibits hereto:

•The audited consolidated financial statements of Calpine as of December 31, 2025 and 2024 and for the years ended December 31, 2025, 2024 and 2023, and the related notes to the consolidated financial statements, which are filed as Exhibit 99.1 to this Current Report on Form 8-K and are incorporated herein by reference; and

•The unaudited pro forma condensed combined financial statements of CEG Parent and Constellation as of and for the year ended December 31, 2025, and the related notes to the unaudited pro forma condensed combined financial statements, which are filed as Exhibit 99.2 to this Current Report on Form 8-K and are incorporated herein by reference.

The unaudited pro forma condensed combined financial statements give pro forma effect to the acquisition of Calpine. The pro forma financial statements are derived from the historical financial statements of CEG Parent, Constellation and Calpine.

Section 9 - Financial Statements and Exhibits

Item 9.01. Financial Statements and Exhibits

a) Financial statements of business to be acquired

The audited consolidated financial statements of Calpine as of December 31, 2025 and 2024 and for the years ended December 31, 2025, 2024 and 2023, and the related notes to the consolidated financial statements, which are filed as Exhibit 99.1 to this Current Report on Form 8-K and are incorporated herein by reference.

b) Pro forma financial information

The unaudited pro forma condensed combined financial statements of CEG Parent and Constellation as of and for the year ended December 31, 2025, and the related notes to the pro forma combined financial statements, which are filed as Exhibit 99.2 to this Current Report on Form 8-K and are incorporated herein by reference.

(d) Exhibits.


Exhibit No.						Description
23.1						Consent of Deloitte & Touche LLP, independent auditors for Calpine.
23.2						Consent of PricewaterhouseCoopers LLP, independent auditors for Calpine.
99.1						Historical audited financial statements of Calpine as of December 31, 2025 and 2024 and for the years ended December 31, 2025, 2024 and 2023.
99.2						Unaudited pro forma condensed combined financial statements of CEG Parent and Constellation as of and for the year ended December 31, 2025.
101						Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document.
104						The cover page from the Current Report on Form 8-K, formatted as Inline XBRL.

* * * * *

This combined Current Report on Form 8-K is being filed separately by Constellation Energy Corporation and Constellation Energy Generation, LLC, (collectively, the “Registrants”). Information contained herein relating to any individual Registrant has been filed by such Registrant on its own behalf. Neither Registrant makes any representation as to information relating to the other Registrant.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.


			CONSTELLATION ENERGY CORPORATION

			/s/ Shane P. Smith
			Shane P. Smith
			Executive Vice President and Chief Financial Officer


			CONSTELLATION ENERGY GENERATION, LLC

			/s/ Shane P. Smith
			Shane P. Smith
			Executive Vice President and Chief Financial Officer

March 20, 2026

EXHIBIT INDEX


Exhibit No.						Description
23.1						Consent of Deloitte & Touche LLP, independent auditors for Calpine.
23.2						Consent of PricewaterhouseCoopers LLP, independent auditors for Calpine.
99.1						Historical audited financial statements of Calpine as of December 31, 2025 and 2024 and for the years ended December 31, 2025, 2024 and 2023.
99.2						Unaudited pro forma condensed combined financial statements of CEG Parent and Constellation as of and for the year ended December 31, 2025.
101						Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document.
104						The cover page from the Current Report on Form 8-K, formatted as Inline XBRL.

Annual Report for the year ended December 31, 2025 ______________________ 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, 2025 TABLE OF CONTENTS Page Item 1. Business Overview viii Item 2. Financial Statements and Unaudited Supplementary Data 10 Signatures 11 Index of Consolidated Financial Statements 12 i

DEFINITIONS As used in this report for the year ended December 31, 2025 (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. 2026 First Lien Notes Collectively, the $625 million initial aggregate principal amount of 5.25% Senior Secured Notes due 2026, issued May 31, 2016, and the $560 million initial aggregate principal amount of 5.25% Senior Secured Notes due 2026, issued December 15, 2017. 2026 First Lien Term Loans Collectively, the $950 million first lien senior secured term loan, issued April 5, 2019, and the $750 million first lien senior secured term loan, issued August 12, 2019. 2027 First Lien Term Loan The $860 million first lien senior secured term loan, issued December 16, 2020. In January 2024, we amended our 2027 First Lien Term Loan to reduce the applicable margin. 2028 First Lien Notes The $1.250 billion initial aggregate and current outstanding principal amount of 4.50% senior secured notes due 2028, issued December 20, 2019. 2028 Senior Unsecured Notes The $1.400 billion initial aggregate and current outstanding principal amount of 5.125% senior unsecured notes due 2028, issued December 27, 2019. 2029 Senior Unsecured Notes The $650 million initial aggregate and current outstanding principal amount of 4.625% senior unsecured notes due 2029, issued August 10, 2020. 2031 First Lien Term Loans The $1.650 billion first lien senior secured term loans are our legacy 2026 First Lien Term Loans as refinanced in January 2024, and repriced and consolidated in December 2024 extending the maturity date to January 2031. 2031 First Lien Notes The $900 million initial aggregate and current outstanding principal amount of 3.75% senior secured notes due 2031, issued December 16, 2020. 2031 Senior Unsecured Notes The $850 million initial aggregate and current outstanding principal amount of 5.00% senior unsecured notes due 2031, issued August 10, 2020. 2032 First Lien Term Loan The $860 million first lien senior secured term loan is our legacy 2027 First Lien Term Loans as refinanced in December 2024 extending the maturity date to February 2032. AB Assembly Bill Accounts Receivable Sales Program Receivables purchase agreement between Calpine Solutions and Calpine Receivables and the purchase and sale agreement between Calpine Receivables and an unaffiliated financial institution, which together allows for the revolving sale of up to $500 million in certain trade accounts receivables to third parties. AOCI Accumulated Other Comprehensive Income ASC Accounting Standards Codification ASU Accounting Standards Update 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 capacity factor, excluding peakers A measure of total actual power generation as a percent of total potential power generation. It is calculated by dividing (a) total MWh generated by our power plants, excluding peakers, by (b) the product of multiplying (i) the average total MW in operation, excluding peakers, during the period by (ii) the total hours in the period. ABBREVIATION DEFINITION ii

Board of Directors Calpine Corporation Board of Directors Btu British thermal unit(s), a measure of heat content Calpine Receivables Calpine Receivables, LLC, an indirect, wholly-owned subsidiary of Calpine, which was established as a bankruptcy remote, special purpose subsidiary and is responsible for administering the Accounts Receivable Sales Program. Calpine Solutions Calpine Energy Solutions, LLC, an indirect, wholly-owned subsidiary of Calpine, which is a supplier of power to commercial and industrial retail customers in the United States with customers in 18 states, including presence in California, Texas, the mid-Atlantic and the Northeast. CAISO California Independent System Operator is an entity that manages the power grid and operates the competitive power market in California. CAMT Corporate Alternative Minimum Tax CCFC Calpine Construction Finance Company, L.P., an indirect, wholly-owned subsidiary of Calpine. CCFC Term Loan The $1.875 billion first lien senior secured term loan dated December 15, 2017, as amended on June 6, 2024, and September 16, 2024, issued by CCFC and due July 31, 2030. On November 18, 2025, CCFC refinanced to increase the total notional principal amount of the CCFC Term Loan from $1.875 billion to $2.100 billion. CDHI Calpine Development Holdings, LLC (CDHI) is an indirect, wholly-owned subsidiary of Calpine. CDHI Credit Agreement The approximately $1.158 billion aggregate amount letter of credit, reimbursement, and revolving credit agreement dated March 29, 2023 as amended and restated, issued by CDHI Intermediate Holdco, LLC and Calpine York Holdings, LLC. Class A common shares Class of common stock of the Company held by CPN Management, LP. Class A common shares retain all voting rights in relation to Calpine as well as the rights and obligations as specified under the Stockholders Agreement and the Sixth Amended and Restated Certificate of Incorporation of Calpine. Class B common shares Class B common shares have no voting rights in relation to Calpine. The rights and obligations of this class of common shares are specified under the Stockholders Agreement and the Sixth Amended and Restated Certificate of Incorporation of Calpine. Class C common shares Class of common stock of the Company with no current issuances. Class C common shares have no voting rights in relation to Calpine. The rights and obligations of this class of common shares are specified under the Stockholders Agreement and the Sixth Amended and Restated Certificate of Incorporation of Calpine. Cogeneration The use of all or portion of the steam generated in the power generating process to supply a customer with the steam for use in the customer's operations. Commodity expense The sum of our expenses from fuel and purchased energy expense, commodity transmission and transportation expense, environmental compliance expense, ancillary retail expense and realized settlements from our marketing, hedging and optimization activities including natural gas and fuel oil transactions hedging future power sales. Commodity-linked Revolver The $1.786 billion commodity-linked revolving credit facility between Calpine Corporation, as borrower, the lenders parties thereto, MUFG Bank, Ltd., as administrative agent, and MUFG Union Bank, N.A., as collateral agent, dated July 21, 2022, as amended. On July 17, 2025, the agreement was extended through July 2026, and the total commitment amount was decreased from $1.786 billion to $1.646 billion. ABBREVIATION DEFINITION iii

Commodity Margin Commodity Margin is a non-GAAP measure of segment profit or loss under Financial Accounting Standards Board ("FASB") ASC 280, Segment Reporting, utilized by our chief operating decision maker in assessing segment performance and making decisions about allocating resources to specific segments. Commodity Margin is calculated as Commodity revenue less Commodity expense, adjusted to exclude one-time and non-cash 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. Commodity revenue The sum of our revenues recognized on our wholesale and retail power sales activity, electric capacity sales, renewable energy credit ("REC") sales, steam sales and realized settlements from our marketing, hedging, optimization and trading activities excluding natural gas and fuel oil transactions, which are reflected in Commodity expense. Company Calpine Corporation, a Delaware corporation and its subsidiaries Corporate Revolving Facility The approximately $2.500 billion aggregate amount revolving credit facility agreement, dated December 10, 2010, as amended. CPN Management, L.P. CPN Management, L.P., which owns all of the Class A common shares of Calpine Corporation as of December 31, 2025. CSAPR Cross-State Air Pollution Rule DCF Discounted Cash Flow DOJ U.S. Department of Justice EIA Energy Information Administration of the U.S. Department of Energy ERCOT Electric Reliability Council of Texas, which is an entity that manages the flow of electric power to Texas customers representing approximately 90 percent of the state’s electric load. FASB Financial Accounting Standards Board FDIC U.S. Federal Deposit Insurance Corporation FERC U.S. Federal Energy Regulatory Commission First Lien Notes Collectively, the 2026 First Lien Notes, the 2028 First Lien Notes and the 2031 First Lien Notes. First Lien Term Loans Collectively, the 2031 First Lien Term Loan and the 2032 First Lien Term Loans. Geysers Assets Our geothermal power plant assets, including our steam extraction and gathering assets, located in northern California consisting of 13 operating power plants. GPC Geysers Power Company, LLC, an indirect, wholly-owned subsidiary of Calpine GPC Term Loan The $1.771 billion first lien senior secured term loan and $250 million letter of credit facility issued by GPC on June 9, 2020, and subsequently amended on November 9, 2021 and May 31, 2022. Greenfield LP Effective September 5, 2023, Greenfield Energy Centre LP became an indirect, wholly- owned subsidiary of Calpine, as a result of our purchase of the partnership’s outstanding 50% ownership interest from a third party. Prior to September 5, 2023, we owned 50% of the ownership interest of Greenfield LP. Greenfield Term Loan Facility The loan agreement issued by Greenfield LP in 2008, as amended, comprised of a Term Facility of $500 million Canadian dollars ("CAD"), a revolving working capital facility of $48 million CAD, and two other letter of credit facilities. ABBREVIATION DEFINITION iv

Gregory Power Holdings, LLC Gregory Power Holdings, LLC, which owns and operates a 385 MW combined cycle generation facility located in Corpus Christi, Texas. Effective December 29, 2023, Calpine Corporation, through a wholly-owned subsidiary, purchased an investment in Gregory Power Holdings, LLC, with the remaining ownership interest in the entity held by a third party, Gregory Power Investments, LLC. Heat Rate(s) A measure of the amount of fuel required to produce a unit of power. ICE Intercontinental Exchange IESO Independent Electricity System Operator, which operates the electricity market in the province of Ontario, Canada. IRA Inflation Reduction Act of 2022, signed into law on August 16, 2022, created a new corporate alternative minimum tax effective for periods beginning after December 31, 2022, and includes provisions intended to mitigate climate change by, among others, providing tax credit incentives for reductions in greenhouse gas emissions. IRS U.S. Internal Revenue Service ISO(s) Independent System Operator(s), which is an entity that coordinates, controls and monitors the operation of an electric power system. ISO-NE ISO New England Inc., an independent nonprofit regional transmission organization ("RTO") serving states in the New England area, including Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont. ITC Investment Tax Credit KWh Kilowatt hour(s), a measure of power produced, purchased, or sold. LIBOR London Inter-Bank Offered Rate, effective July 1, 2023, all outstanding debt agreements and interest rate instruments priced against LIBOR were converted from LIBOR to SOFR. LTSA(s) Long-Term Service Agreement(s) Lyondell LyondellBasell Industries N.V. MISO Mid-continent ISO, which operates the flow of electricity across the central U.S. MMBtu Million Btu MW Megawatt(s), a measure of plant capacity MWh Megawatt hour(s), a measure of power produced, purchased, or sold NERC North American Electric Reliability Council NOL(s) Net operating loss(es) Nova Power, LLC An indirect, wholly-owned subsidiary of Calpine that is operating the Nova Power Battery Storage Facilities. Nova Credit Agreement A credit agreement issued by Nova Power, LLC on December 21, 2023, comprising of certain credit facilities totaling more than $1.005 billion, including (a) a construction facility in an aggregate principal amount of $655 million, (b) a bridge facility in an aggregate principal amount of $256 million, available until the facility’s investment tax credits are received and (c) letter of credit facilities available to support various obligations with $94 million of total available capacity. The bridge facility was fully repaid in September 2024. The construction facility was converted to a first lien term loan on October 31, 2024. ABBREVIATION DEFINITION v

NPCC Northeast Power Coordinating Council NPNS Normal purchase-normal sale NYISO New York ISO, which operates competitive wholesale markets to manage the flow of electricity across New York. NYMEX New York Mercantile Exchange OCI Other Comprehensive Income OTC Over-the-Counter PJM PJM Interconnection is an RTO that coordinates the movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. PPA(s) Any term power purchase agreement or other contract for a physically settled sale (as distinguished from a financially settled future, option, or swap) of any power product, including power, capacity and/or ancillary services, in the form of a bilateral agreement or a written or oral confirmation of a transaction between two parties to a master agreement, including sales related to a tolling transaction in which the purchaser provides the fuel required by us to generate such power and we receive a variable payment to convert the fuel into power and steam. PUCT Public Utility Commission of Texas REC(s) Renewable energy credit(s) Report This Annual Report for the year ended December 31, 2025, will be available on February 26, 2026. RFC Reliability First Corporation RMR Contract(s) Reliability Must Run contract(s) RTO(s) Regional Transmission Organization(s), which is an entity that coordinates, controls and monitors the operation of an electric power system and administers the transmission grid on a regional basis. Senior Unsecured Notes Collectively, the 2028 Senior Unsecured Notes, the 2029 Senior Unsecured Notes and the 2031 Senior Unsecured Notes. SERC Southeastern Electric Reliability Council SOFR A rate equal to the secured overnight financing rate as administered by the Federal Reserve Bank of New York. Spark Spread(s) The difference between the sales price of power per MWh and the cost of natural gas to produce it. Steam Adjusted Heat Rate The adjusted Heat Rate for our natural gas-fired power plants, excluding peakers calculated by dividing (a) the fuel consumed in Btu, reduced by the net equivalent Btu in steam exported to a third party by (b) the KWh generated. Steam Adjusted Heat Rate is a measure of fuel efficiency, so the lower our Steam Adjusted Heat Rate, the lower our cost of generation. Stockholders Agreement Collectively, the Stockholders Agreement of Calpine Corporation, dated as of March 8, 2018, and the First Amended and Restated Stockholders Agreement of Calpine Corporation, dated as of June 13, 2022, by and between Calpine Corporation and CPN Management, LP, and such other stockholders who become parties thereto from time to time. ABBREVIATION DEFINITION vi

TRE Texas Reliability Entity, Inc. U.S. GAAP Generally accepted accounting principles in the U.S. VAR Value-at-risk VIE(s) Variable interest entity(ies) Volt Merger Merger of Volt Merger Sub, Inc. with and into Calpine under the terms of the Merger Agreement, which was consummated on March 8, 2018. WECC Western Electricity Coordinating Council Winter Storm Uri A winter weather event in Texas during February 2021 that resulted in temperatures well below freezing for more than five days and ERCOT declaring a system emergency and initiating firm load shedding, or blackouts, from February 15, 2021, through February 19, 2021. ABBREVIATION DEFINITION vii

Item 1. BUSINESS OVERVIEW 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: • West: Includes our power plants and battery storage facilities located in California in the CAISO region, as well as our power plants in Arizona and Oregon • Texas: Includes our power plants located in ERCOT • East: Includes our power plants located in PJM, ISO-NE, NYISO, MISO, SERC and the Canadian IESO • Retail: Includes our retail operations throughout the country Significant Events The following significant events occurred during 2025 and 2024: 2025 Merger Agreement and Reorganization: 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 (“CEG Parent”). See Note 5, Acquisitions and Divestitures, for further discussion. The Plan of Merger Agreement provided for, among other things, a series of reorganization-related transactions (the "Reorganization") at Calpine to occur immediately prior to the merger closing date. In accordance with the Plan of Merger Agreement, the Company, among other things, amended and restated its Fifth Amended and Restated Certificate of Incorporation to, among other matters, create and authorize a new class of non-voting common stock denominated as Class C Common Stock and on January 5, 2026, Calpine Corporation converted into a Delaware limited liability company as part of the Reorganization. In addition, immediately prior to the merger effective date, the Company purchased from certain management shareholders a portion of their Calpine stock, thus resulting in Calpine retaining treasury stock prior to merger close. On January 7, 2026, Constellation acquired 100% of the outstanding Calpine equity for a purchase price of approximately $22 billion. The merger consideration consisted of 50 million shares of newly issued Constellation common stock and $4.5 billion in cash. As a result of the merger, Calpine became a wholly-owned subsidiary of Constellation. In connection with certain regulatory approvals required for the transaction, we will divest certain generating assets located in PJM and ERCOT, the only markets where there was a material overlap of generation owned by both companies. In January 2026, we completed the divestiture of our minority ownership interest in the Gregory Power Plant, located in ERCOT, as required under the terms of the resolution with the DOJ associated with the approval of the merger. This resolution was the final regulatory clearance to complete the merger of Calpine and Constellation, which required, among other things, the combined company to divest York 2 (Pennsylvania), the Jack Fusco Energy Center (Texas) and a minority ownership interest in the Gregory Power Plant (Texas). This resolution also incorporated the FERC requirement for Constellation to divest four power plants in PJM (Hay Road, Edge Moor, Bethlehem and York 1). Subsequent to the Constellation merger closing date, Constellation utilizing proceeds from their newly issued bond offering, cash on hand and short-term debt, repaid $2.5 billion in Calpine corporate term loans and $1.25 billion in Calpine senior secured first lien notes. Additionally, in December 2025, Constellation commenced a private exchange offering and related consent solicitations with respect to certain outstanding debt of Calpine. Pursuant to the Exchange Offers, Constellation issued new notes in January 2026 effectively replacing $2.3 billion of Calpine's senior unsecured and secured notes. Constellation dissolved the Calpine Corporate Revolving Facility as well as the Calpine Commodity-Linked Revolving Facility. See Note 19, Subsequent Events, for further discussion of all items noted above. viii

Strategic Growth and Operations: Data Center Origination Transaction Execution • In September 2025, we executed the second phase of our 400 MW power supply agreement with Dallas-based CyrusOne, a leading global data center developer and operator, to serve a new hyperscaler data center development adjacent to the Thad Hill Energy Center in Bosque County, Texas. The new contract adds 210 MW of power to the 190 MW originally announced in July completing a deal that will secure power, grid connection, and land to support the CyrusOne facility. The facility is under construction and expected to be operational by the fourth quarter of 2026. • In February 2026, we executed a new 380 MW power supply agreement with Dallas-based CyrusOne to serve a new data center adjacent to the Freestone Energy Center in Freestone County, Texas. The agreement provides CyrusOne with access to power, grid connectivity and site infrastructure needed to support development of the new facility. Lyondell - Houston Refinery Closing Calpine Channel Energy Center has a long-term steam host agreement with the Lyondell refinery located in the Houston Ship Channel under which Lyondell takes both steam and energy from the Calpine facility for a contractual fee. In the third quarter of 2025, Lyondell continued its previously announced shutdown activities associated with its Houston refinery. With this change, we expect Lyondell to take less steam and electricity under the Energy Sales Agreement (“ESA”). Based on preliminary evaluation, the change in cash flows associated with lower volumes of steam and electricity sold to Lyondell do not have a material effect on the future expected cash flows of Channel and thus the fair value of the facility is not less than Channel’s current carrying value. Accordingly, we have not recognized any impairment loss associated with this event during the year ended December 31, 2025. Battery Storage Facility Commercial Operations The fifth and final phase of our Nova battery storage bank located in Southern California achieved commercial operations during June 2025, bringing the total available capacity of the fully contracted four-hour duration battery facility to 680 MW. North Geysers Development The first installation of producing wells from our North Geysers drilling initiative were placed into service during June 2025, adding an additional 7 MW of generation capacity availability to our Geysers Generation Fleet. The North Geysers development represents an expanded geothermal drilling initiative at our Geysers generation facility expected to add 25 MW of additional generation capacity to the facility upon final completion of the initiative. Balance Sheet Management: • In 2025 we completed multiple financing agreements to continue to manage our liquidity and capital resources. See Note 8, Debt for additional information related to our financing agreements. • In the second quarter of 2025, we drew approximately $62 million against the CDHI Credit Agreement utilized to fund construction of our Pastoria Solar project. • During the second quarter of 2025, the Company received approximately $52 million of investment tax credits associated with the completion of the final phase of our Nova Battery installation as well as the initial phase of our North Geysers geothermal drilling program. Additionally, during the second quarter, the Company sold $55 million in investment tax credits earned on projects. • On October 13, 2025, Pin Oak Creek Energy Center, LLC, an indirect subsidiary of Calpine Corporation, entered into a credit agreement providing for a term loan in the aggregate principal amount of approximately $278 million with the Public Utility of Texas (“PUCT”) as the lender and, U.S. Bank Trust Company, National Association as administrative agent for the lender, pursuant to the Texas Energy Fund (“TEF”). The loan will amortize over a 17- year period beginning in the second quarter of 2029. The proceeds will be used to finance anticipated eligible costs for the development, construction, and installation of the Pin Oak Creek Energy Center, an approximately 460 MW peaking facility located adjacent to Freestone Energy Center in Freestone County, Texas. Total borrowing during the fourth quarter was $229 million. • On July 17, 2025, the Company extended the Commodity-Linked Revolver through July 2026 and decreased the total borrowing base limit from $1.786 billion to $1.646 billion. 1

• On November 18, 2025, CCFC refinanced to increase the total notional principal amount of the CCFC Term Loan from $1.875 billion to $2.100 billion and to reduce the borrowing rate. 2024 Acquisitions: • In September 2024, we completed the purchase of a 100% ownership interest in Quail Run Energy Center, a 550 MW combined cycle, natural gas-fired generation facility located in Odessa, Texas. The purchase price was funded by a portion of the proceeds from the CCFC Term Loan refinancing that closed in September 2024. Strategic Growth and Operations: • Through our integrated business model, we showed strong earnings through December 2024, with strong operations performance of our facilities and incremental value created through our retail and wholesale hedging and marketing activities. • In the second and third quarters of 2024, the Company achieved commercial operations on Phase I and, subsequently, Phases II through IV, respectively, of the Nova Battery Storage Facilities. As a result, 620 MW of the total capacity of the project of 680 MW is currently in operation. Additionally, in September 2024, we, through our wholly-owned subsidiary, completed the sale of certain investment tax credits from the Nova Battery Storage Facilities for a total sales price of approximately $353 million. These proceeds were partially used to repay the outstanding principal on the Nova Bridge Loan of $183 million. • In July 2024, we achieved commercial operations on our Bear Canyon and West Ford Flat Battery Storage Facilities located at the Geysers Assets (“Geysers,” or “The Geysers”). • In July 2024, we signed Phase I agreements with the DOE on our Baytown Energy Center and Sutter Energy Center CCS Projects. • In August 2024, we completed the sale of our investment tax credits related to Johanna Battery Facilities for a total sales price of approximately $23 million. Balance Sheet Management: • In 2024, we completed multiple financing agreements to continue to manage our liquidity and capital resources. See the section titled “Item 7. Management’s Discussion and Team Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” for the fiscal year ended December 31, 2024. • On November 1, 2024, the Company's existing $200 million loan executed under its master securities lending agreement with JPMorgan Chase, N.A. expired. This transaction was reflected as a non-cash transaction in our Consolidated Statements of Cash Flows. • We paid dividends to our stockholders equal to $1.9 billion in the aggregate for the fiscal year ended December 31, 2024. 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 $514 billion in power sales in the United States in 2024. Despite its centrality to the economy, United States power demand has been relatively flat for the past two decades, 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: • Reindustrialization: The American manufacturing industry has grown significantly, propelled by federal domestic content requirements and the promotion of private investment through the CHIPS and Science Act and the IRA. Federal estimates indicate that since 2021, approximately $481 billion in commitments for industrial and manufacturing facilities have been announced, all of which will require significant power. • Electrification: The electrification of transportation, buildings and industry could add to the demand for electricity in the U.S. Electrification of the broader economy, including industrial processes, home heating and others, is also expected to increase power demand. 2

• Growth of Data Centers, including for AI: Significant demand from data centers is expected to support the growth of artificial intelligence. 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 50% to 15%, while the share generated using gas has increased from 18% to 43% and the share generated by renewables (including hydro, geothermal, wind and solar) has increased from 8% to 22%. 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, 2025 and 2024. Year Ended December 31, West Texas East Retail 2025 2024 2025 2024 2025 2024 2025 2024 Production Volumes: (MWh in thousands) MWh Generated1 29,189 31,752 51,769 51,114 40,220 37,974 n/a n/a Average Total MW in Operations1 8,423 8,026 9,729 9,221 9,754 9,774 n/a n/a Availability, Heat Rate, & Capacity Factor: Average Availability 83.9% 85.3% 84.9% 83.0% 85.9% 85.8% n/a n/a Average Capacity Factor, excluding peakers and Geysers 42.0% 47.9% 60.7% 63.1% 55.3% 52.7% n/a n/a Steam Adjusted Heat Factor (Btu/KWh) 7,313 7,374 7,435 7,290 7,617 7,610 n/a n/a Retail Sales Volumes (MW) Average Commercial and Industrial Sales 6,356 5,966 Average Residential Sales 364 332 Average Total Retail Electric Sales Volume 6,720 6,298 3

____________ (1) Average total MW in Operations in our West region includes both generation facility and battery storage facility MW in operation. Battery storage facilities achieved commercial operations primarily in September 2024. Market Pricing Year Ended December 31, 2025 2024 Average Market On-Peak Power Prices ($/MWh)(1): CAISO NP 15 $ 37.38 $ 41.44 ERCOT Houston $ 39.88 $ 35.06 ERCOT North $ 37.33 $ 33.63 PJM West Hub $ 60.09 $ 40.75 ISO-NE $ 75.58 $ 46.59 Natural Gas Prices ($/MMBtu)(2): NYMEX Henry Hub $ 4.45 $ 3.02 PG&E Citygate $ 3.39 $ 3.08 Houston Ship Channel $ 3.01 $ 1.87 TETCOM 3 $ 3.69 $ 2.07 Algonquin Citygate $ 6.27 $ 3.02 Carbon Prices ($/Ton)(2): AB32 Posted Price $ 29.89 $ 38.11 Average Annual On-Peak Market Spark Spread ($/MWh)(3): CAISO NP 15 to PG&E Citygate Spark Spread $ 2.44 $ 5.58 ERCOT Houston to Houston Ship Channel Spark Spread $ 18.79 $ 21.99 ERCOT North to Houston Ship Channel Spark Spread $ 16.23 $ 20.55 PJM West Hub to Tetco M3 Spark Spread $ 28.71 $ 23.19 ISO-NE to Algonquin Spark Spread $ 31.71 $ 25.47 ____________ (1) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized. (2) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us. (3) NP-15 average spark spread calculated as a clean spark using an average 7 heat rate for all periods. PJM and ISO-NE spark spreads exclude the effect of carbon costs given different state participation in each program. 4

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, 17,744 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, 2025, 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 2025 Steam Adjusted Heat Rate of 7,471 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 732 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 2025, our Geysers Assets were responsible for approximately 5% 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 5

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 27,600 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 43 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, 2025, is as follows: • 31% related to leases with the Federal Government via the Bureau of Land Management; • 27% related to leases with the California State Lands Commission; and • 42% related to leases with private landowners/leaseholders. 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 of 10 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. In 2025, the North Geysers Incremental Development Project expanded development across our existing leasehold, bringing an additional 7 MW of geothermal electricity online. We will continue our expansion, bringing an additional 18 MW online in June 2026. 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 89% in 2025. 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, 2025, we have four battery storage projects in California that are fully operational representing 798 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, and the final phase came online in June 2025. We also have 725 MW of conventional steam turbine technology at our Edge Moor Energy Center. 6

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, 2025. SEGMENT/Power Plant NERC Region U.S. State or Canadian Province Technology Calpine Interest Percentage Calpine Net Interest Baseload (MW)(1)(3) Calpine Net Interest With Peaking (MW)(2)(3) 2025 Total MWh Generated(4) WEST Geothermal McCabe #5 & #6 WECC CA Renewable 100% 85 85 648,833 Ridge Line #7 & #8 WECC CA Renewable 100% 77 77 687,418 Calistoga WECC CA Renewable 100% 69 69 454,658 Eagle Rock WECC CA Renewable 100% 71 71 255,163 Big Geysers WECC CA Renewable 100% 61 61 384,838 Lake View WECC CA Renewable 100% 56 56 516,122 Quicksilver WECC CA Renewable 100% 53 53 382,552 Sonoma WECC CA Renewable 100% 53 53 435,646 Cobb Creek WECC CA Renewable 100% 51 51 361,201 Socrates WECC CA Renewable 100% 50 50 343,491 Sulphur Springs WECC CA Renewable 100% 47 47 456,892 Grant WECC CA Renewable 100% 41 41 278,316 Aidlin WECC CA Renewable 100% 18 18 82,366 Natural Gas-Fired Delta Energy Center WECC CA Combined Cycle 100% 860 882 4,145,527 Pastoria Energy Center WECC CA Combined Cycle 100% 780 759 3,620,948 Hermiston Power Project WECC OR Combined Cycle 100% 566 635 2,989,112 Russell City Energy Center(5) WECC CA Combined Cycle 100% 572 619 1,574,872 Otay Mesa Energy Center WECC CA Combined Cycle 100% 513 608 1,629,901 Metcalf Energy Center WECC CA Combined Cycle 100% 584 625 2,338,035 Sutter Energy Center WECC CA Combined Cycle 100% 542 578 1,781,491 Los Medanos Energy Center WECC CA Cogen 100% 518 572 2,485,512 South Point Energy Center WECC AZ Combined Cycle 100% 545 555 2,024,908 Los Esteros Critical Energy Facility WECC CA Combined Cycle 100% 243 309 157,233 Gilroy Energy Center WECC CA Simple Cycle 100% — 141 30,912 Gilroy Cogeneration Plant WECC CA Combined Cycle 100% 109 130 21,084 King City Cogeneration Plant WECC CA Combined Cycle 100% 120 120 24,336 Wolfskill Energy Center WECC CA Simple Cycle 100% — 48 3,929 Yuba City Energy Center WECC CA Simple Cycle 100% — 47 23,431 Feather River Energy Center WECC CA Simple Cycle 100% — 47 35,447 Creed Energy Center WECC CA Simple Cycle 100% — 47 2,560 Lambie Energy Center WECC CA Simple Cycle 100% — 47 4,005 Goose Haven Energy Center WECC CA Simple Cycle 100% — 47 5,359 Riverview Energy Center WECC CA Simple Cycle 100% — 47 12,349 King City Peaking Energy Center WECC CA Simple Cycle 100% — 44 5,438 Agnews Power Plant WECC CA Combined Cycle 100% 28 28 8,578 Battery Storage Facilities Santa Ana I - III(5) WECC CA Battery Storage 100% 80 80 90,362 Nova Battery Power Bank(6) WECC CA Battery Storage 100% 680 680 845,196 Bear Canyon battery storage project(7) WECC CA Battery Storage 100% 13 13 15,112 West Ford Flat battery storage project(7) WECC CA Battery Storage 100% 25 25 25,700 Subtotal 7,510 8,465 29,188,833 7

SEGMENT/Power Plant NERC Region U.S. State or Canadian Province Technology Calpine Interest Percentage Calp ine Net Interest Baseload (MW)(1)(3) Calpine Net Interest With Peaking (MW)(2)(3) 2025 Total MWh Generated(4) TEXAS Deer Park Energy Center TRE TX Cogen 100% 1,116 1,217 7,791,483 Guadalupe Energy Center TRE TX Combined Cycle 100% 1,049 1,040 5,712,182 Baytown Energy Center TRE TX Cogen 100% 810 896 3,815,006 Channel Energy Center TRE TX Cogen 100% 760 845 4,874,895 Pasadena Power Plant(8) TRE TX Cogen/ Combined Cycle 100% 763 781 5,089,392 Thad Hill Energy Center TRE TX Combined Cycle 100% 770 792 4,111,089 Freestone Energy Center TRE TX Combined Cycle 75% 809 776 4,859,935 Magic Valley Generating Station TRE TX Combined Cycle 100% 682 712 2,261,869 Jack A. Fusco Energy Center(14) TRE TX Combined Cycle 100% 523 609 3,645,650 Corpus Christi Energy Center TRE TX Cogen 100% 446 520 2,178,888 Texas City Power Plant TRE TX Cogen 100% 400 453 1,955,541 Hidalgo Energy Center TRE TX Combined Cycle 78.5% 413 395 2,136,374 Quail Run Energy Center TRE TX Combined Cycle 100% 550 550 3,081,401 Gregory Power Plant(9) TRE TX Combined Cycle 43.3% 167 167 255,647 Subtotal 9,258 9,753 51,769,352 EAST Bethlehem Energy Center(10) (14) RFC PA Combined Cycle 100% 960 1,130 5,845,826 Hay Road Energy Center(10) (14) RFC DE Combined Cycle 100% 931 1,130 2,178,938 York 2 Energy Center(10)( 14) RFC PA Combined Cycle 100% 668 828 5,479,898 Morgan Energy Center SERC AL Cogen 100% 720 807 4,801,855 Fore River Energy Center(10) NPCC MA Combined Cycle 100% 750 731 3,105,508 Edge Moor Energy Center(10) (14) RFC DE Steam Cycle 100% — 725 396,465 Granite Ridge Energy Center NPCC NH Combined Cycle 100% 745 695 3,398,440 York Energy Center(10) (14) RFC PA Combined Cycle 100% 464 565 3,305,686 Westbrook Energy Center NPCC ME Combined Cycle 100% 552 552 3,387,934 Greenfield Energy Center NPCC ON Combined Cycle 100% 893 1,088 4,843,568 Zion Energy Center(10) RFC IL Simple Cycle 100% — 503 468,240 Pine Bluff Energy Center SERC AR Cogen 100% 184 215 1,117,709 Cumberland Energy Center(10) RFC NJ Simple Cycle 100% — 191 119,394 Kennedy International Airport Power Plant(10) NPCC NY Cogen N/A 110 125 608,710 Sherman Avenue Energy Center(10) RFC NJ Simple Cycle 100% — 92 43,018 Bethpage Energy Center 3 NPCC NY Combined Cycle 100% 60 80 349,522 Bethpage Power Plant NPCC NY Combined Cycle 100% 55 56 279,643 Christiana Energy Center RFC DE Simple Cycle 100% — 53 813 Bethpage Peaker NPCC NY Simple Cycle 100% — 48 189,702 Stony Brook Power Plant(10) NPCC NY Cogen 100% 45 47 284,604 Tasley Energy Center RFC VA Simple Cycle 100% — 33 2,704 Delaware City Energy Center RFC DE Simple Cycle 100% — 23 171 8

West Energy Center RFC DE Simple Cycle 100% — 20 359 Bayview Energy Center RFC VA Simple Cycle 100% — 12 3,845 Crisfield Energy Center RFC MD Simple Cycle 100% — 10 2,128 Vineland Solar Energy Center RFC NJ Renewable 100% — 4 5,123 Subtotal 7,137 9,763 40,219,803 Total operating power plants and battery storage facilities 79 23,905 27,981 121,177,988 SEGMENT / Power Plant NERC Region U.S. State or Canadian Province Technology Calpine Interest Percentage Calpine Net Interest Baseload (MW)(1)(3) Calpine Net Interest With Peaking (MW)(2)(3) 2025 Total MWh Generated(4) Projects under construction North Geysers Development(11) WECC CA Renewable 100% 18 18 n/a Pastoria Solar Project(12) WECC CA Renewable 100% 105 105 n/a Pin Oak Creek Energy Center, LLC(13) TRE TX Combined Cycle 100% 0 425 n/a Pastoria/BESS Power Storage Project WECC CA Battery Storage 100% 80 80 n/a Total operating power plants, battery storage facilities and projects under construction 24,108 28,609 ____________ (1) Natural gas-fired fleet capacities are generally derived on as-built as-designed outputs, including upgrades, based on site specific annual average temperatures and average process steam flows for cogeneration. (2) Natural gas-fired fleet peaking capacities are primarily derived from as-built-as-designed peaking outputs based on site-specific average summer temperatures and include power enhancement features such as heat recovery steam generator duct-firing, gas turbine power augmentation and/or other power augmentation features. For certain power plants with definitive contracts, capacities at contract conditions have been included. Oil-fired capacities reflect capacity test results. Battery storage capacity is based on installed MW. (3) These outputs do not factor in the typical MW loss and recovery profiles over time, which natural gas-fired turbine power plants display associated with their planned major maintenance schedules. (4) MWh generation for our power generation facilities and capacity for our battery storage facilities is shown here as our net operating interest. (5) The Santa Ana battery storage facility is a four-hour duration battery installation comprised of three phases with a total capacity of 80 MW - phase I for 20 MW/80 MWh, phase II for 20 MW/80 MWh and phase III for 40 MW/160 MWh. (6) The Nova Battery Power Bank is a four-hour duration battery installation comprised of five phases. Phases I-IV reached commercial operation in the second quarter and third quarter of 2024 (620 MW/2,480 MWh) and Phase V reached commercial operation in the second quarter of 2025 (60 MW/240 MWh). (7) The Bear Canyon battery storage facility is a four-hour duration battery installation (13 MW/52 MWh), and West Ford Flat battery storage facility is a four-hour duration battery installation (25 MW/100 MWh). (8) Pasadena comprises 260 MW of CoGen technology and 521 MW of combined cycle (non-CoGen) technology. (9) As of December 31, 2025, Calpine owned a 53.5% non-economic interest and a 43.25% economic interest in Gregory Power Holdings, LLC, an entity that owns a 385 MW combined cycle generation facility in Texas. We entered into an LLC agreement with a third party, who currently owns the remaining 56.75% economic interest in the entity, and we agreed to contribute up to a 45% economic interest in Gregory Power Holdings, LLC over time. (10) These power plants have dual-fuel capability. (11) North Geysers development represents a drilling expansion project expected to increase capacity at our Geysers Assets by 25 MW. During June 2025, we achieved steam flow on the drilling project which resulted in an incremental 7 MW of generation capacity starting in June 2025. (12) Pastoria Solar Project is a solar photovoltaic power-generating facility up to 105 MW and is currently under construction. (13) Pin Oak Creek Energy Center, LLC is a new 425 MW peaking facility that will be adjacent to our Freestone Energy Center and is currently under construction. (14) Bethlehem Energy Center, York Energy Center, Hay Road Energy Center, Edge Moor Energy Center, York 2 Energy Center and Jack A Fusco Energy Center were reclassified to current assets held for sale and current liabilities held for sale in the Consolidated Balance Sheets at December 31, 2025. See Note 5, Acquisitions and Divestitures, for further discussion 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. 9

Item 2. FINANCIAL STATEMENTS AND UNAUDITED SUPPLEMENTARY DATA The information required hereunder is set forth under “Independent Auditor's Reports," “Consolidated Statements of Operations,” “Consolidated Statements of Comprehensive Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Stockholder's Equity,” “Consolidated Statements of Cash Flows” and “Notes to Consolidated Financial Statements” included in the Consolidated Financial Statements that are a part of this Report. 10

SIGNATURES Calpine has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized. CALPINE CORPORATION By: /s/ JEFF KOSHKIN Jeff Koshkin Senior Vice President and Chief Accounting Officer (Principal Financial Officer) Date: February 26, 2026 11

CALPINE CORPORATION AND SUBSIDIARIES INDEX TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2025 Page Independent Auditor's Report ............................................................................................................................................... 13 Independent Auditor's Report ............................................................................................................................................... 15 Consolidated Statements of Operations for the Years Ended December 31, 2025, 2024 and 2023 ..................................... 17 Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2025, 2024 and 2023 ................ 18 Consolidated Balance Sheets at December 31, 2025 and 2024 ............................................................................................ 19 Consolidated Statements of Changes In Stockholders’ Equity for the Years Ended December 31, 2025, 2024 and 2023 . 20 Consolidated Statements of Cash Flows for the Years Ended December 31, 2025, 2024 and 2023 ................................... 21 Notes to Consolidated Financial Statements for the Years Ended December 31, 2025, 2024 and 2023 ............................. 23 12

Report of Independent Auditors To the Management of Calpine LLC Opinion We have audited the accompanying consolidated financial statements of Calpine Corporation and its subsidiaries (the “Company”), which comprise the consolidated balance sheet as of December 31, 2025, and the related consolidated statements of operations, comprehensive income, changes in stockholders’ equity, and cash flows for the year then ended, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the accompanying consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025, and the results of its operations and its cash flows for the year then ended in accordance with accounting principles generally accepted in the United States of America. Basis for Opinion We conducted our audit in accordance with auditing standards generally accepted in the United States of America (US GAAS). Our responsibilities under those standards are further described in the Auditors’ Responsibilities for the Audit of the Consolidated Financial Statements section of our report. We are required to be independent of the Company and to meet our other ethical responsibilities, in accordance with the relevant ethical requirements relating to our audit. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion. Responsibilities of Management for the Consolidated Financial Statements Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; and for the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error. In preparing the consolidated financial statements, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company’s ability to continue as a going concern for one year after the date the consolidated financial statements are available to be issued. Auditors’ Responsibilities for the Audit of the Consolidated Financial Statements Our objectives are to obtain reasonable assurance about whether the consolidated financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditors’ report that includes our opinion. Reasonable assurance is a high level of assurance but is not absolute assurance and therefore is not a guarantee that an audit conducted in accordance with US GAAS will always detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. Misstatements are considered material if there is a substantial likelihood that, individually or in the aggregate, they would influence the judgment made by a reasonable user based on the consolidated financial statements. In performing an audit in accordance with US GAAS, we: • Exercise professional judgment and maintain professional skepticism throughout the audit. • Identify and assess the risks of material misstatement of the consolidated financial statements, whether due to fraud or error, and design and perform audit procedures responsive to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. • Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, no such opinion is expressed. • Evaluate the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluate the overall presentation of the consolidated financial statements. • Conclude whether, in our judgment, there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company’s ability to continue as a going concern for a reasonable period of time. 13

We are required to communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit, significant audit findings, and certain internal control-related matters that we identified during the audit. Other Information Management is responsible for the other information included in the annual report. The other information comprises Business Overview and Unaudited Supplementary Data, but does not include the consolidated financial statements and our auditors’ report thereon. Our opinion on the consolidated financial statements does not cover the other information, and we do not express an opinion or any form of assurance thereon. In connection with our audit of the consolidated financial statements, our responsibility is to read the other information and consider whether a material inconsistency exists between the other information and the consolidated financial statements or the other information otherwise appears to be materially misstated. If, based on the work performed, we conclude that an uncorrected material misstatement of the other information exists, we are required to describe it in our report. PricewaterhouseCoopers LLP Houston, TX February 26, 2026 14

INDEPENDENT AUDITOR'S REPORT To the Board of Directors and Stockholders' of Calpine Corporation Opinion We have audited the consolidated financial statements of Calpine Corporation and subsidiaries (the "Company"), which comprise the consolidated balance sheet as of December 31, 2024, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the two years in the period ended December 31, 2024, and the related notes (collectively referred to as the "financial statements"). In our opinion, the accompanying financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2024 in accordance with accounting principles generally accepted in the United States of America. Basis for Opinion We conducted our audits in accordance with auditing standards generally accepted in the United States of America (GAAS). Our responsibilities under those standards are further described in the Auditor's Responsibilities for the Audit of the Financial Statements section of our report. We are required to be independent of the Company and to meet our other ethical responsibilities, in accordance with the relevant ethical requirements relating to our audits. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion. Responsibilities of Management for the Financial Statements Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America, and for the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error. In preparing the financial statements, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company's ability to continue as a going concern for one year after the date that the financial statements are available to be issued. Auditor’s Responsibilities for the Audit of the Financial Statements Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor's report that includes our opinion. Reasonable assurance is a high level of assurance but is not absolute assurance and therefore is not a guarantee that an audit conducted in accordance with GAAS will always detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. Misstatements are considered material if there is a substantial likelihood that, individually or in the aggregate, they would influence the judgment made by a reasonable user based on the financial statements. In performing an audit in accordance with GAAS, we: • Exercise professional judgment and maintain professional skepticism throughout the audit. • Identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, and design and perform audit procedures responsive to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. • Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control. Accordingly, no such opinion is expressed. 15

• Evaluate the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluate the overall presentation of the financial statements. • Conclude whether, in our judgment, there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company’s ability to continue as a going concern for a reasonable period of time. We are required to communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit, significant audit findings, and certain internal control-related matters that we identified during the audit. Other Information Included in the Annual Report Management is responsible for the other information included in the annual report. The other information comprises the information included in the annual report but does not include the financial statements and our auditor's report thereon. Our opinion on the financial statements does not cover the other information, and we do not express an opinion or any form of assurance thereon. In connection with our audits of the financial statements, our responsibility is to read the other information and consider whether a material inconsistency exists between the other information and the financial statements, or the other information otherwise appears to be materially misstated. If, based on the work performed, we conclude that an uncorrected material misstatement of the other information exists, we are required to describe it in our report. /s/ DELOITTE & TOUCHE LLP Houston, TX February 18, 2025 (December 9, 2025, as to the effects of the adjustment to goodwill discussed in Note 2) 16

CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (in millions) 2025 2024 2023 Operating revenues: Commodity revenue $ 13,534 $ 12,247 $ 11,507 Mark-to-market gain 701 118 2,131 Other revenue 65 69 49 Operating revenues 14,300 12,434 13,687 Operating expenses: Fuel and purchased energy expense: Commodity expense 8,490 7,149 7,311 Mark-to-market loss (gain) 169 (19) 1,248 Fuel and purchased energy expense 8,659 7,130 8,559 Operating and maintenance expense 1,468 1,458 1,353 Depreciation and amortization expense 798 770 735 General and other administrative expense 165 170 168 Other operating expense 215 100 102 Total operating expenses 11,305 9,628 10,917 (Gain) loss on sale of assets, net (127) 13 — (Income) loss from unconsolidated subsidiaries (9) 4 (3) Income from operations 3,131 2,789 2,773 Interest expense 607 584 555 Loss on extinguishment of debt 7 52 16 Other expense, net 66 31 65 Income before income taxes 2,451 2,122 2,137 Income tax expense 478 460 542 Net income $ 1,973 $ 1,662 $ 1,595 Year Ended December 31, The accompanying notes are an integral part of these Consolidated Financial Statements. 17

CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (in millions) Year Ended December 31, 2025 2024 2023 Net income $ 1,973 $ 1,662 $ 1,595 Cash flow hedging activities: (Loss) gain on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income (370) 67 181 Reclassification adjustment for (loss) gain on cash flow hedges realized in net income (100) 165 194 Unrealized actuarial gains arising during period — 4 — Foreign currency translation (loss) gain — (1) 15 Deferred income tax benefit (expense) 117 (59) (94) Other comprehensive (loss) income (353) 176 296 Comprehensive income $ 1,620 $ 1,838 $ 1,891 The accompanying notes are an integral part of these Consolidated Financial Statements. 18

CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (in millions) December 31, 2025 2024 ASSETS Current assets: Cash and cash equivalents ($19 and $38 attributable to VIEs) $ 1,859 $ 706 Accounts receivable, net of allowance of $6 and $12 1,134 1,038 Inventories ($155 and $127 attributable to VIEs) 875 955 Margin deposits and other prepaid expense 116 144 Restricted cash, current ($78 and $140 attributable to VIEs) 261 278 Derivative assets, current 758 579 Current assets held for sale 1,586 — Other current assets ($14 and $15 attributable to VIEs) 30 23 Total current assets 6,619 3,723 Property, plant and equipment, net ($4,185 and $4,033 attributable to VIEs) 11,624 12,579 Restricted cash, net of current portion ($1 and nil attributable to VIEs) 1 1 Investments in unconsolidated subsidiaries 136 77 Long-term derivative assets ($27 and $69 attributable to VIEs) 1,001 559 Intangible assets, net 155 189 Goodwill 242 242 Deferred income tax asset 163 — Other long-term assets ($30 and $73 attributable to VIEs) 381 425 Total assets $ 20,322 $ 17,795 LIABILITIES & STOCKHOLDERS’ EQUITY Current liabilities: Accounts payable $ 1,260 $ 1,132 Accrued interest payable 87 87 Debt, current portion ($194 and $166 attributable to VIEs) 279 355 Derivative liabilities, current 232 316 Current liabilities held for sale 54 — Other current liabilities ($107 and $98 attributable to VIEs) 1,205 1,345 Total current liabilities 3,117 3,235 Debt, net of current portion ($4,194 and $4,132 attributable to VIEs) 12,203 11,807 Deferred income tax liability 1,135 752 Long-term derivative liabilities 447 388 Other long-term liabilities 814 629 Total liabilities 17,716 16,811 Commitments and contingencies (see Note 16) Stockholders’ equity: Common stock (see Note 14) Class A shares: par value $.001; number of shares authorized at December 31, 2025 - 1,400,000 and December 31, 2024 - 1,200,000; number of shares issued and outstanding at at December 31, 2025 - 952,153 and December 31, 2024 - 952,153 Class B shares: par value $.001; number of shares authorized at December 31, 2025 - 200,000 and December 31, 2024 - 200,000; number of shares issued and outstanding at December 31, 2025- 48,654 and December 31, 2024 - 48,651 Class C shares: par value $.001; number of shares authorized at December 31, 2025 - 200,000 and December 31, 2024 - nil; number of shares issued and outstanding at December 31, 2025 - nil and December 31, 2024 - nil — — Additional paid-in capital 9,933 9,931 Accumulated deficit (6,865) (8,838) Accumulated other comprehensive loss (462) (109) Total stockholders’ equity 2,606 984 Total liabilities and stockholders’ equity $ 20,322 $ 17,795 The accompanying notes are an integral part of these Consolidated Financial Statements. 19

CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (in millions) Common Stock Treasury Stock Additional Paid-In Capital Accumulated Deficit Accumulated Other Comprehensive Loss Total Stockholders’ Equity Balance, December 31, 2022 $ — $ — $ 9,911 $ (8,493) $ (581) $ 837 Stock-based compensation (Note 15) — — 18 — — 18 Dividends — — — (1,703) — (1,703) Net income — — — 1,595 — 1,595 Other comprehensive income — — — — 296 296 Balance, December 31, 2023 $ — $ — $ 9,929 $ (8,601) $ (285) $ 1,043 Stock-based compensation (Note 15) — — 2 — — 2 Dividends — — — (1,899) — (1,899) Net income — — — 1,662 — 1,662 Other comprehensive income — — — — 176 176 Balance, December 31, 2024 $ — $ — $ 9,931 $ (8,838) $ (109) $ 984 Stock-based compensation (Note 15) — — 2 — — 2 Net income — — — 1,973 — 1,973 Other comprehensive loss — — — — (353) (353) Balance, December 31, 2025 $ — $ — $ 9,933 $ (6,865) $ (462) $ 2,606 The accompanying notes are an integral part of these Consolidated Financial Statements. 20

CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions) Year Ended December 31, 2025 2024 2023 Cash flows from operating activities: Net income $ 1,973 $ 1,662 $ 1,595 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization(1) 829 811 781 Loss on extinguishment of debt 7 38 10 Gain on sale of Bosque land (117) — — Deferred income taxes 330 338 494 Proceeds from sale of ITC 53 377 — Mark-to-market activities, net (512) (107) (864) (Income) loss from unconsolidated subsidiaries (9) 4 (3) Stock-based compensation expense 2 2 18 Other (45) 24 56 Change in operating assets and liabilities: Accounts receivable 35 12 1,670 Accounts payable and accrued expenses 237 12 (1,527) Margin deposits and prepaid expenses 1 (46) 296 Other assets and liabilities, net (139) 228 (227) Derivative instruments, net (594) 216 227 Net cash provided by operating activities 2,051 3,571 2,526 Cash flows from investing activities: Purchases of property, plant and equipment (1,149) (1,104) (908) Acquisition of Power plants, net of cash acquired, and other — (340) (51) Cash receipt from sale of York's transmission line 16 — — Cash contributions to Gregory Power Holdings, LLC (84) (44) — Other 2 — 19 Net cash used in investing activities (1,215) (1,488) (940) Cash flows from financing activities: Borrowings under CCFC Term Loan and First Lien Term Loans 216 798 296 Repayments of CCFC Term Loan, Corporate First Lien Term Loan and Corporate First Lien Notes (140) (291) (305) Borrowings under revolving facilities 517 200 952 Repayments of borrowings under revolving facilities (116) (342) (1,438) Borrowings under construction loan facilities, project financing, notes payable and other — 477 549 Repayments of borrowings under construction loan facilities, project financing, notes payable and other (173) (341) (157) Debt issuance costs 4 (36) (38) Dividends paid — (1,899) (1,703) Other (7) (12) (17) Net cash provided by (used in) financing activities 301 (1,446) (1,861) Net increase (decrease) in cash, cash equivalents and restricted cash 1,137 637 (275) Cash, cash equivalents and restricted cash, beginning of period 985 348 623 Cash, cash equivalents and restricted cash, end of period(3) $ 2,122 $ 985 $ 348 The accompanying notes are an integral part of these Consolidated Financial Statements. 21

CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS — (Continued) (in millions) Year Ended December 31, 2025 2024 2023 Cash paid during the period for: Interest, net of amounts capitalized $ 546 $ 516 $ 489 Income taxes $ 107 $ 88 $ 46 Supplemental disclosure of non-cash investing and financing activities: Capital expenditures included in accounts payable and other assets and liabilities, net $ 188 $ 327 $ 206 Contribution to Calpine Receivables, LLC $ — $ 15 $ — Capital expenditures transferred from other assets to property, plant and equipment(2) $ (246) $ (137) $ (224) Recognition of loans related to master securities lending transaction $ — $ — $ 95 Extended maturity of loans related to master securities lending transaction $ — $ — $ (95) Maturity of loans related to JPM Master Securities Lending Agreement $ — $ (200) $ — Initial recognition of asset retirement obligation asset and liability $ 49 $ 53 $ 14 Recognition of investment tax credits related to battery storage facilities $ — $ 57 $ — ___________ (1) Includes amortization recorded in commodity revenue and commodity expense in the Consolidated Statements of Operations associated with intangible assets amortization. Additionally, includes amortization of debt issuance costs and discounts recorded in interest expense in the Consolidated Statements of Operations. (2) Deposit and milestone payments made for property, plant and equipment prior to the acquisition of the fixed asset are initially recognized within other assets in our Consolidated Balance Sheets and as a cash outflow within operating activities in our Consolidated Statements of Cash Flows. These amounts are subsequently transferred from other assets to property, plant and equipment, net in our Consolidated Balance Sheets when the property, plant and equipment is acquired by the Company and are not included within the cash flows from investing activities section of our Consolidated Statements of Cash Flows. (3) Our cash and cash equivalents, restricted cash, current and restricted cash, net of current portion are stated as separate line items on our Consolidated Balance Sheets. The accompanying notes are an integral part of these Consolidated Financial Statements. 22

CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Organization and Operations Calpine Corporation (“Calpine” or “the Company”), a Delaware corporation, is one of the largest power generators in the U.S. measured by power produced. Calpine owns and operates primarily natural gas-fired, geothermal and battery storage power plants in North America and has a significant presence in major competitive wholesale and retail power markets in California, Texas, and the Northeast and Mid-Atlantic regions of the U.S. The Company sells power, steam, capacity, REC(s) and ancillary services to its customers. The Company's wholesale customer base includes but is not limited to utilities, power marketers, retail power providers, municipalities, community choice aggregators, independent electric system operators, industrial companies and other governmental entities. Additionally, through Calpine's retail brands, retail energy and related products are marketed to commercial, industrial, governmental and residential customers. The Company continues to focus on providing products and services that are beneficial to wholesale and retail customers. The Company primarily purchases natural gas and fuel oil as fuel for its power plants and engages in related natural gas transportation and storage transactions. The Company also purchases power and related products for sale to customers and purchases electric transmission rights to deliver power to customers. Consistent with internal risk management policy, the Company executes natural gas, power, environmental products, fuel oil and other physical and financial commodity contracts to hedge certain business risks and optimize the portfolio of power plants. 2. Summary of Significant Accounting Policies Basis of Presentation and Principles of Consolidation The Company's Consolidated Balance Sheets as of December 31, 2025 and 2024, the related Consolidated Statements of Operations, Consolidated Statements of Comprehensive Income, Consolidated Statements of Stockholder's Equity and Consolidated Statements of Cash Flows for the years ended December 31, 2025, 2024, and 2023 and the related notes (collectively referred to as the “Consolidated Financial Statements,” and “financial statements”) have been prepared in accordance with generally accepted accounting principles in the U.S. (“U.S. GAAP,” and “GAAP”) and include the accounts of all majority-owned subsidiaries that are not variable interest entities (“VIEs”) and all VIEs where it was determined the Company is the primary beneficiary. All significant intercompany transactions and balances have been eliminated in consolidation. Equity Method Investments and Investments without readily determinable fair value — The Company uses the equity method or other method of accounting to record net interests in entities where it was determined that the Company does not control the investment and is not the primary beneficiary, which as of December 31, 2025, includes Gregory Power Holdings, LLC, and Calpine Receivables, LLC (“Calpine Receivables”). Calpine Receivables, an indirect, wholly-owned subsidiary of Calpine, was established as a bankruptcy-remote, special purpose subsidiary responsible for administering the Accounts Receivable Sales Program. For the equity method investments, the Company's share of net income (loss) is calculated according to its equity ownership percentage or according to the terms of the applicable agreements. The Company's investments without a readily determinable fair value are not material as of December 31, 2025. See Note 7, Variable Interest Entities and Unconsolidated Investments for further discussion of VIEs and unconsolidated investments. Jointly-Owned Plants — Certain of Calpine's subsidiaries own undivided interests in jointly-owned plants. These plants are maintained and operated pursuant to their joint ownership participation and operating agreements. The Company is responsible for its subsidiaries’ share of operating costs and direct expenses and includes its proportionate share of the facilities and related revenues and direct expenses in these jointly-owned plants in the corresponding balance sheet and income statement captions of the Consolidated Financial Statements. The following table summarizes the proportionate ownership interest held in jointly-owned power plants (in millions, except percentages): As of December 31, 2025 Ownership Interest Property, Plant & Equipment Accumulated Depreciation Construction in Progress Freestone Energy Center 75.0 % $ 364 $ (164) $ — Hidalgo Energy Center 78.5 % $ 252 $ (107) $ — 23

As of December 31, 2024 Ownership Interest Property, Plant & Equipment Accumulated Depreciation Construction in Progress Freestone Energy Center 75.0 % $ 367 $ (170) $ — Hidalgo Energy Center 78.5 % $ 249 $ (100) $ (1) Use of Estimates in Preparation of Financial Statements The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Actual results could differ from those estimates. Fair Value of Financial Instruments and Derivatives See Note 8, Debt, for disclosures regarding the fair value of debt instruments and Note 9, Assets and Liabilities with Recurring Fair Value Measurements, for disclosures regarding the fair values of derivative instruments and related margin deposits and certain of cash balances. Concentrations of Credit Risk Financial instruments that potentially subject the Company to credit risk consist of cash and cash equivalents, restricted cash, accounts and notes receivable, as well as derivative financial instruments. Certain of cash and cash equivalents, as well as restricted cash balances, are invested in money market accounts with investment banks that are not U.S. Federal Deposit Insurance Corporation (“FDIC”) insured. The Company places its cash and cash equivalents and restricted cash in what it believes to be creditworthy financial institutions and certain of its money market accounts agencies to invest in United States (“U.S.”) Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies, or instrumentalities. Additionally, the Company actively monitors the credit risk of its counterparties and customers, including receivable, commodity and derivative transactions. The Company's accounts and notes receivable are concentrated within entities engaged in the energy industry, mainly within the United States. Generally, we have not collected collateral for accounts receivable from utilities and end-user customers; however, the Company may require collateral in the future. For financial and commodity derivative counterparties and customers, the Company evaluates the net accounts receivable, accounts payable and fair value of commodity contracts. The Company may require security deposits, cash margin or letters of credit to be posted if the exposure reaches a certain level or their credit rating declines. The Company's counterparties and customers primarily consist of four categories of entities that participate in the energy markets: • financial institutions and trading companies; • regulated utilities, municipalities, cooperatives, independent system operators (“ISOs”) and other retail power suppliers; • oil, natural gas, chemical, and other energy-related industrial companies; and • commercial, industrial and residential retail customers. The Company has concentrations of credit risk with a few of its wholesale counterparties and retail customers relating to its sales of power and steam and hedging, optimization and trading activities. The Company has exposure to trends within the energy industry, including declines in the creditworthiness of the counterparties and customers for the commodity and derivative transactions. Certain Company counterparties and customers within the energy industry have below-investment- grade credit ratings. The risk control group manages counterparty and customer credit risk and monitors the net exposure with each counterparty or customer daily. The analysis is performed on a mark-to-market basis using forward curves. The net exposure is compared against a credit risk threshold. This threshold is determined based on each counterparty's and customers' credit rating and evaluation of their financial statements. We use these thresholds to determine if additional collateral or restriction of activity with the counterparty or customer is needed. We believe that the credit policies and portfolio of transactions adequately monitor and diversify the credit risk. The wholesale counterparties and retail customers are performing and financially settling in a timely manner according to their respective agreements. 24

Cash and Cash Equivalents The Company considers all highly liquid investments with an original maturity of three months or less as cash and cash equivalents. The Company has cash and cash equivalents held in non-corporate accounts for certain project finance facilities and lease agreements that require the Company to establish and maintain segregated cash accounts. These accounts have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit are limited from time to time based on the status of the project. Restricted Cash Certain Company debt agreements, lease agreements or other agreements require us to establish and maintain segregated cash accounts, the use of which is restricted, making these cash funds unavailable for general use. These amounts are held by depository banks to comply with the contractual provisions requiring reserves for payments such as debt service, rent and major maintenance or with applicable regulatory requirements. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents in the Consolidated Balance Sheets. The table below represents the components of the restricted cash as of December 31, 2025 and 2024 (in millions): December 31, 2025 2024 Current Non- Current Total Current Non- Current Total Construction/major maintenance $ 90 $ — $ 90 $ 140 $ — $ 140 Security/project/insurance 164 — 164 133 — 133 Other 7 1 8 5 1 6 Total $ 261 $ 1 $ 262 $ 278 $ 1 $ 279 Cash and Cash Equivalents and Restricted Cash The following table provides a reconciliation of cash and cash equivalents and restricted cash reported in the Consolidated Statements of Cash Flows to the total of the same amounts reported in the Consolidated Balance Sheets as of December 31, 2025 and 2024 (in millions): December 31, 2025 2024 Cash and cash equivalents $ 1,859 $ 706 Restricted cash included in current and non-current assets 262 279 Total cash and cash equivalents and restricted cash $ 2,121 $ 985 Business Interruption Proceeds The Company records business interruption insurance proceeds when amounts are realizable. We recorded approximately nil, nil and $39 million of business interruption proceeds in operating revenues for the years ended December 31, 2025, 2024 and 2023. Business interruption proceeds recognized in 2023 are related to extended outages at several facilities, including the Geysers and the Pasadena Cogeneration facility. Accounts Receivable, Net and Accounts Payable Accounts receivable and accounts payable represent amounts due from customers and amounts owed to vendors, suppliers and creditors for goods and services received, respectively. Accounts receivables are recorded at invoiced amounts, net of reserves and allowances, and do not bear interest as the balances are short-term in nature. We use a variety of information to determine our allowance for expected credit losses based on multiple factors, including the length of time receivables are past due, current and future economic trends and conditions affecting our customer base, significant one-time events, historical write-off experience and forward-looking information, such as internally developed forecasts. Allowance for expected credit losses totaled $6 million and $12 million as of December 31, 2025 and 2024, respectively. The accounts receivable and payable balances also include settled but unpaid amounts relating to our marketing, hedging and optimization activities. These receivables and payables with individual counterparties are subject to master netting arrangements whereby we legally have a 25

right of offset and settle the balances net. However, for balance sheet presentation purposes and to be consistent with the way we present the majority of amounts related to marketing, hedging and optimization activities on our Consolidated Statements of Operations, we present our receivables and payables on a gross basis. We do not have any significant off-balance sheet credit exposure related to our customers. Inventory Inventory primarily consists of spare parts, stored natural gas and fuel oil, environmental products and natural gas exchange imbalances. Other than spare parts, inventory is stated primarily at the lower of cost or net realizable value under the weighted average cost method. Spare parts inventory is valued at weighted average cost and is expensed to operating and maintenance expense or capitalized to property, plant and equipment as the parts are used and consumed. Collateral The Company uses margin deposits, prepayments and letters of credit as credit support for commodity procurement and risk management activities with and from our counterparties and customers. Calpine has granted priority liens on the Company’s assets, as collateral in accordance with power and natural gas agreements, under the 2026 First Lien Notes, 2028 First Lien Notes and 2031 First Lien Notes (collectively, the “First Lien Notes”), our 2032 First Lien Term Loan and 2031 First Lien Term Loan (collectively, the “First Lien Term Loans”) and Corporate Revolving Facility. These agreements qualify as “Eligible Commodity Hedge Agreements” under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. The first priority liens have been granted in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to our counterparties under such agreements. The counterparties under such agreements would ratably share the benefits of the collateral subject to such first priority liens with the lenders under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. Interest rate hedging instruments are related to project financings collateralized by first-priority liens on the underlying assets. See Note 11, Use of Collateral, for further discussion. Property, Plant and Equipment, Net Property, plant and equipment is stated at cost. The Company capitalizes costs incurred in connection with the construction of power plants and battery storage facilities, the development of geothermal properties and the refurbishment of major turbine generator equipment. When capital improvements to leased power plants meet the Company's capitalization criteria, they are capitalized as leasehold improvements and amortized over the shorter term of the lease or the economic life of the capital improvement. The Company expenses maintenance costs when the service performed does not meet the capitalization criteria. The Company's current capital expenditures at its' geothermal power plant assets, including steam extraction and gathering assets, located in northern California include those incurred for proven reserves and reservoir replenishment (primarily water injection), pipeline and power generation assets and drilling of “development wells” as all drilling activity has been performed within the known boundaries of the steam reservoir. Significant additions or improvements extending asset lives are capitalized as incurred, while repairs and maintenance that do not improve or extend the life of the respective asset are charged to expense as incurred. The Company purchased our Geysers Assets as a proven steam reservoir and all well costs, except well workovers and routine repairs and maintenance, have been capitalized since its purchase date. The Company depreciates assets under the straight-line method over the shorter of the useful life or the lease term. For natural gas-fired power plants, an estimated salvage value that approximates 10.0% of the depreciable cost basis is used on power plants the Company has full ownership or has favorable option to purchase at the end of lease term. For Geysers Assets, no salvage value is used. A de minimis amount of the depreciable costs basis is used for componentized equipment. The component depreciation method is used for natural gas-fired power plant rotable parts, certain componentized balance of plant parts, and information technology equipment. The composite depreciation method is used for other natural gas-fired power plant asset groups and Geysers Assets. Under the composite depreciation method, upon asset normal retirement the costs of assets are retired against accumulated depreciation, and no gain or loss is recorded. For retirement of assets under the component depreciation method, the costs and related accumulated depreciation are removed from Consolidated Balance Sheets, and any gain or loss is recognized as operating and maintenance expense in the Consolidated Statements of Operations. 26

Goodwill and Intangible Assets In accordance with ASC 350, Intangibles—Goodwill and Other (“ASC 350”), the Company recognizes goodwill for the excess cost of an acquired entity over the net value assigned to assets acquired and liabilities assumed. Goodwill represents the excess of the purchase price over the fair value of the net assets acquired at acquisition. The carrying amount of goodwill is assessed for impairment annually each third quarter and when events or changes in circumstances indicate the carrying value of the goodwill and/or intangible asset is not in excess of fair value. The annual goodwill impairment assessment is performed at the reporting unit level, which is identified as one level below the Company’s operating segments for which discrete financial information is available. The assessment includes a review of qualitative factors, including industry and market considerations, overall financial performance and other relevant events and factors that affected the reporting unit. For reporting units in which the impairment assessment concludes that it was more-likely-than-not that the fair value was less than its carrying value, we perform the quantitative goodwill impairment test, which compares the fair value of the reporting unit to its carrying value. If the fair value of the reporting unit exceeds the carrying value of the net assets assigned to that unit, goodwill is not considered impaired and we are not required to perform additional analysis. If the carrying value of the net assets assigned to the reporting unit exceeds the fair value of the reporting unit, then we will record an impairment loss equal to the difference not to exceed the goodwill balance assigned to the reporting unit. Management performed the qualitative annual impairment test and determined a quantitative test was unnecessary. Goodwill resulted from the acquisition of the Company's Retail business. As such, the goodwill balance was allocated to the Retail segment. The Company did not record any changes in the carrying value of our goodwill as of December 31, 2025 and 2024. As of December 31, 2025 and 2024, the Company's goodwill is $242 million and $242 million, respectively. The Company traditionally has elected the private company option to amortize intangible goodwill balances. In January 2025, pursuant to SEC Regulation S-X Rule 3-05 for financial statements of businesses acquired or to be acquired, as a result of the Plan of Merger (the “Plan of Merger Agreement”) with Constellation Energy Corporation, the Company has reinstated all goodwill balances to the initially recorded amount of $242 million effective for annual and interim reporting periods during the twelve month period ending December 31, 2025. This change resulted in the adjustment to accumulated amortization of approximately $73 million for all comparable prior year periods. The Company recognizes intangible assets, such as acquired contracts, customer relationships and trademark and trade names, at their estimated fair values at acquisition. All available information is used to estimate fair values, including quoted market prices, and other widely accepted valuation techniques. Certain estimates and judgments are required in the application of the methods used to measure the fair value of our intangible assets, including estimates of future cash flows, selling prices, replacement costs, economic lives and the selection of a discount rate, which are not observable in the market and represent a Level 3 measurement. All recognized intangible assets consist of rights and obligations with finite lives. Intangible assets components were as follows (in millions): December 31, 2025 2024 Lives Customer relationships $ 356 $ 356 3-14 Years Trademark and trade name 40 40 15 Years Other(1) 25 26 4-33 Years 421 422 Less: Accumulated amortization (266) (233) Intangible assets, net $ 155 $ 189 ______ (1) The Other category includes approximately $8 million and $8 million as of December 31, 2025 and 2024, respectively, associated with the fair value of a power purchase agreement (“PPA”) contract acquired in the Greenfield L.P. acquisition and $10 million and $10 million as of December 31, 2025 and 2024, respectively, related to an acquired interconnection agreement for a battery storage project. Amortization expense related to intangible assets for the years ended December 31, 2025, 2024 and 2023 was $34 million, $31 million, and $29 million, respectively. The estimated aggregate amortization expense of intangible assets for the next five years is as follows (in millions): 27

2026 $ 34 2027 33 2028 29 2029 28 2030 26 Impairment Evaluation of Long-Lived Assets (Including Goodwill, Intangibles and Investments) Long-lived assets, such as property, plant and equipment, equity method investments and finite-lived intangible assets are evaluated for impairment when events or changes in circumstances indicate that the carrying value of such assets may be unrecoverable. Equipment assigned to each power plant is not evaluated for impairment separately; instead, operating power plants and related equipment are evaluated as a whole unit. When an impairment condition occurs, an impairment loss estimate is calculated using undiscounted future cash flows associated with a long-lived asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities for long-lived assets that are expected to be held and used. The Company's multi-year forecast is prepared using a fundamental long-term view of the power market based on long-term production volumes, price curves and operating costs together with the regulatory and environmental requirements within each individual market. Power sales are managed and marketed as a portfolio rather than at the individual power plant or customer level within each designated market, pool or segment. As a result, power plants are grouped based on the corresponding market for valuation purposes. If it is determined that the undiscounted cash flows from an asset or group of assets to be held and used are less than the associated carrying amount, or if an asset has been classified as held for sale, the fair value must be estimated to determine the amount of any impairment loss. The carrying amount of goodwill is assessed for impairment annually each third quarter and when events or changes in circumstances indicate the carrying value of the goodwill and/or intangible asset is not in excess of fair value. The annual goodwill impairment assessment is performed at the reporting unit level, which is identified as one level below the Company’s operating segments for which discrete financial information is available. The assessment includes a review of qualitative factors, including industry and market considerations, overall financial performance, and other relevant events and factors that affected the reporting unit. For reporting units in which the impairment assessment concludes that it was more-likely-than-not that the fair value was less than its carrying value, we perform the quantitative goodwill impairment test, which compares the fair value of the reporting unit to its carrying value. If the fair value of the reporting unit exceeds the carrying value of the net assets assigned to that unit, goodwill is not considered impaired and we are not required to perform additional analysis. If the carrying value of the net assets assigned to the reporting unit exceeds the fair value of the reporting unit, then we will record an impairment loss equal to the difference not to exceed the goodwill balance assigned to the reporting unit. No impairment was recorded for our goodwill for the years ended December 31, 2025, 2024 and 2023. All construction and development projects are reviewed for impairment whenever there is an indication of potential reduction in fair value. If it is determined that a construction or development project is no longer probable of completion and the capitalized costs will not be recovered through future operations, the carrying value of the project will be written down to its fair value. To estimate future cash flows, historical cash flows, existing contracts, capacity prices PPAs, changes in the market environment and other factors are used which may affect future cash flows. To the extent applicable, the assumptions used are consistent with internally generated forecasts that, (for example, are used in preparing earnings forecasts). The use of this method involves inherent uncertainty. Best estimates are used in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in these estimates, and the effect of such variations could be material. When it is determined that assets meet the assets held-for-sale criteria, they are reported at the lower of carrying amount or fair value, less the cost to sell. Equity method investments are also evaluated to determine whether or not they are impaired when the value is considered an “other than a temporary” decline in value. Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. Estimated, discounted future cash flows are used which employ single interest rate representative of the risk involved with the asset, including contract terms, tenor and credit risk of counterparties. Factors considered also include prices of similar assets, consultations with brokers or employment of other valuation techniques. Best estimates are used in these evaluations which consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. 28

However, actual future market prices and project costs could vary from the assumptions used in estimates, and the effect of such variations could be material. No impairment losses were recorded for the years ended December 31, 2025, 2024 and 2023. Assets Held For Sale The Company classifies assets and liabilities to be sold (disposal group) as held for sale in the period in which all of the following criteria are met: (1) management, having the authority to approve the action, commits to a plan to sell the disposal group; (2) the disposal group is available for immediate sale in its present condition subject only to terms that are usual and customary for sales of such disposal groups; (3) an active program to locate a buyer and other actions required to complete the plan to sell the disposal group have been initiated; (4) the sale of the disposal group is probable, and transfer of the disposal group is expected to qualify for recognition as a completed sale within one year, except if events or circumstances beyond the Company’s control extend the period of time required to sell the disposal group beyond one year; (5) the disposal group is being actively marketed for sale at a price that is reasonable in relation to its current fair value; and (6) actions required to complete the plan indicate that it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn. The Company initially measures an asset that is classified as held for sale at the lower of its carrying value or fair value less any costs to sell. Any loss resulting from this measurement is recognized in the period in which the held for sale criteria are met. Conversely, gains are not recognized on the sale of an asset until the date of sale. The Company assesses the fair value of an asset, less any costs to sell, each reporting period it remains classified as held for sale and reports any subsequent changes as an adjustment to the carrying value of the asset, as long as the new carrying value does not exceed the carrying value of the asset at the time it was initially classified as held for sale. Additionally, depreciation and amortization is not recorded during the period in which the long-lived assets are classified as held for sale. Upon determining that an asset meets the criteria to be classified as held for sale, the Company reports the assets and liabilities, if material, in current assets held for sale and current liabilities held for sale in the Consolidated Balance Sheets. Accrued Compensation As of December 31, 2025 and 2024, $317 million and $313 million were recorded, respectively. This balance is included in other current liabilities on the Consolidated Balance Sheets. Current Environmental Liability As of December 31, 2025 and 2024, we recognized a current liability of $267 million and $470 million, respectively, associated with renewable portfolio standard and emission obligations in accordance with regulatory compliance programs. This balance is included in other current liabilities on the Consolidated Balance Sheets. Asset Retirement Obligation The Company accounts for Asset Retirement Obligations (“AROs”) in accordance with ASC 410-20, Asset Retirement Obligations, or ASC 410-20. Retirement obligations associated with long-lived assets included within the scope of ASC 410-20 are those for which a legal obligation exists under enacted laws, statutes, and written or oral contracts, including obligations arising under the doctrine of promissory estoppel, and for which the timing and/or method of settlement may be conditional on a future event. ASC 410-20 requires an entity to recognize the fair value of a liability for an ARO in the period in which it is incurred, and a reasonable estimate of fair value can be made. Upon initial recognition of a liability for an ARO, the Company capitalizes the asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. As of December 31, 2025 and 2024, the asset retirement obligation liability was $259 million and $179 million, respectively, primarily relating to land leases upon which power plants are built and the requirement that the property meets specific conditions upon its return. This balance is included in other long-term liabilities on the Consolidated Balance Sheets. The following table summarizes the changes to our asset retirement obligations (in millions): 29

December 31, 2025 2024 Balance, beginning of period $ 179 $ 115 Accretion expense 16 11 Adjustments for new asset retirement obligations 64 53 Balance, end of period $ 259 $ 179 Leases It is determined at contract inception, if the contract is or contains a lease, which involves the contract conveying the right to control the use of explicitly or implicitly identified property, plant or equipment for a period of time in exchange for consideration. Right-of-use (“ROU”) assets represent the Company's right to use an underlying asset for the lease term and lease liabilities represent the Company's obligation to make lease payments arising from the lease. ROU assets and lease liabilities are recognized at the commencement date of the underlying lease based on the present value of lease payments over the lease term. The Company's secured incremental borrowing rate is used and is based on information available at lease commencement to determine the present value of lease payments. Operating leases are included in ROU assets, operating lease liabilities (current) and operating lease liabilities (non-current) on the Consolidated Balance Sheet. Finance leases are included in property, plant and equipment, other current liabilities, other non-current liabilities and deferred credits on the Consolidated Balance Sheets. The lease term includes options to extend or terminate the lease when it is reasonably certain that the option will be exercised. The Company applies the practical expedient permitted by ASC 842, Leases, to not separate lease and non- lease components for most lease asset classes. Leases with an initial lease term of 12 months or less are not recorded on the balance sheet. Lease expense is recognized for these leases on a straight-line basis over the lease term. There are no material operating and finance subleases. See Note 4, Leases, for further discussion. Debt Issuance Costs Costs incurred related to the issuance of debt instruments are deferred and amortized over the term of the related debt using a method that approximates the effective interest rate method. However, when the timing of debt transactions involves contemporaneous exchanges of cash between the Company and the same creditor(s) in connection with the issuance of a new debt obligation and satisfaction of an existing debt obligation, debt issuance costs are accounted for depending on whether the transaction qualifies as an extinguishment or modification, which requires us to either write-off the original debt issuance costs and capitalize the new issuance costs, or continue to amortize the original debt issuance costs and immediately expense the new issuance costs. Debt issuance costs related to a recognized debt liability are presented as a direct deduction from the carrying amount of the related debt liability, which is consistent with the presentation of debt discounts. Accounting for Derivative Instruments The Company accounts for derivative instruments under ASC 815, Derivatives and Hedging, which requires the Company to record all derivatives on the balance sheet at fair value and changes in fair value in earnings unless they qualify for the NPNS exception. The Company enters into various derivative instruments, including both exchange-traded and over-the-counter (“OTC”) power and natural gas forwards, options as well as instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options), and interest rate derivative instruments. All derivative instruments that qualify for derivative accounting treatment are recognized as either assets or liabilities and are measured at fair value unless they qualify for and are designated under the NPNS exemption. Accounting for derivatives at fair value requires estimation of future prices during periods for which price quotes may not be available from external sources in which case internally developed price estimates are relied upon. Hedge accounting requires formal documentation, designation, and an assessment of the effectiveness of hedge accounting transactions. Cash Flow Hedges — The Company has elected to designate certain of our commodity and interest rate derivative instruments in cash flow hedging relationships where the accounting rules permit. As a result, we previously applied hedge accounting to a portion of our interest rate and commodity hedging instruments with the change in fair value of all other hedging instruments recorded through earnings. Effective September 1, 2025, the Company elected to discontinue hedge accounting for all commodity hedges of future generation fleet sales and fuel procurement activity. Effective December 1, 30

2025, the Company elected to discontinue hedge accounting for all interest rate hedging relationships. In both cases the mark- to-market gains or losses associated with all such contracts frozen in OCI as of the date of discontinuation of hedge accounting treatment. All such balances will be reclassified into earnings in the same period that the hedged forecasted transaction affects earnings with any future changes in fair value recorded to earnings directly. See Note 10, Derivative Instruments, for further discussion. Revenue Recognition Operating revenues are comprised of the following: • power and steam revenue consisting of variable payments related to generation, power revenues consisting of fixed and variable capacity payments not related to generation - including capacity payments received from regional transmission organizations (“RTO”) and ISO capacity auctions – REC revenue from our Geysers Assets, and other revenues such as RMR contracts, resource adequacy, and certain ancillary service revenues, • retail power and gas sales activities, • realized settlements from our marketing, hedging, optimization and trading activities, • unrealized mark-to-market revenues from derivative instruments as a result of our marketing, hedging, optimization and trading activities; and • sales of natural gas and other service revenues. For further information about the Company's accounting for revenue from contracts with customers, see Note 3, Revenue from Contracts with Customers Realized Settlements of Commodity Derivative Instruments — The realized value of power sales and commodity purchase contracts that are net settled, or settled as gross sales and purchases but could have been net settled, are reflected on a net basis and included in Commodity revenue on our Consolidated Statements of Operations. Mark-to-Market (Gain) Loss — Changes in the realized mark-to-market value of power-based commodity derivative instruments are reflected on a net basis as a separate component of operating revenues on our Consolidated Statements of Operations. Gross vs. Net Accounting — We determine at contract inception whether the financial statement presentation of revenues should be on a gross or net basis. Where the Company acts as principal, settlement of physical commodity contracts is recorded on a gross or net basis dependent upon whether the contract results in the physical delivery of the underlying product. With respect to our physical executory contracts, where we do not take title to the commodities but receive a variable payment to convert natural gas into power and steam in a tolling operation, revenues are recorded on a net basis. Fuel and Purchased Energy Expense Fuel and purchased energy expense is comprised of the cost of natural gas and fuel oil purchased from third parties for the purposes of power plant consumption in our power plants as fuel, the cost of power purchased from third parties for sale to retail customers, the cost of power and natural gas purchased from third parties for marketing, hedging and optimization activities, and realized settlements and mark-to-market gains and losses resulting from general market price movements against certain derivative natural gas and power contracts. This includes financial natural gas transactions economically hedging anticipated future power sales that either do not qualify as hedges under the hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected. Realized and Mark-to-Market Expenses from Commodity Derivative Instruments Realized Settlements of Commodity Derivative Instruments — The realized value of natural gas commodity purchase and sales contracts that are net settled are reflected on a net basis and included in commodity expense on our Consolidated Statements of Operations. Power purchase commodity contracts that result in the physical delivery of power, and that also supplement our power generation, are reflected on a gross basis and are included in commodity expense on our Consolidated Statements of Operations. Mark-to-Market (Gain)/Loss — Changes in the mark-to-market value of natural gas-based and certain power-based commodity derivative instruments are reflected on a net basis as a separate component of fuel and purchased energy expense. 31

Operating and Maintenance Expense Operating and maintenance expenses primarily include employee expenses, utilities, chemicals, repairs and maintenance (including equipment failure and major maintenance), insurance and property taxes. These expenses are recognized when the service is performed or in the period to which the expense relates. Income Taxes Income taxes are accounted for using the asset and liability method in accordance with ASC 740, Income Taxes. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying values of existing assets and liabilities and their respective tax basis, and for tax credit and net operating loss (“NOL”) carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities due to a change in tax rates is recognized in income in the period that includes the enactment date. See Note 12, Income Taxes, for further discussion. The Company recognizes the financial statement effects of a tax position are recognized when it is more-likely-than- not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more- likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely to be realized upon ultimate tax authority settlement. Previously recognized tax positions are reversed in the first period in which it is no longer more-likely-than-not that the tax position will be sustained upon examination. See Note 12, Income Taxes, for further discussion. Recent Accounting Pronouncements Income Tax Disclosures — In December 2023, the FASB issued ASU 2023-09, “Improvements to Income Tax Disclosures” (“ASU 2023-09”) which requires a tabular reconciliation of the expected tax to the reported tax using both percentages and amounts, broken out into specific categories, with certain reconciling items at or above 5% of the expected tax further broken out by nature and/or jurisdiction. Entities are also required to disclose income taxes paid, broken out between federal, state/local and foreign, as well as to an individual jurisdiction for 5% or more of the total income taxes paid. The Company adopted ASU 2023-09 for its 2025 Consolidated Financial Statement disclosure and applied it prospectively. Expense Disaggregation Disclosures — In November 2024, the FASB issued ASU 2024-03, “Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Topic 220-40): Disaggregation of Income Statement Expenses” (“ASU 2024-03”), and in January 2025, the FASB issued ASU 2025-01, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40): Clarifying the Effective Date (“ASU 2025-01”). ASU 2024-03 requires disclosure, in the notes to the financial statements, of specified information about certain costs and expenses. The amendments require that at each interim and annual reporting period an entity: (1) disclose the amounts of (a) purchases of inventory, (b) employee compensation, (c) depreciation, (d) intangible asset amortization, and (e) depreciation, depletion and amortization recognized as part of oil-and gas-producing activities (or other amounts of depletion expense) included in each relevant expense caption. A relevant expense caption is an expense caption presented on the face of the income statement within continuing operations that contains any of the expense categories listed in (a)–(e); (2) include certain amounts that are already required to be disclosed under current U.S. GAAP in the same disclosure as the other disaggregation requirements; (3) disclose a qualitative description of the amounts remaining in relevant expense captions that are not separately disaggregated quantitatively; and (4) disclose the total amount of selling expenses and, in annual reporting periods, an entity’s definition of selling expenses. ASU 2024-03, as clarified by ASU 2025-01, is effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. ASU 2024-03, as clarified by ASU 2025-01 should be applied either (1) prospectively to financial statements issued for reporting periods after the effective date of this update or (2) retrospectively to any or all prior periods presented in the financial statements. While the Company is not a public company, it is currently assessing the impact of adopting ASU 2024-03, as amended, on its Consolidated Financial Statement disclosure. Business Combination and Consolidation Disclosures — In May 2025, the FASB issued ASU No. 2025-03, "Business Combinations (Topic 805) and Consolidation (Topic 810), Determining the Accounting Acquirer in the Acquisition of a Variable Interest Entity" (“ASU 2025-03”), which revises current guidance for determining the accounting acquirer for a transaction effected primarily by exchanging equity interests in which the legal acquiree is a VIE that meets the definition of a business. The amendments require that an entity consider the same factors that are currently required for determining which entity is the accounting acquirer in other acquisition transactions. The amendments in ASU 2025-03 are effective for all entities for annual reporting periods beginning after December 15, 2026, and interim reporting periods within those annual reporting 32

periods, and require that an entity apply the new guidance prospectively to any acquisition transaction that occurs after the initial application date. Early adoption is permitted as of the beginning of an interim or annual reporting period. The Company is currently assessing the impact of ASU 2025-03 on its Consolidated Financial Statement disclosure. 3. Revenue from Contracts with Customers The following tables represent a disaggregation of revenue by reportable segment (in millions). See Note 18, Segment and Significant Customer Information for a description of these segments. Year Ended December 31, 2025 Wholesale West Texas East Retail Elimination Total Third-Party: Energy & other products $ 871 $ 1,215 $ 1,790 $ 1,105 $ — $ 4,981 Capacity 760 495 591 — — 1,846 Revenues relating to physical or executory contracts – third-party $ 1,631 $ 1,710 $ 2,381 $ 1,105 $ — $ 6,827 Affiliate(1): $ 229 $ 334 $ 65 $ 47 $ (675) $ — Revenues relating to leases and derivative instruments(2) $ 7,470 Other 3 Total operating revenues $ 14,300 Year Ended December 31, 2024 Wholesale West Texas East Retail Elimination Total Third-Party: Energy & other products $ 867 $ 1,184 $ 1,616 $ 1,058 $ — $ 4,725 Capacity 603 368 369 — — 1,340 Revenues relating to physical or executory contracts – third-party $ 1,470 $ 1,552 $ 1,985 $ 1,058 $ — $ 6,065 Affiliate(1): $ 197 $ 284 $ 67 $ 56 $ (604) $ — Revenues relating to leases and derivative instruments(2) $ 6,369 Total operating revenues $ 12,434 33

Year Ended December 31, 2023 Wholesale West Texas East Retail Elimination Total Third-Party: Energy & other products $ 1,589 $ 1,619 $ 905 $ 1,091 $ — $ 5,204 Capacity 470 447 348 — — 1,265 Revenues relating to physical or executory contracts – third-party $ 2,059 $ 2,066 $ 1,253 $ 1,091 $ — $ 6,469 Affiliate(1): $ 140 $ 296 $ 66 $ 144 $ (646) $ — Revenues relating to leases and derivative instruments(2) $ 7,217 Other 1 Total operating revenues $ 13,687 ___________ (1) Affiliate energy, other and capacity revenues reflect revenues on transactions between wholesale and retail affiliates, excluding affiliate activity related to leases and derivative instruments. All such activity supports retail supply needs from the wholesale business and/or allows for collateral margin netting efficiencies at Calpine. (2) Revenues relating to contracts accounted for as leases and derivatives include energy and capacity revenues relating to PPAs which must be accounted for as operating leases and physical and financial commodity derivative contracts, primarily relating to power, natural gas, and environmental products. Lease revenues were not material for the years ended December 31, 2025, 2024 and 2023, as further discussed in Note 4, Leases. Revenue related to derivative instruments includes revenue recorded in Commodity revenue and mark-to-market gain (loss) within operating revenues in the Consolidated Statements of Operations. Energy and Other Products Variable payments for power and steam that are based on generation, including retail sales of power, are recognized over time as the underlying commodity is generated or purchased and control is transferred to the customer upon transmission and delivery. Ancillary service revenues are also included within energy-related revenues and are recognized over time as the service is provided. For power, steam and ancillary service contracts we have elected the practical expedient which allows us to recognize revenue at the amount which we are entitled to invoice to the extent we determine such amounts correspond directly with the value provided to date. To the extent this practical expedient cannot be used, revenue is recognized over time, based on the quantity of the commodity delivered to the customer for power and steam sales, and as the service is provided for ancillary service sales. Energy and other revenues also include revenues generated from the sale of natural gas and environmental products, including RECs, and are recognized at either a point-in-time or over time when control of the commodity has transferred. Revenues from the sale of RECs are primarily related to credits that are generated upon generation of renewable power from the Geysers Assets and are recognized over the same period of time as the timing of the related energy sale. Revenues from sales of RECs or other environmental products that are generated by third parties are recognized once all certifications have been completed and the credits are delivered to the customer at a point in time. Revenues from natural gas sales are recognized at a point in time when delivery of the natural gas is provided. Revenues from natural gas and emission product sales are generally at the contracted transaction price, which may be fixed or index-based. Capacity Capacity revenues include fixed and variable capacity payments, which are based on generation volumes and include capacity payments received from RTO and ISO capacity auctions as well as contractual capacity under long-term PPAs. For these contracts, we have elected the practical expedient which allows us to recognize revenue equivalent to the amount invoiced. To the extent this practical expedient cannot be used, we recognize revenue over time as the service is provided to the customer. 34

Performance Obligations and Contract Balances The Company's contracts may have multiple performance obligations. The revenues associated with each individual performance obligation are based on the relative stand-alone sales price of each good or service or, when not available, is based on a cost incurred plus margin approach. For a significant portion of these contracts with multiple performance obligations, management has applied the practical expedient that results in recognition of revenue commensurate with the invoiced amount and no allocation is required as all performance obligations are transferred over the same period. The Company's contracts may also include volumetric optionality based on customer needs. The transaction price within these contracts is based on a stand-alone sale price of the good or service being provided and revenue is recognized based on customer usage. On a monthly basis, revenue is recognized based on estimated or actual usage by the customer at the transaction price. To the extent estimated usage is used in the recognition of revenue, revenues are adjusted for actual usage once known; however, this adjustment is not material to the revenues recognized. Generally, we apply the practical expedient that allows us to recognize revenue based on the invoiced amount. Changes in contract estimates are not material and revisions to estimates are recognized when the amounts can be reasonably estimated. Unbilled retail sales are based upon estimates of customer usage since the date of the last meter reading provided by the ISOs or electric distribution companies by applying the estimated revenue per Kilowatt hour (“KWh”) by customer class to the estimated number of KWh delivered but not yet billed. Estimated amounts are adjusted when actual usage is known and billed. During the years ended December 31, 2025, 2024 and 2023, there were no significant changes to revenue amounts recognized in prior periods resulting from a change in estimates. Sales and other taxes collected concurrent with revenue-producing activities are excluded from operating revenues. Billing requirements for wholesale customers generally result in billing customers on a monthly basis in the month following the delivery of the good or service. Once billed, payment is generally required within 20 days resulting in payment for the delivery of the good or service in the month following delivery of the good or service. Billing requirements for our retail customers are generally once every 30 days and may result in billed amounts relating to retail customers extending up to 60 days. Based on the terms of customer agreements, payment is generally received at or shortly after good or service delivery. Changes in customer accounts receivable are primarily due to the timing difference between payment and when the goods or services are provided. As of December 31, 2025 and 2024, there were no significant changes in accounts receivable other than normal billing and collections, and there were no material credit or impairment losses recognized related to customer accounts receivable balances. As such, the unbilled accounts receivable balance for all revenue streams totaled $978 million and $891 million, as of December 31, 2025 and 2024, respectively, and is included within accounts receivable, net in the Consolidated Balance Sheets. When consideration from a customer is received prior to transferring goods or services to the customer it is recorded as deferred revenue, which represents a contract liability. Such deferred revenue typically results from consideration received prior to the transfer of goods and services relating to our capacity contracts and the sale of RECs that are not generated from power plants. Based on the nature of these contracts and the timing between when consideration is received and delivery of the good or service is provided, these contracts do not contain any material financing elements. As of December 31, 2025, the deferred revenue balance related to contracts with customers primarily relates to environmental products and capacity sales, and are included in other current liabilities in the Consolidated Balance Sheets. The balance outstanding as of December 31, 2025 and 2024, was $86 million and $112 million, respectively. Revenue recognized during the years ended December 31, 2025, 2024 and 2023, relating to the deferred revenue balance at the beginning of the period, was $124 million, $61 million and $57 million, respectively, and resulted from performance under our customer contracts. The change in the deferred revenue balance as of December 31, 2025 and 2024 was primarily due to the timing difference of when consideration was received and when the related good or service was transferred. Contract Costs For certain retail contracts, third-party incremental broker costs are incurred and are capitalized on the Consolidated Balance Sheets. Capitalized contract costs are amortized on a straight-line basis over the term of the underlying sales contract to the extent the term extends beyond one year. Contract costs associated with sales contracts that are less than one year are expensed as incurred under a practical expedient. As of December 31, 2025 and 2024, respectively, the capitalized contract cost balance was not material. There were no impairment losses or changes in amortization during the years ended December 31, 2025, 2024 and 2023, and amortization of contract costs during these periods was immaterial. 35

Performance Obligations not yet Satisfied As of December 31, 2025, the Company has entered into certain contracts for fixed and determinable amounts with customers under which performance obligations have not been completed, which primarily includes agreements for which we are providing capacity from our generating facilities. These revenues are related to the sale of capacity through participation in various ISO capacity auctions, estimated based upon cleared volumes and the sale of capacity to customers of $862 million, $841 million, $489 million, $244 million and $156 million, that will be recognized during the years ending December 31, 2026, 2027, 2028, 2029 and 2030, respectively, and $550 million thereafter. Revenues under these contracts will be recognized as control of the commodities is transferred to customers. 4. Leases Accounting for Leases – Lessee Contracts are evaluated for lease accounting at contract inception and lease classification is assessed at the lease commencement date. A right-of-use asset is recognized for leases and corresponding lease obligation liability at the lease commencement date where the lease obligation liability is measured at the present value of the minimum lease payments. For operating leases, the right-of-use asset amortization and the accretion of lease obligation liability results in a single straight-line expense recognized over the lease term. The discount rate determined is associated with operating and finance leases using the Company’s incremental borrowing rate at lease commencement. For operating leases, an interest rate is used which is commensurate with the interest rate to borrow on a collateralized basis over a similar term with an amount equal to the lease payments. Factors management considered in the calculation of the discount rate include, the amount of the borrowing, the lease term, including options that are reasonably certain of exercise, the current interest rate environment and the credit rating of the entity. For finance leases, the interest rate used is commensurate with the interest rate for a project finance borrowing arrangement with similar collateral package, repayment terms, restrictive covenants and guarantees. The Company’s operating leases are primarily related to office space for corporate and regional offices, as well as land and operating-related leases for power plants which contain renewal options to extend the lease term. The inclusion of these lease term renewal periods in the minimum lease payments is dependent on specific facts and circumstances for each lease and whether it is determined to be reasonably certain that the extension option will be exercised. Operating leases do not contain any material restrictive covenants or residual value guarantees. As lessee, lease and non-lease components are not separated for current classes of underlying leased assets. The Company has entered into finance lease agreements for certain power plants and related equipment with original terms that range up to 30 years (including lease renewal options). Finance leases require the lessee to pay taxes, maintenance, insurance, and other operating costs for the leased property. The Company has made an accounting policy election to not recognize lease assets and liabilities for leases with a term of 12 months or less, which are immaterial. There are no material subleases associated with these operating and finance leases. The operating and finance lease expense components are as follows for the periods presented (in millions): Year Ended December 31, 2025 2024 2023 Operating leases Operating lease expense(1) $ 19 $ 19 $ 19 Finance leases Depreciation of property, plant and equipment 3 4 4 Interest expense 2 2 3 Finance lease expense $ 5 $ 6 $ 7 Variable lease expense(2) 3 3 6 Total lease expense $ 27 $ 28 $ 32 36

____________ (1) Operating lease expense is recognized within operating and maintenance expense or general and other administrative expenses based upon the lease arrangement. (2) Variable lease expense relates to operating leases where common area maintenance and similar variable charges are incurred. The following is a schedule by year of future minimum lease payments associated with our operating and finance leases, together with the present value of the net minimum lease payments as of December 31, 2025 (in millions): Operating Leases(1) Finance Leases(2) 2026 $ 18 $ 7 2027 20 6 2028 19 6 2029 19 — 2030 18 — Thereafter 160 — Total minimum lease payments 254 19 Less: Amount representing interest(3) (84) (2) Total lease obligation 170 17 Less: current lease obligation (9) (5) Long-term lease obligation $ 161 $ 12 ____________ (1) The lease liabilities associated with operating leases are included in other current liabilities and other long-term liabilities on the Consolidated Balance Sheets. (2) The lease liabilities associated with finance leases are included in debt, current portion and debt, net of current portion on our Consolidated Balance Sheets. (3) The amount representing interest is recorded in operating lease expense for operating leases and interest expense for our finance leases on the Consolidated Statements of Operations. Supplemental balance sheet information related to operating and finance leases is as follows (in millions, except lease term and discount rate): December 31, 2025 2024 Operating leases(1) Right-of-use assets associated with operating leases $ 150 $ 140 Finance leases(2) Property, plant and equipment, gross 103 104 Accumulated amortization (43) (43) Property, plant and equipment, net $ 60 $ 61 Weighted average remaining lease term (in years) Operating leases 14.6 15.7 Finance leases 3.0 3.8 Weighted average discount rate Operating leases 5.5 % 5.4 % Finance leases 9.4 % 8.2 % 37

____________ (1) The right-of-use assets associated with operating leases are included in other assets on the Consolidated Balance Sheets. (2) The right-of-use assets associated with finance leases are included in property, plant and equipment, net on the Consolidated Balance Sheets. Supplemental cash flow information related to operating and finance leases is as follows for the periods presented (in millions): Year Ended December 31, 2025 2024 2023 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 20 $ 19 $ 25 Operating cash flows from finance leases $ 2 $ 3 $ 3 Financing cash flows from finance leases $ 7 $ 6 $ 16 Right-of-use assets obtained in exchange for lease obligations Operating leases $ 25 $ 5 $ 19 Finance leases $ — $ — $ — Accounting for Leases – Lessor The Company applies lease accounting to PPAs that meet the definition of a lease and determines lease classification treatment at agreement commencement. Currently, there are no contracts which are accounted for as sales-type leases or direct financing leases and all leases in which the Company is the lessor are classified as operating leases. Revenue from contracts accounted for as operating leases, such as certain tolling agreements, with minimum lease rentals (capacity payments), which vary over time, must be levelized. These contract revenues are levelized on a straight-line basis over the term of the contract. Operating leases that have commenced contain terms extending through May 2042. These contracts also contain variable payment components based on volumes or operating efficiency. Revenues associated with the variable payments are recognized over time as the goods or services are provided to the lessee. These operating leases generally do not contain renewal or purchase options or residual value guarantees. The Company has elected not to separate lease and non-lease components as the lease components reflect the predominant characteristics of these agreements. Revenue recognized related to fixed lease payments on operating leases for the periods presented is as follows (in millions): Year Ended December 31, 2025 2024 2023 Operating leases(1) Fixed lease payments $ 205 $ 153 $ 196 ____________ (1) Revenues associated with operating leases are included in Commodity revenue and other revenue on the Consolidated Statements of Operations. 38

The total contractual future minimum lease rentals for contracts that have commenced and are accounted for as operating leases at December 31, 2025, are as follows (in millions): 2026 $ 214 2027 213 2028 215 2029 179 2030 166 Thereafter 1,255 Total $ 2,242 Lease receivables associated with operating leases are not recognized as the long-lived assets subject to the lease contracts are recorded on the Consolidated Balance Sheets and are being depreciated over their estimated useful lives. Amounts recorded on the Consolidated Balance Sheets associated with the long-lived assets subject to our operating leases are as follows (in millions): December 31, 2025 2024 Assets subject to contracts accounted for as operating leases Property, plant and equipment, gross $ 1,817 $ 1,303 Accumulated depreciation (399) (346) Property, plant and equipment, net(1)(2) $ 1,418 $ 957 ____________ (1) Assets are subject to contracts that are accounted for as operating leases, which primarily consist of power plants and are subject to tolling contracts. (2) The increase in Property, plant and equipment, net is primarily attributable to the commercial operations of new battery facilities during the year ended December 31, 2025. Lease levelization assets and liabilities are recorded for any difference between the timing of the contractual payments made related to operating lease contracts and revenue recognized on a straight-line basis. These balances are included in current and long-term assets and liabilities on the Consolidated Balance Sheets. 5. Acquisitions and Divestitures Quail Run Energy Partners, LP On September 17, 2024, Calpine, through its wholly-owned subsidiary, completed the purchase of Quail Run Energy Centre, a 550 Megawatt (“MW”) natural gas-fired, combined cycle generation facility located in Odessa, Texas, and included within the Texas segment. The purchase price, as specified in the purchase and sale agreement, including working capital and other adjustments, was $334 million. The acquisition was funded through cash on hand and proceeds from the September 2024 refinancing of the CCFC Term Loan. The purchase price was primarily allocated to property, plant and equipment, net of the fair value of associated out-of-the-money Heat Rate call options. Bosque Parcel 2, LLC On September 30, 2025, Bosque Parcel 2, LLC, a Delaware limited liability company sold land for $130 million, resulting in a gain on sale of assets of $117 million in connection with the execution of a new 210 MW agreement with Dallas- based CyrusOne, a leading global data center developer and operator, for development of a second data center facility located adjacent to Calpine’s Thad Hill Energy Center in Bosque County, Texas. The deal secured power, grid connection and land to support a second facility with Cyrus One and, with the previously announced 190 MW power purchase agreement, which brought the total MW’s under contract with CyrusOne to 400 MW’s. 39

Assets Held For Sale The assets and liabilities of Bethlehem Energy Center, Hay Road Energy Center, Edge Moor Energy Center, York Energy Center, York II Energy Center, which are part of the East segment, as well as Jack A Fusco Energy Center, which is part of the Texas Segment, were reclassified to current assets held for sale and current liabilities held for sale in the Consolidated Balance Sheets at December 31, 2025. The conclusion to reclassify all balances for the four facilities other than Jack A Fusco Energy Center and York II Energy Center was reached following conditional FERC approval for the Plan of Merger Agreement between Constellation Energy Group and Calpine Corporation on July 23, 2025, which included such proposed divestitures. Then, on December 5, 2025, Constellation announced it had reached a resolution with the DOJ on the conditions required to complete the Calpine Corporation acquisition, which included a requirement to also divest the Jack A Fusco Energy Center, the York II Energy Center and the Company's minority ownership interest in the Gregory Power Plant. Calpine did not recognize any losses upon reclassification of all balances to held for sale during the year ended December 31, 2025. The sale will be considered an asset sale for tax purposes, requiring net deferred tax liabilities to be excluded from held for sale balances. The table below presents the carrying amounts of the major classes of assets and liabilities included as part of the expected sale (in millions): December 31, 2025 Inventories $ 125 Other current assets 7 Property, plant and equipment 1,450 Right-of-use assets 4 Total current assets held for sale $ 1,586 Other current liabilities $ (19) Other long-term liabilities (35) Total current liabilities held for sale $ (54) 6. Property, Plant and Equipment, Net The components of property, plant and equipment are stated at cost, less accumulated depreciation as follows (in millions): December 31, 2025 2024 Depreciable Lives Buildings, machinery and equipment $ 15,883 $ 17,921 1.5 – 35 Years Geothermal properties 1,859 1,811 13 – 58 Years Other 474 407 3 – 35 Years 18,216 20,139 Less: Accumulated depreciation (7,685) (8,237) 10,531 11,902 Land 134 115 Construction in progress 959 562 Property, plant and equipment, net $ 11,624 $ 12,579 Total depreciation expense, including amortization of finance lease assets, recorded for the years ended December 31, 2025, 2024 and 2023, was $748 million, $727 million and $697 million, respectively. The Company has various debt instruments which are collateralized by its property, plant and equipment. See Note 8, Debt for a discussion of such instruments. 40

Buildings, Machinery and Equipment This component primarily includes power plants and related equipment. Included in buildings, machinery and equipment are assets under finance leases. See Note 4, Leases for further information regarding these assets under finance leases. Geothermal Properties This component primarily includes power plants and related equipment associated with our Geysers Assets. Other This component primarily includes software and hardware as well as emission reduction credits that are power plant specific and not available to be sold. Capitalized Interest The total amount of interest capitalized was $30 million, $43 million and $27 million for the years ended December 31, 2025, 2024 and 2023, respectively. 7. Variable Interest Entities and Unconsolidated Investments The Company consolidates all of its VIEs where it has been determined that the Company is the primary beneficiary. Except for the changes discussed below, there were no changes in determining whether the Company is the primary beneficiary of these VIEs for the year ended December 31, 2025. The following types of VIEs are consolidated in the Consolidated Financial Statements: Subsidiaries with Project Debt — All subsidiaries with project debt not guaranteed by Calpine have PPAs that provide financial support and are thus considered VIEs. The Company retains ownership and absorbs the full risk of loss and potential for reward once the project debt is paid in full. Actions by the lender to assume control of collateral can occur only under limited circumstances such as upon the occurrence of an event of default. See Note 8, Debt, for further information regarding project debt and Note 2, Summary of Significant Accounting Policies, for information regarding restricted cash balances. Subsidiaries with PPAs — The Company's majority-owned subsidiaries have PPAs that limit the risk and reward of its ownership and thus constitute a VIE. Consolidation of VIEs VIEs are consolidated when it is determined that the Company has both the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance and the obligation to absorb losses or receive benefits from the VIE. It was determined that the Company has the obligation to absorb losses and receive benefits in almost all of its VIEs where majority equity interest is held. Therefore, the determination of whether to consolidate is based upon which variable interest holder has the power to direct the most significant activities of the VIE (the primary beneficiary). This analysis includes consideration of the following primary activities that have a significant effect on a power plant’s financial performance: operations and maintenance, plant dispatch and fuel strategy, as well as the ability to control or influence contracting and overall plant strategy. The approach to determining which entity holds the powers and rights is based on powers held as of the balance sheet date. Contractual terms that may change the powers held in future periods, such as a purchase or sale option, are not considered in this analysis. Based on the analysis, the Company holds the power and rights to direct the most significant activities for most majority-owned VIEs. Under the consolidation policy and under U.S. GAAP, the Company also: • performs an ongoing reassessment each reporting period of whether it is the primary beneficiary of the VIEs and • evaluate if an entity is a VIE and whether we are the primary beneficiary whenever any changes in facts and circumstances occur, such as contractual changes where the holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of a VIE that most significantly affect the VIE’s economic performance or when there are other changes in the powers held by individual variable interest holders. 41

Consolidated VIEs The Company's consolidated VIEs include natural gas-fired and geothermal power plants and battery storage facilities with an aggregate capacity of 8,462 MW and 8,365 MW in operation at December 31, 2025 and 2024, respectively. For these VIEs, the Company may provide other operational and administrative support through various affiliate contractual arrangements among the VIEs, Calpine Corporation, and its other wholly-owned subsidiaries, whereby the Company supports the VIE through the reimbursement of costs and/or the purchase and sale of energy. Other than amounts contractually required, the Company provided no additional material support to the VIEs in the form of cash and other contributions during each of the years ended December 31, 2025 and 2024. U.S. GAAP requires separate disclosure on the face of the Consolidated Balance Sheets of the significant assets of a consolidated VIE that can be used only to settle obligations of the consolidated VIE and the significant liabilities of a consolidated VIE for which creditors (or beneficial interest holders) do not have recourse to the general credit of the primary beneficiary. In determining which VIE assets meet the separate disclosure criteria, the Company considered that this separate disclosure requirement is met where Calpine Corporation is substantially limited or prohibited from access to assets (including cash and cash equivalents, restricted cash and property, plant and equipment, net), and where its VIEs have project financing that prohibits the VIE from providing guarantees on the debt of others. In determining which VIE liabilities meet the separate disclosure criteria, the Company considered that this separate disclosure requirement is met where there are agreements that prohibit the debt holders of the VIEs from recourse to the general credit of Calpine Corporation. Unconsolidated VIEs and Investments in Unconsolidated Subsidiaries Calpine Receivables and Gregory Power Holdings, LLC are unconsolidated investments as of December 31, 2025. Calpine Receivables is a VIE and a bankruptcy remote entity created for the special purpose of purchasing trade accounts receivable from Calpine Solutions under the Accounts Receivable Sales Program. The Company determined that it does not have the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance nor the obligation to absorb losses or receive benefits from the VIE. Accordingly, it was determined that the Company is not the primary beneficiary of Calpine Receivables because it does not have the power to affect its financial performance as the unaffiliated financial institutions that purchase the receivables from Calpine Receivables, control the selection criteria of the receivables sold and appoint the servicer of the receivables which controls management of default. Thus, the Company does not consolidate Calpine Receivables in its Consolidated Financial Statements but instead uses the equity method of accounting to record the net interest in Calpine Receivables. As of December 31, 2025, the Company has a 53.5% non-economic (for certain voting rights) and 43.3% economic interest in Gregory Power Holdings, LLC. The Company had an obligation to fund future cash contributions to Gregory Power Holdings, LLC, until its economic investment interest reached 45% ownership in the entity. The Company made $84 million and $44 million in cash contributions to Gregory Power Holdings, LLC during the years ended December 31, 2025 and 2024, respectively. The Company's net interest in Gregory Power Holdings, LLC was accounted for as an equity method investment at December 31, 2025 and 2024. The Company does not consolidate Gregory Power Holdings, LLC because it does not exert significant influence over the investment. As part of the DOJ resolution reached on December 5, 2025 in connection with the Constellation merger, the Company agreed to divest its ownership interest in the Gregory Power Plant, which divestiture was completed in January 2026. See Note 19, Subsequent Events, for additional details related to the Gregory Power Plant sale. For the period that these entities meet the criteria for unconsolidated investment, the Company accounts for these entities under the equity method of accounting and includes its net equity interest in investments in unconsolidated subsidiaries in the Consolidated Balance Sheets. As of December 31, 2025 and 2024, the Company's investments included in the Consolidated Balance Sheets were comprised of the following (in millions): 42

Ownership Interest as of December 31, 2025 December 31, 2025 2024 Calpine Receivables(1) 100.0 % 15 25 Gregory Power Holdings, LLC(2) 43.3 % 114 44 Total investment in unconsolidated subsidiaries under equity method of accounting(3) $ 129 $ 69 ____________ (1) The Company's ownership interest as of December 31, 2025 and 2024 was 100%. The Company's investment in Calpine Receivables is accounted for using the equity method of accounting. (2) The Company's ownership interest as of December 31, 2025 and 2024 was 43.3% and 28.5%, respectively. The Company's investment in Gregory Power Holdings, LLC was accounted for using the equity method of accounting. (3) In addition to our investment in the table above, the Company also held a cost investment of $7 million and $7 million related to an additional entity as of December 31, 2025 and 2024, respectively. The Company's risk of loss related to its investment in Calpine Receivables is $96 million and $100 million as of December 31, 2025 and 2024, respectively, which consists of notes receivable from Calpine Receivables and its investment associated with Calpine Receivables. The Company has $10 million and $45 million as of December 31, 2025 and 2024, respectively, of related party debt outstanding with Calpine Receivables offset against its investment in the entity. During the year ended December 31, 2025 , the Company wrote off $35 million in related party debt outstanding with Calpine Receivables which offset its investment in the entity. See Note 17, Related Party Transactions, for further information associated with related party activity with Calpine Receivables. Debt holders of the Company's unconsolidated investments do not have recourse to Calpine Corporation or its other subsidiaries; therefore, the debt of unconsolidated investments is not reflected in the Consolidated Balance Sheets. The Company's equity interest in the net (income) loss from its investments in unconsolidated subsidiaries for the years ended December 31, 2025, 2024 and 2023, is recorded in (income) loss from unconsolidated subsidiaries in the Consolidated Statements of Operations. The following table reflects (income) loss from unconsolidated subsidiaries for the years indicated (in millions): (Income) loss from Unconsolidated Subsidiaries Distributions Year Ended December 31, Year Ended December 31, 2025 2024 2023 2025 2024 2023 Greenfield L.P.(1) $ — $ — $ (12) $ — $ — $ — Calpine Receivables (23) 4 9 — — — Gregory Power Holdings, LLC 14 — — — — — Total $ (9) $ 4 $ (3) $ — $ — $ — ___________ (1) The (income) loss from unconsolidated investments and distributions from Greenfield L.P. only include the results of the Company's investment in Greenfield L.P. through September 5, 2023. Subsequent to the acquisition of the remaining 50% equity interest in Greenfield L.P., all of the results of operations of the partnership are included within the consolidated results in the Consolidated Statements of Operations. 43

8. Debt Pursuant to the completion of Agreement and Plan of Merger, dated January 10, 2025, Constellation Energy Generation LLC (“Constellation”) assumed various long-term debt of Calpine, including $7.6 billion of senior unsecured and secured notes, and corporate term loans. In December 2025, Constellation commenced private exchange offers and related consent solicitations ("Exchange Offers") with respect to certain outstanding debt of Calpine. Pursuant to the Exchange Offers, Constellation issued new notes in January 2026 effectively replacing $2.3 billion of Calpine's 2031 First Lien Notes, 2029 Senior Secured Notes, and 2031 Senior Unsecured Notes. In addition, using the proceeds from Constellation’s January 2026 bond issuance along with cash on hand and short-term debt, Constellation paid off Calpine's First Lien Term Loans totaling $2.5 billion immediately after the acquisition closing and redeemed Calpine's 2028 First Lien Notes totaling $1.25 billion in February 2026. Simultaneous to the acquisition closing, Constellation dissolved Calpine's Corporate Revolving Facility and Commodity-Linked Revolving Facility. See Note 19, Subsequent Events, for further discussion. The Company's debt is summarized in the table below (in millions): December 31, 2025 2024 Revolving facilities $ 548 $ 148 First Lien Term Loans 2,488 2,484 CCFC Term Loan 2,095 1,864 GPC Term Loan 1,375 1,486 Construction loan facilities, project financing, notes payable and other 930 997 Senior Unsecured Notes 2,889 2,886 First Lien Notes 2,140 2,276 Finance lease obligations 17 21 Subtotal 12,482 12,162 Less: Current maturities (279) (355) Total long-term debt $ 12,203 $ 11,807 The Company's debt agreements contain covenants that could permit lenders to accelerate the repayment of its debt by providing notice, the lapse of time or both, if certain events of default remain uncured after any applicable grace period. The Company was in compliance with all of the covenants in its debt agreements as of December 31, 2025. The Company's effective interest rate on the consolidated debt, including the cash settlement contribution of interest rate hedging instruments, was 4.9% as of December 31, 2025. The effective interest rate excludes the impacts of capitalized interest and unrealized mark- to-market gains and losses on interest rate derivative instruments. Annual Debt Maturities Contractual annual principal repayments or maturities of debt instruments as of December 31, 2025, are as follows (in millions): 2026 $ 279 2027 266 2028 2,994 2029 1,721 2030 2,217 Thereafter 5,089 Subtotal 12,566 Less: Debt issuance costs (66) Less: Discount (18) Total debt $ 12,482 Revolving Facilities Revolving facilities are summarized in the table below (in millions, except for interest rates): 44

Outstanding at December 31, Weighted Average Effective Interest Rates(1) 2025 2024 2025 2024 Corporate Revolving Facility $ — $ — — % 4.8 % CDHI Credit Agreement 319 148 6.5 % 4.6 % Commodity-linked Revolver — — — % — % Geysers(2) — — — % 6.7 % Pin Oak Creek Energy Center(3) 229 — 2.6 % — % Total $ 548 $ 148 ____________ (1) The weighted average interest rate calculation for revolving facilities does not include the amortization of debt issuance costs and the cash settlement contribution of interest rate hedging instruments, as applicable. (2) During the year ended December 31, 2025 and 2024, GPC drew approximately nil and $38 million, respectively, revolving loans on the Geysers Credit Agreement associated with the Bear Canyon and West Ford Flat battery storage projects. In August 2024, the entire $50 million revolving loan was converted to a term loan following the commercial operations of Bear Canyon and West Ford Flat. (3) On October 13, 2025, Pin Oak Creek Energy Center, LLC, an indirect subsidiary of Calpine Corporation, entered into a credit agreement with the Public Utility of Texas (“PUCT”) as the lender and, U.S. Bank Trust Company, National Association as administrative agent for the lender, pursuant to the Texas Energy Fund (“TEF”). As of December 31, 2025, we drew approximately $229 million on the facility. The table below represents amounts issued under letter of credit facilities (in millions): December 31, 2025 2024 Corporate Revolving Facility $ 754 $ 273 CDHI Credit Agreement 690 640 Project financing facilities(1) 324 290 Other corporate facilities 725 849 Total $ 2,493 $ 2,052 ____________ (1) The letters of credit issued within project financing facilities include the GPC, Greenfield and Nova Power credit facilities. As of December 31, 2025, the Greenfield Term Loan Facility issued $83 million CAD ($61 million USD), respectively, in letters of credit used to support the partnership’s operations and debt obligations. Refer to Construction Loan Facilities, Project Financing, Notes Payable and Other for further details. Corporate Revolving Facility On January 14, 2022, the Company amended its Corporate Revolving Facility, originally dated December 10, 2010, to increase the capacity from approximately $2.150 billion to $2.500 billion and extended the maturity date from December 16, 2025, to January 14, 2027, with additional options to extend. On January 31, 2024, the maturity was further extended to $2.225 billion of the facility to January 2029, while the remaining $275 million retained the original January 2027 maturity date. In December 2024, the Company amended the Corporate Revolving Credit Agreement to replace the existing schedule of revolving commitment amounts with a new schedule. This converted a $175 million Class D Revolving Commitment into a Class E Revolving Commitment, which extended its expiration date to match the Class E Original Termination Date of January 31, 2029. Now, $2.400 billion of Class E commitments expire January 2029, while only a $100 million commitment remains as Class D, with termination date of January 2027. The Corporate Revolving Facility represents the Company's primary revolving facility. Borrowings under the Corporate Revolving Facility bear interest, optionally, at either a base rate or SOFR. Base rate borrowings shall be at the base rate plus an applicable margin of 1.00% or 1.25% as provided in the Corporate Revolving Facility credit agreement. Base rate is defined as the highest of (1) the Federal Funds Rate, as published by the Federal Reserve Bank of New York, plus 0.50%, (2) the rate the administrative agent announces from time to time as its prime per annum rate and (3) the Adjusted Term SOFR for a one-month tenor plus 1.00%. SOFR borrowings shall be at the applicable rate published by the Federal Reserve Bank of New 45

York for the interest period as selected by us as one, three, or six months, plus an applicable margin of 2.00% or 2.25%. An unused commitment fee is incurred ranging from 0.25% to 0.50% on the unused amount of commitments under the Corporate Revolving Facility. The Corporate Revolving Facility does not contain any requirements for mandatory prepayments. However, the Company may voluntarily repay, in whole or in part, the Corporate Revolving Facility, together with any accrued but unpaid interest, with prior notice and without premium or penalty. Amounts repaid may be re-borrowed, and we may also voluntarily reduce the commitments under the Corporate Revolving Facility without premium or penalty. The Corporate Revolving Facility is guaranteed and secured by certain current domestic subsidiaries and will also be additionally guaranteed by future domestic subsidiaries that are required to provide such a guarantee in accordance with the terms of the Corporate Revolving Facility. The Corporate Revolving Facility ranks equally in right of payment with all of the Company and the guarantors’ other existing and future senior indebtedness and will be effectively subordinated in right of payment to all existing and future liabilities of our subsidiaries that do not guarantee the Corporate Revolving Facility. The Corporate Revolving Facility also requires compliance with financial covenants that include a minimum cash interest coverage ratio and a maximum net leverage ratio. CDHI Credit Agreement On March 29, 2023, the Company amended its CDHI Credit Agreement upsizing the available capacity from $700 million to approximately $1.2 billion and extending the maturity date to March 29, 2028. The facility can be used for general corporate purposes with a limit up to $400 million for construction loans that meet specified criteria. At December 31, 2025, we had $319 million in borrowings outstanding under the facility. Borrowings bear interest optionally at either a base rate or SOFR. Base rate borrowings shall be at the base rate plus an applicable margin of 1.00%. Base rate is defined as the highest of (a) the rate the administrative agent announces from time to time as its prime per annum rate, (b) the Federal Funds Effective Rate, as published by the Federal Reserve Bank of New York, plus 0.50% or (c) the Term SOFR in effect for a one-month period then in effect plus 1.00%. SOFR borrowings shall be at the Term SOFR Reference Rate for the tenor compared to the applicable interest period plus an applicable margin ranging from 2.25% to 2.375%. The applicable margin relating to a specific loan is dependent on the nature of the loan and when the loan agreement was entered. An unused commitment fee of 0.50% is incurred on the unused amount of commitments under the facility. Borrowings under the CDHI Credit Agreement are required to be repaid over time prior to the maturity date, depending on the nature of the loan. However, the Company may voluntarily repay, in whole or in part, the outstanding borrowings, together with any accrued but unpaid interest, with prior notice and without premium or penalty. Amounts repaid may be re-borrowed, and the Company may also voluntarily reduce the commitments without premium or penalty. The CDHI Credit Agreement is guaranteed and secured by the assets of certain of domestic subsidiaries in accordance with the terms of the agreement. The credit agreement provides for certain requirements to be met for distributions to be made from the subsidiaries guaranteeing the credit agreement to Calpine Corporation including meeting certain financial covenant requirements such as a leverage ratio. Commodity-linked Revolving Credit Facility On July 21, 2022, the Company entered into a one-year Commodity-linked Revolving Credit Facility and extended the credit facility in July 2024, with a maturity date of July 18, 2025. Additionally, on July 17, 2025, the Company extended the Commodity-linked Revolver through July 2026, and decreased the total borrowing base limit from $1.786 billion to $1.646 billion. Borrowings from the Commodity-linked Revolver can be solely used to meet collateral posting requirements for eligible commodity hedge agreements, as defined in the agreement. Draws on the Commodity-linked Revolver are limited to the weekly mark-to-market value change of qualified natural gas and power hedge transactions, as specified in the agreement. To the extent that outstanding borrowings would exceed the limit, a repayment will be made to reduce outstanding borrowings to be less than or equal to the limit. At December 31, 2025, the Company had no borrowings outstanding under the Commodity- linked Revolver. The loans outstanding on the Commodity-linked Revolver may bear interest, optionally, on either a base rate or SOFR rate, as specified in the agreement. Base rate borrowings shall be at the base rate plus an applicable margin of 1.00% to 1.25%, as specified in the agreement, based on the current leverage ratio. The base rate is defined as the highest of: (1) the Prime Rate, (2) the Federal Funds Rate, as published by the Federal Reserve Bank of New York, plus 0.50%, or (3) the Term SOFR for a one-month tenor plus 1.00%. SOFR borrowings shall be the applicable SOFR rate for the interest period as selected by the 46

Company as one, three, or six months, plus an applicable margin of 2.00% or 2.25%. An applicable revolving commitment fee is incurred ranging from 0.375% to 0.625% under the facility in accordance with the agreement. The Commodity-linked Revolver does not contain any requirements for mandatory prepayments outside of the requirement for the borrowings to be under the limit, as described above. However, the Company may voluntarily repay, in whole or in part, the outstanding borrowings, together with any accrued but unpaid interest, without premium or penalty. Amounts repaid can be re-borrowed during the facility's term. The Commodity-linked Revolver is secured pari passu on substantially the same collateral and guaranteed by the same guarantors as the Corporate Revolving Facility. Borrowings under this facility are therefore guaranteed and secured by certain of our current domestic subsidiaries and will also be additionally guaranteed by future domestic subsidiaries that are required to provide such a guarantee in accordance with the terms of the agreements. The facility ranks equally in right of payment with all of the Company's and the guarantors’ other existing and future senior indebtedness and will be effectively subordinated in right of payment to all existing and future liabilities of subsidiaries that do not guarantee the facilities. Other corporate facilities The Company has several unsecured letters of credit facilities with third-party financial institutions totaling approximately $200 million and $325 million as of December 31, 2025 and 2024, respectively. In June 2025, the Goldman Sachs CDS backed letter of credit facility totaling approximately $125 million expired and was not renewed. The above amounts exclude available capacity under the Corporate Revolving Facility, the capacity of Calpine Development Holdings, LLC (“CDHI”) under the CDHI Credit Agreement, and under our project financing credit facilities at GPC, Greenfield L.P. and Nova Power, LLC. There are also four bilateral letter of credit agreements for up to $525 million and $525 million of capacity with varying tenors as of December 31, 2025 and 2024, respectively. On January 31, 2024, the Company extended one bilateral letter of credit agreement with a notional amount of $150 million from January 2025 to January 2027. First Lien Term Loans First Lien Term Loans are summarized in the table below (in millions, except for interest rates): Outstanding at December 31, Weighted Average Effective Interest Rates(1) 2025 2024 2025 2024 2032 First Lien Term Loan $ 852 $ 851 6.3 % 3.0 % 2031 First Lien Term Loans 1,636 1,633 6.3 % 3.6 % Total $ 2,488 $ 2,484 ______________ (1) The weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount, as well as the cash settlement contribution of interest rate hedging instruments. 2032 First Lien Term Loan On December 16, 2020, the Company entered into a $1.0 billion first lien senior secured term loan, referred to as the 2027 First Lien Term Loan, which bears interest, at the Company's option, at either (1) the Base Rate, equal to the highest of (a) the Federal Funds Effective Rate plus 0.50% per annum, (b) the Prime Rate or (c) Adjusted term SOFR for a one month tenor in effect plus 1.00% (in each case, as such terms are defined in the term loan agreement), plus an applicable margin of 1.50% per annum, or (2) Adjusted Term SOFR Rate plus an applicable margin of 2.50% per annum and matures on December 16, 2027. On January 31, 2024, the 2027 First Lien Term Loan was amended to reduce the applicable margin to 1.00% per annum for Base Rate loans and 2.00% per annum for Term SOFR Rate loans. An aggregate amount equal to 0.25% of the aggregate principal amount is payable at the end of each quarter, with the remaining balance payable on the maturity date. An upfront fee was paid in an amount equal to 1.00% of the aggregate principal amount, which is structured as an original issue discount and recorded approximately $12 million in debt issuance costs during the fourth quarter of 2020 related to the issuance of the 2027 First Lien Term Loan. The 2027 First Lien Term Loan contains substantially similar covenants, qualifications, exceptions and limitations as the First Lien Term Loans and First Lien Notes. On August 3, 2023, the Company used the excess proceeds from the CCFC Term Loan refinancing, along with cash on hand, to pay down $275 million of the borrowings outstanding under the 2027 First Lien Term Loan, leaving a remaining 47

outstanding principal of $691 million as of December 31, 2023. This resulted in a loss on debt extinguishment of $4 million, consisting of the write-off of unamortized debt issuance costs. In December 2024, a refinancing of the 2027 First Lien Term Loans was completed, extending the maturity on the new total $860 million principal amount from December 2027 to February 2032. The refinancing reduced the applicable margin to 0.75% per annum for Base Rate loans and 1.75% per annum for Term SOFR Rate loans. The 2032 First Lien Term Loans no longer have quarterly amortizations. In addition, the Company recognized a loss on extinguishment of debt of $6 million related to the refinancing. See Note 19, Subsequent Events, for further discussion of transactions occurring subsequent to December 31, 2025. 2031 First Lien Term Loans On August 12, 2019 and on April 5, 2019, the Company entered into $750 million and $950 million first lien senior secured term loans, respectively, collectively, referred to as the 2026 First Lien Term Loans. On January 31, 2024, the Company refinanced the 2026 First Lien Term Loans into the 2031 First Lien Term Loans totaling $1.7 billion in principal, with the original $750 million loan refinanced to $730 million and the original $950 million loan refinanced to $925 million. The maturity was extended from the original April and August 2026 dates to January 2031. These loans bear interest, at the Company's option, at either (1) the Base Rate, equal to the highest of (a) the Federal Funds Effective Rate plus 0.50% per annum, (b) the Prime Rate, or (c) Adjusted Term SOFR for a one-month tenor in effect plus 1.00% (in each case, as such terms are defined in the credit agreement) plus an applicable margin of 1.00% or (2) Adjusted Term SOFR plus 2.00% per annum (with a 0% floor). An aggregate amount equal to 0.25% of the aggregate principal amount is payable quarterly, with the remaining balance due at the January 2031 maturity. The Company paid an upfront fee in an amount equal to 0.50% and 1.0% of the $750 million and $950 million principal amounts, respectively, which were structured as original issue discounts. Debt issuance costs of approximately $11 million and $7 million were recorded in the third and second quarters of 2019, respectively. The 2031 First Lien Term Loans contained substantially similar covenants, qualifications, exceptions and limitations as the other First Lien Term Loans and First Lien Notes. In December 2024, a repricing of the 2031 First Lien Term Loans was completed and consolidated into a single term loan, reducing the applicable margin to 0.75% per annum for Base Rate loans and 1.75% per annum for Term SOFR Rate loans. The 2031 First Lien Term Loans no longer have quarterly amortizations. The term remained unchanged through January 2031. In addition, the Company recognized a loss of $4.7 million, related to the repricing and consolidation. CCFC Term Loan The CCFC Term Loan is summarized in the table below (in millions, except for interest rates): Outstanding at December 31, Weighted Average Effective Interest Rates(1) 2025 2024 2025 2024 CCFC Term Loan $ 2,095 $ 1,864 6.4 % 5.2 % ____________ (1) The weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount, as well as the cash settlement contribution of interest rate hedging instruments. On December 15, 2017, CCFC entered into a credit agreement providing for a $1.000 billion first-lien senior secured term loan facility. On August 2, 2023, CCFC amended the CCFC Term Loan facility, increasing the total capacity to $1.250 billion and extending the maturity to July 31, 2030. On June 6, 2024, the facility was further amended through repricing that reduced the applicable SOFR spread and removed quarterly principal payments prior to maturity. Subsequently, on September 16, 2024, CCFC refinanced to increase the total principal amount to $1.875 billion. The CCFC Term Loan bears interest, at CCFC’s option, at either (1) the Base Rate, equal to the highest of (a) the Federal Funds Effective Rate plus 0.50% per annum, (b) the Prime Rate or (c) the Term SOFR for a month tenor (as such terms are defined in the Credit Agreement) plus 1.00% per annum, plus an applicable margin of 1.00% per annum, or (2) Term SOFR plus 2.00% per annum. The Company paid an upfront fee of an amount equal to 0.75% of the aggregate principal amount, which is structured as an original issue discount, and recorded approximately $15 million in debt issuance costs during the third quarter of 2023 related to the refinancing. In addition, a loss on extinguishment of debt of $11 million was recognized 48

including, the write-off of unamortized debt issuance costs of $2 million and costs incurred during the refinancing of $9 million. On November 18, 2025, CCFC refinanced to increase the total notional principal amount of the CCFC Term Loan from $1.875 billion to $2.100 billion. The term of the credit agreement remained unchanged through June 2030. As a result, the Company recognized a loss on extinguishment of debt of approximately $7 million, including a loss of $5 million related to the write-off of existing debt issuance costs and $0.8 million of existing original issue discount costs. The CCFC Term Loan refinance new original discount costs for $0.3 million was expensed to loss on extinguishment of debt, and the debt issuance cost for $2.4 million of which $0.8 million debt issuance cost was expensed to loss on extinguishment of debt and the remaining $1.6 million was capitalized as deferred financing cost. The CCFC Term Loan is secured by certain real and personal property of CCFC, consisting primarily of seven natural gas-fired power plants. The CCFC Term Loan is not guaranteed by Calpine Corporation and is without recourse to Calpine Corporation or any of its non-CCFC subsidiaries or assets; however, CCFC generates the majority of its cash flows from an intercompany tolling agreement with Calpine Energy Services, L.P. and has various service agreements in place with other subsidiaries of Calpine Corporation. GPC Term Loan The GPC Term Loan is summarized in the table below (in millions, except for interest rates): Outstanding at December 31, Weighted Average Effective Interest Rates(1) 2025 2024 2025 2024 GPC Term Loan $ 1,375 $ 1,486 4.2 % 4.3 % ____________ (1) The weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount, as well as the cash settlement contribution of interest rate hedging instruments. On November 9, 2021, Geysers Power Company, LLC (“GPC”) and the guarantor's party thereto amended the existing seven-year $900 million first lien senior secured term loan facility upsizing the facility, to $1.500 billion and extending the maturity to November 9, 2028. Additionally, the three senior secured revolving letter of credit facilities totaling $200 million were amended to a single revolving letter of credit facility with an available capacity of $250 million and a maturity date of November 9, 2028. On May 31, 2022, GPC amended the then existing seven-year $1.500 billion first lien senior secured term loan facility by upsizing the facility to $1.770 billion, extending the maturity to May 31, 2029, and adjusting the interest rate from the London Inter-Bank Offered Rate (“LIBOR”) + 162.5 basis points (“bps”) to SOFR + 150 bps, reducing the all-in rate by 12.5 bps. Additionally, the revolving letter of credit facility with an available capacity of $250 million was amended, extending the maturity date to May 31, 2029, and providing the ability to draw up to $50 million in loans for eligible battery projects based on terms within the amended agreement. Proceeds from the amended GPC Term Loan were used for general corporate purposes, including but not limited to the repayment of other Calpine debt and future renewable project development. The GPC Term Loan is certified under the Climate Bonds Standard. Any letters of credit issued under the GPC Term Loan letter of credit facilities must be at the request of, and for, the account of GPC. The GPC Term Loan bears interest, at GPC’s option, at either (1) the Base Rate, equal to the highest of (a) the Federal Funds Rate plus 0.5% per annum, (b) the Prime Rate published by the Wall Street Journal, or (c) Adjusted one-month Term SOFR plus 1.00%, or (2) SOFR plus an applicable margin of 1.50% per annum, increasing by 0.125% every three years. The GPC Term Loan includes amortizing payments over the seven-year term with a final payment at maturity but may be prepaid at any time upon irrevocable notice to the Administrative Agent. The GPC Term Loan is secured by certain real and personal property of GPC and its restricted subsidiaries consisting primarily of the Geysers Assets. The GPC Term Loan is not guaranteed by Calpine Corporation and is without recourse to Calpine Corporation or any of its non-GPC subsidiaries or assets; however, GPC generates a portion of its cash flows from an intercompany tolling agreement with Calpine Energy Services, L.P. and has various service agreements in place with other subsidiaries of Calpine Corporation. 49

Construction Loan Facilities, Project Financing, Notes Payable and Other The Company's construction loan facilities, project financing, notes payable and other debt are summarized in the table below (in millions, except for interest rates): Outstanding at December 31, Weighted Average Effective Interest Rates(1) 2025 2024 2025 2024 Nova $ 578 $ 607 5.9 % 7.8 % Pasadena(2) 3 4 8.8 % 8.4 % Bethpage Energy Center 3 due 2025(3) — 7 6.8 % 6.8 % Greenfield 337 332 6.3 % 6.5 % Other(4) 12 47 5.2 % 3.9 % Total $ 930 $ 997 _____________ (1) The weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount, as well as the cash settlement contribution of interest rate hedging instruments, as applicable. (2) Represents a failed sale-leaseback transaction that is accounted for as a financing transaction under U.S. GAAP. (3) Represents a weighted average of first and second-lien loans for the weighted average effective interest rates. (4) The Company has $10 million and $45 million as of December 31, 2025 and 2024, respectively, of related party debt outstanding with Calpine Receivables offset against its investment in the entity. During the year ended December 31, 2025 , the Company wrote off $35 million in related party debt outstanding with Calpine Receivables which offset its investment in the entity. Nova Power Credit Facility On December 21, 2023, the Company, through its wholly-owned subsidiary, Nova Power, LLC, entered into a credit agreement comprising certain credit facilities to finance a portion of the costs of the development, construction, and operation of the Nova power battery storage project. The credit facilities total more than $1.000 billion, including (a) an aggregate principal amount of $655 million (“Construction Facility”), (b) an aggregate principal amount of $256 million (“Bridge Facility”), available until the facility’s investment tax credits are received, and (c) letter of credit facilities available to support various obligations with $94 million of total available capacity. The financing received Climate Bond Certification as green financing. On September 17, 2024, proceeds of $353 million were used from the sale of certain investment tax credits related to the Nova battery storage facilities to repay the outstanding $183 million principal and interest balance on the Bridge Facility in full. This activity resulted in a total drawn principal balance of $578 million and $607 million and as of December 31, 2025 and 2024, respectively, on the Nova Credit Agreement. On October 31, 2024, Calpine Corporation, through its wholly-owned subsidiary Nova Power Holdco, converted the existing Nova Power Battery Facility construction loan to a first-lien term loan with a total notional balance outstanding of $640 million and a term of seven years from the conversion date. The Term Loan maturity date is the seventh anniversary of the Term Loan Conversion Date. SOFR-based loans under the Nova Credit Agreement will bear interest at the Daily Compounded SOFR plus 1.75%. Alternate Base Rate ("ABR") Loans, as defined in the agreement, will bear interest at the ABR rate, defined as the per annum rate equal to the greatest of: (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus ½ of 1.00% and (c) the Daily Compounded SOFR then in effect (assuming a one-month Interest Period) plus 1.00%, plus an applicable margin. The applicable margin for both SOFR Loans and ABR Loans varies based on the nature of the loan and other considerations, as specified in the credit agreement. Approximately $23 million in debt issuance costs were recorded during the fourth quarter of 2023 related to the Nova Credit Agreement. The Nova Credit Agreement is secured by all of Nova Power's real and personal property. In addition, Nova Power Holdco, LLC, the parent of Nova Power, LLC, has agreed to secure its equity interest in Nova Power, LLC to the lenders, along with its rights to certain intercompany agreements related to the purchase of equipment for the project. Additionally, certain assets of additional wholly-owned subsidiaries of Calpine have pledged certain equity interests and certain third-party agreements to the creditors. The Nova Credit Agreement is not guaranteed by Calpine Corporation and is without recourse to Calpine Corporation other than the bridge facility. 50

Greenfield Credit Facility On September 5, 2023, we completed the acquisition of the remaining 50% equity interest of Greenfield L.P. as detailed in Note 5, Acquisitions and Divestitures. As of the acquisition date, the debt balance held by Greenfield L.P. totaled $263 million CAD ($193 million USD) with a term through September 2028. On November 14, 2023, Greenfield L.P. entered into the second amended and restated credit agreement, which increased the notional amount of the term loan to $500 million CAD and extended the term of the credit agreement through November 14, 2030 (“Greenfield Credit Agreement”). As of December 31, 2025, the Greenfield Credit Agreement is comprised of a term loan facility with an outstanding balance of $469 million CAD ( $342 million USD) and several letter of credit facilities with a total available capacity of $29 million CAD ($21 million USD) to support various obligations of Greenfield LP and is secured by the real and personal property of Greenfield L.P. without recourse to Calpine Corporation or any of its non-Greenfield subsidiaries or assets. Proceeds from the amended credit agreement will primarily be used to construct an expansion upgrade at the Greenfield facility. The term loan incurs interest based on either the Canada Prime Rate or the Canada Overnight Repo Rate Average (“CORRA”) plus an applicable margin, as defined in the credit agreement. We recorded approximately $12 million CAD in debt issuance costs during the fourth quarter of 2023 related to the refinancing of the Greenfield Credit Agreement. Master Securities Lending Transaction On December 13, 2022, the Company, through its wholly-owned subsidiary, Calpine Energy Services, L.P., entered into a master securities lending transaction with JPMorgan Chase, N.A. that allows for JPMorgan Chase, N.A. to lend U.S. Treasury securities to this subsidiary in exchange for letters of credit. This subsidiary uses the U.S. Treasury securities to post collateral for commodity transactions on market exchanges. The total value of the letters of credit provided as collateral for the Treasury securities is based on the fair market value of the U.S. Treasury securities and will fluctuate daily. The subsidiary pays a loan fee for all amounts not collateralized by cash collateral, as specified in the agreement. On June 1, 2023, Calpine Energy Services, L.P. renewed an existing $95 million loan executed under the master securities lending transaction, extending the term of the loan through February 15, 2024. On February 15, 2024, the loan was further extended to November 1, 2024. The Company had entered into an underlying loan with a notional amount of $105 million for a term through November 1, 2024, and posted letters of credit as collateral totaling $200 million for the above two loans. The agreement expired on November 1, 2024. As of December 31, 2025, the Company has no outstanding balance for the above two loans. This agreement was accounted for as a financing transaction on the Consolidated Balance Sheets. Outside of the master securities lending transaction discussed above, project financings are collateralized solely by the capital stock or partnership interests, physical assets, contracts and/or cash flows attributable to the entities that own the power plants. The lenders’ recourse under these specific project financings is limited to such collateral. Senior Unsecured Notes The Senior Unsecured Notes are summarized in the table below (in millions, except for interest rates): Outstanding at December 31, Weighted Average Effective Interest Rates(1) 2025 2024 2025 2024 2028 Senior Unsecured Notes $ 1,397 $ 1,395 5.3 % 5.3 % 2029 Senior Unsecured Notes 647 646 4.8 % 4.8 % 2031 Senior Unsecured Notes 845 845 5.1 % 5.1 % Total $ 2,889 $ 2,886 ____________ (1) The weighted average interest rate calculation includes the amortization of debt issuance costs. On December 27, 2019, the Company issued $1.400 billion in aggregate principal amount of 5.13% senior unsecured notes due 2028 in a private placement (“2028 Senior Unsecured Notes”). The 2028 Senior Unsecured Notes bear interest at 5.13% per annum, with interest payable semi-annually on March 15 and September 15 of each year, beginning on September 15, 2020. The 2028 Senior Unsecured Notes mature on March 15, 2028. On August 10, 2020, the Company issued $650 million in aggregate principal amount of 4.63% senior unsecured notes due 2029 ("2029 Senior Unsecured Notes") and $850 million in aggregate principal amount of 5.00% senior unsecured notes 51

due 2031(“2031 Senior Unsecured Notes”) in private placements. The 2029 Senior Unsecured Notes bear interest at 4.63% per annum, and the 2031 Senior Unsecured Notes bear interest at 5.00% per annum, with interest payable on both series of notes semi-annually on February 1 and August 1 of each year, beginning on February 1, 2021. The Senior Unsecured Notes are: • general unsecured obligations of Calpine; • rank equally in right of payment with all of Calpine’s existing and future senior indebtedness; • effectively subordinated to Calpine’s secured indebtedness to the extent of the value of the collateral securing such indebtedness; • structurally subordinated to any existing and future indebtedness and other liabilities of Calpine’s subsidiaries; and • senior in right of payment to any of Calpine’s subordinated indebtedness. First Lien Notes The First Lien Notes are summarized in the table below (in millions, except for interest rates): Outstanding at December 31, Weighted Average Effective Interest Rates(1) 2025 2024 2025 2024 2026 First Lien Notes $ — $ 139 — % 6.2 % 2028 First Lien Notes 1,246 1,244 4.7 % 4.7 % 2031 First Lien Notes 894 893 3.9 % 3.9 % Total $ 2,140 $ 2,276 ____________ (1) The weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount. 2026 First Lien Notes On December 15, 2017, the Company issued $560 million in aggregate principal amount of 5.25% senior secured notes due 2026 in a private placement. Additionally, on May 31, 2016, the Company issued $625 million in aggregate principal amount of 5.25% senior secured notes due 2026 in a private placement. The 2026 First Lien Notes bear interest at 5.25% payable semi-annually on June 1 and December 1 of each year. The 2026 First Lien Notes mature on June 1, 2026, and contain substantially similar covenants, qualifications, exceptions, and limitations as the First Lien Notes. On September 25, 2024, the Company issued notice to redeem the outstanding principal of the 2026 First Lien Notes, and on October 25, 2024, a partial redemption for $286 million was completed, including accrued interest. On December 10, 2024, the Company issued notice to redeem the remaining outstanding principal of the 2026 First Lien Notes, and on January 9, 2025, a redemption for $140 million was completed, including accrued interest. Approximately $8 million in debt issuance costs was recorded during the fourth quarter of 2017 related to the issuance of a portion of the 2026 First Lien Notes and approximately $9 million in debt issuance costs during the second quarter of 2016 related to the issuance of a portion of the 2026 First Lien Notes. 2031 First Lien Notes On December 16, 2020, the Company issued $900 million in aggregate principal amount of 3.75% senior secured notes due 2031 in a private placement. The 2031 First Lien Notes bear interest at 3.75%, payable semiannually on March 1 and September 1 of each year beginning on September 1, 2021. The 2031 First Lien Notes mature on March 1, 2031, and contain substantially similar covenants, qualifications, exceptions, and limitations as the First Lien Notes. Approximately $12 million in debt issuance costs was recorded during the fourth quarter of 2020 related to the issuance of the 2031 First Lien Notes. 2028 First Lien Notes On December 20, 2019, the Company issued $1.25 billion in aggregate principal amount of 4.50% senior secured notes due 2028 in a private placement. The 2028 First Lien Notes bear interest at 4.50% payable semi-annually on February 15 and August 15 of each year, beginning on August 15, 2020. The 2028 First Lien Notes mature on February 15, 2028, and contain substantially similar covenants, qualifications, exceptions, and limitations as our First Lien Notes. We recorded 52

approximately $16 million in debt issuance costs during the fourth quarter of 2019 related to the issuance of the 2028 First Lien Notes. First Lien Notes The First Lien Notes are secured equally and ratably with indebtedness incurred under the First Lien Term Loans and Corporate Revolving Facility, subject to certain exceptions and permitted liens, on substantially all of the Company's and certain of the guarantors’ existing and future assets. Additionally, the First Lien Notes rank equally in right of payment with all the Company's and the guarantors’ other existing and future senior indebtedness and will be effectively subordinated in right of payment to all existing and future liabilities of subsidiaries that do not guarantee the First Lien Notes. Subject to certain qualifications and exceptions, the First Lien Notes will, among other things, limit the Company's ability and the ability of the guarantors to: • incur or guarantee additional first-lien indebtedness; • enter into certain types of commodity hedge agreements that can be secured by first lien collateral; • enter into sale and leaseback transactions; • create or incur liens; and • consolidate, merge, or transfer all or substantially all of Company assets and the assets of restricted subsidiaries on a combined basis. Finance Lease Obligations See Note 4, Leases, for disclosures related to finance lease obligations. Fair Value of Debt The Company records debt instruments based on contractual terms, net of any applicable premium or discount, and debt issuance costs. The following table details the fair values and carrying values of debt instruments (in millions): December 31, 2025 2024 Fair Value Carrying Value Fair Value Carrying Value Senior Unsecured Notes $ 2,912 $ 2,889 $ 2,750 $ 2,886 First Lien Term Loans 2,509 2,488 2,502 2,484 First Lien Notes 2,120 2,140 2,139 2,275 CCFC Term Loan 2,103 2,095 1,870 1,864 GPC Term Loan 1,392 1,375 1,508 1,486 Construction loan facilities, project financing, notes payable and other(1) 945 927 1,014 993 Revolving facilities 548 548 148 148 Total $ 12,529 $ 12,462 $ 11,931 $ 12,136 ____________ (1) Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP. The Company's Senior Unsecured Notes, First Lien Term Loans, First Lien Notes and CCFC Term Loan are categorized as Level 2 within the fair value hierarchy. The GPC Term Loan, revolving facilities, construction loan facilities, project financing, notes payable and other debt instruments are categorized as Level 3 within the fair value hierarchy. The Company does not have any debt instruments with fair value measurements categorized as Level 1 within the fair value hierarchy. 9. Assets and Liabilities with Recurring Fair Value Measurements Cash Equivalents — Highly liquid investments that meet the definition of cash equivalents, primarily investments in money market accounts and other interest-bearing accounts, are included in both cash and cash equivalents and restricted cash on the Consolidated Balance Sheets. Certain money market accounts involve investing in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. The Company does not have any 53

cash equivalents invested in institutional prime money market funds which require use of a floating net asset value and are subject to liquidity fees and redemption restrictions. Certain cash equivalents are classified within Level 1 of the fair value hierarchy. Derivatives — The Company's derivative instruments include physical and financial commodity contracts as well as interest rate swap agreements that meet the definition of a derivative instrument. The primary factors affecting the fair value of the derivative instruments at any point in time are the volume of open derivative positions MMBtu, MWh and $ notional amounts; changing commodity market prices, primarily for power and natural gas; the Company's credit standing and that of its counterparties and customers for energy commodity derivatives; and prevailing interest rates for interest rate instruments. Prices for power and natural gas and interest rates are volatile, which can result in material changes in the fair value measurements reported in future financial statements. The Company uses market data, such as pricing services and broker quotes, and assumptions that it believes market participants would use in pricing its assets or liabilities, including assumptions about the risks inherent to the inputs in the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. The market data obtained from broker pricing services is evaluated to determine the nature of the quotes obtained and, where accepted as a reliable quote, used to validate the assessment of fair value. The Company uses other qualitative assessments to determine the level of activity in any given market. The Company primarily applies the market approach and income approach for recurring fair value measurements and uses the best available information. Valuation techniques are used which seek to maximize the use of observable inputs and minimize the use of unobservable inputs. Fair value balances are classified based on the observability of those inputs. The fair value of the derivatives includes consideration of the Company's credit standing, the credit standing of its counterparties and customers, and the effect of credit enhancements, if any. Credit reserves have been recorded in the determination of fair value based on the expectation of how market participants would determine fair value. Such valuation adjustments are generally based on market evidence, if available, or the best estimate. Level 1 fair value derivative instruments primarily consist of power and natural gas swaps, futures and options traded on the NYMEX or ICE. Level 2 fair value derivative instruments primarily consist of interest rate instruments and OTC power and natural gas forwards for which market-based pricing inputs in the principal or most advantageous market are representative of executable prices for market participants. These inputs are observable at commonly quoted intervals for substantially the full term of the instruments. In certain instances, Level 2 derivative instruments may use models to measure fair value. These models are industry-standard models, including the Black-Scholes option-pricing model, which incorporates various assumptions, including quoted interest rates, correlation, volatility, as well as other relevant economic measures. All of these assumptions are observable in the marketplace throughout the full term of the instrument, it can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Level 3 fair value derivative instruments may consist of OTC power and natural gas forwards and options where pricing inputs are unobservable, as well as other complex and structured transactions primarily for the sale and purchase of power and natural gas to both wholesale counterparties and retail customers. Complex or structured transactions are tailored to customers' needs and can introduce the need for internally developed model inputs which might not be observable in or corroborated by the market. When such inputs have a significant effect on the measurement of fair value, the instrument is categorized in Level 3. Valuation models used may incorporate historical correlation information and extrapolate available broker and other information to future periods. 54

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement at period end. Determining the significance of a particular input to the fair value measurement requires judgment and may affect the fair value estimate of assets and liabilities and their placement within the fair value hierarchy levels. The following tables present the Company's assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2025, and 2024, by level within the fair value hierarchy (in millions): Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2025 Level 1 Level 2 Level 3 Total Assets: Cash equivalents(1) $ 1,282 $ — $ — $ 1,282 Commodity instruments: Commodity exchange traded derivatives contracts 1,545 — — 1,545 Commodity forward contracts(2) — 366 1,563 1,929 Interest rate derivative instruments — 106 — 106 Effect of netting and allocation of collateral(3)(4) (1,545) (200) (76) (1,821) Total assets $ 1,282 $ 272 $ 1,487 $ 3,041 Liabilities: Commodity instruments: Commodity exchange traded derivatives contracts $ 2,146 $ — $ — $ 2,146 Commodity forward contracts(2) — 490 411 901 Interest rate derivative instruments — 10 — 10 Effect of netting and allocation of collateral(3)(4) (2,146) (196) (36) (2,378) Total liabilities $ — $ 304 $ 375 $ 679 Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2024 Level 1 Level 2 Level 3 Total Assets: Cash equivalents(1) $ 295 $ — $ — $ 295 Commodity instruments: Commodity exchange traded derivatives contracts 1,768 — — 1,768 Commodity forward contracts(2) — 567 649 1,216 Interest rate derivative instruments — 257 — 257 Effect of netting and allocation of collateral(3)(4) (1,768) (270) (65) (2,103) Total assets $ 295 $ 554 $ 584 $ 1,433 Liabilities: Commodity instruments: Commodity exchange traded derivatives contracts $ 1,782 $ — $ — $ 1,782 Commodity forward contracts(2) — 399 600 999 Interest rate derivative instruments — 10 — 10 Effect of netting and allocation of collateral(3)(4) (1,782) (257) (48) (2,087) Total liabilities $ — $ 152 $ 552 $ 704 ___________ (1) As of December 31, 2025 and 2024, there were cash equivalents of $1,029 million and $35 million included in cash and cash equivalents and $253 million and $260 million included in restricted cash, respectively. (2) Includes OTC swaps and options. (3) Fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation; therefore, amounts recognized for the right to reclaim, or the obligation to return, cash collateral are 55

presented net with the corresponding derivative instrument fair values. See Note 10, Derivative Instruments, for further discussion of derivative instruments subject to master netting arrangements. (4) Cash collateral posted with (received from) counterparties allocated to Level 1, Level 2 and Level 3 derivative instruments totaled $601 million, $(4) million and $(40) million, respectively, as of December 31, 2025. Cash collateral posted with (received from) counterparties allocated to Level 1, Level 2, and Level 3 derivative instruments totaled $14 million, $(13) million and $(17) million, respectively, as of December 31, 2024. As of December 31, 2025 and 2024, respectively, the derivative instruments classified as Level 3 primarily included commodity contracts. As noted in the table below, forward commodity prices are the significant unobservable input resulting in a Level 3 classification. Significant changes in forward commodity prices would have a direct impact on the fair values of the Level 3 derivatives which could be material. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give us the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give us the obligation or right to sell a commodity). Further, interrelationships exist between market prices of natural gas and power which will also impact the change in fair value of these instruments. For example, an increase in natural gas pricing would potentially have a similar impact on forward power markets. The following table presents quantitative information regarding the Level 3 fair value measurements as of December 31, 2025 and 2024. As noted in the tables presented below, the range in prices noted did not result in a significant shift in the fair value of Level 3 derivatives (in millions). Quantitative Information about Level 3 Fair Value Measurements December 31, 2025 Fair Value, Net Asset Valuation Significant Unobservable (Liability) Technique Input Range Average Power Contracts(1) $ 1,001 Discounted cash flow Market price (per MWh) $4.42 - $333.44/MWh $75.97/ MWh Power Congestion Products $ 40 Discounted cash flow Market price (per MWh) $(28.04) - $153.48/MWh $3.83/ MWh Natural Gas Contracts $ 71 Discounted cash flow Market price (per MMBtu) $(0.57) - $17.62/MMBtu $3.01 MMBtu Quantitative Information about Level 3 Fair Value Measurements December 31, 2024 Fair Value, Net Asset Valuation Significant Unobservable (Liability) Technique Input Range Average Power Contracts(1) $ (65) Discounted cash flow Market price (per MWh) $3.83 - $269.92/MWh $63.78/ MWh Power Congestion Products $ 32 Discounted cash flow Market price (per MWh) $(26.03) - $125.37/MWh $(3.20)/ MWh Natural Gas Contracts $ 65 Discounted cash flow Market price (per MMBtu) $1.97 - $17.00/MMBtu $6.35 MMBtu ___________ (1) Power contracts include power and Heat Rate instruments classified as Level 3 in the fair value hierarchy. 56

The following table sets forth certain information related to changes in the fair value of net derivative assets (liabilities) classified as Level 3 in the fair value hierarchy for the periods indicated (in millions): Year Ended December 31, 2025 2024 2023 Balance, beginning of period $ 32 $ 150 $ (304) Realized and mark-to-market gains (losses): Included in net income: Included in operating revenues(1)(6) 1,003 (169) 162 Included in fuel and purchased energy expense(2) 48 44 (20) Changes in collateral 22 (8) 19 Purchases and issuances: Purchases 30 33 27 Issuances (1) — — Settlements (30) (30) 308 Transfers into and/or out of Level 3(3): Transfers into Level 3(4) 4 8 (11) Transfers out of Level 3(5) 4 4 (31) Balance, end of period $ 1,112 $ 32 $ 150 Change in unrealized gains (losses) included in net income relating to instruments still held at the end of the period $ 1,051 $ (125) $ 142 ___________ (1) For power contracts and other power-related products, included in the Consolidated Statements of Operations. (2) For natural gas and power contracts, swaps and options are included in the Consolidated Statements of Operations. (3) We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no transfers into or out of Level 1 during the years ended December 31, 2025, 2024 and 2023. (4) There were $4 million in gains, $8 million in gains and $11 million in losses transferred out of Level 2 into Level 3 for the years ended December 31, 2025, 2024 and 2023, respectively. (5) There were $4 million in losses, $4 million in losses and $31 million in gains transferred out of Level 3 into Level 2 for the years ended December 31, 2025, 2024 and 2023, respectively. (6) Includes fair value associated with long-term structured deals previously classified as normal purchase/normal sale that are now being accounted for as derivative contracts beginning in the fourth quarter of 2025. 10. Derivative Instruments Types of Derivative Instruments and Volumetric Information Commodity Instruments — The Company is exposed to changes in prices for the purchase and sale of power, natural gas, fuel oil, environmental products and other energy commodities. The Company uses derivatives, including physical and financial commodity instruments such as OTC and exchange-traded swaps, futures, options, forward agreements and instruments that settle on power price to natural gas price relationships (Heat Rate swaps and options) or price relationships between delivery points in order to maximize risk-adjusted returns through economically hedging a portion of the commodity price risk associated with the Company's assets. By entering into these transactions, a portion of the Spark Spread can be economically hedged at estimated generation and prevailing price levels. The Company also engages in limited trading activities related to its commodity derivative portfolio as authorized by the Board of Directors and monitored by the Chief Risk Officer and Risk Management Committee of senior management. These transactions are executed primarily for the purpose of providing improved price and price volatility discovery, greater market access and profiting from the market knowledge, all of which benefit the asset hedging activities. Trading results were not material for the years ended December 31, 2025, 2024 and 2023. Interest Rate Instruments — A portion of the debt is indexed to base rates, currently primarily SOFR. Effective July 1, 2023, debt agreements and interest rate instruments based on LIBOR were converted to SOFR, resulting in no material impact on the results of operations. The Company has historically used interest rate derivative instruments to adjust the mix between fixed and variable rate debt to hedge our interest rate risk for potential adverse changes in interest rates. 57

The net forward notional buy (sell) position of outstanding commodity derivative instruments that did not qualify or were not designated under the normal purchase normal sale exemption and the aggregate notional amount of interest rate derivative instruments were as follows: Derivative Instruments Notional Amounts December 31, 2025 2024 Unit of Measure Power (MWh) (382) (288) Million MWh Natural gas (MMBtu) 1,555 1,536 Million MMBtu Environmental credits (Tonnes) 12 25 Million Tonnes Oil (gallons) 8 — Million gallons Interest rate derivative instruments $ 4.7 $ 5.8 Billion U.S. dollars Certain of the derivative instruments contain credit risk-related contingent provisions that require maintaining collateral balances consistent with the Company's credit ratings. If the credit rating were to be downgraded, it could require posting additional collateral or could potentially allow the counterparty to request immediate, full settlement on certain derivative instruments in liability positions. The aggregate fair value of derivative liabilities with credit risk-related contingent provisions as of December 31, 2025, was $105 million for which we have posted collateral of $45 million, by posting margin deposits, letters of credit or granting additional first priority liens on the assets currently subject to first priority liens under the First Lien Credit Facility. However, if the Company's credit rating were downgraded from its current level, it is estimated that $18 million of additional collateral would be required and that no counterparty could request immediate, full settlement. Accounting for Derivative Instruments All derivative instruments are recognized that qualify for derivative accounting treatment as either assets or liabilities and those instruments are measured at fair value unless they qualify for, and we elect the normal purchase normal sale exemption. For transactions in which the Company elects the normal purchase normal sale exemption, gains and losses are not reflected in the Consolidated Statements of Operations until the period of delivery. Revenues and expenses derived from instruments that are qualified for hedge accounting or represent an economic hedge are recorded in the same financial statement line item as the item being hedged. Hedge accounting requires formal documentation, designation and assessment of the effectiveness of transactions that receive hedge accounting. Cash flows from the derivatives are presented in the same category as the item being hedged (or economically hedged) within operating activities in the Consolidated Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows are classified within financing activities. Cash Flow Hedges — The Company has elected to designate certain of the commodity and interest rate derivative instruments in cash flow hedging relationships where the accounting rules permit. As a result, we currently apply hedge accounting to a portion of the interest rate and commodity hedging instruments with the change in fair value of all other hedging instruments recorded through earnings. Effective September 1, 2025, the Company elected to discontinue hedge accounting for all commodity hedges of future generation fleet sales and fuel procurement activity. Effective December 1, 2025, the Company elected to discontinue hedge accounting for all interest rate hedging relationships. In both cases the mark- to-market gains or losses associated with all such contracts remain frozen in OCI as of the date of discontinuation of hedge accounting treatment. All such balances will be reclassified into earnings in the same period that the hedged forecasted transaction affects earnings with any future changes in fair value recorded to earnings directly. At December 31, 2025, approximately $535 million in commodity hedge value and approximately $14 million in interest rate hedge value is recorded to OCI which will amortize to earnings over the life of the derivative contract. Mark-to-market gains or losses on our interest rate instruments designated and qualifying as a cash flow hedging instrument are reported as a component of OCI and reclassified as gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. If it is determined that the forecasted transaction is no longer probable to occur, then hedge accounting will be discontinued prospectively, and future changes in fair value will be recorded in earnings. For both designated and de-designated hedging instruments, if the contract is terminated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedging instrument remains deferred in AOCI until such time as the forecasted transaction affects earnings or until it is determined that the forecasted transaction is probable of not occurring. Derivatives Not Designated as Hedging Instruments — The Company enters into power, natural gas, interest rate, environmental product and fuel oil transactions as economic hedges of underlying forward exposure. The instruments primarily act as hedges to asset and interest rate portfolios, but do not qualify for hedge accounting under the accounting guidelines. Changes in the fair value of commodity derivatives not designated as hedging instruments are recognized currently in earnings 58

and are separately stated in the Consolidated Statements of Operations in mark-to-market gain/loss as a component of operating revenues (for physical and financial power and Heat Rate and commodity option activity) and fuel and purchased energy expense (for physical and financial natural gas, power, environmental product and fuel oil activity). Changes in the fair value of interest rate derivatives not designated as hedging instruments are recognized currently in earnings within interest expense. Derivatives Included on the Consolidated Balance Sheets Fair value amounts are offset, which are associated with the derivative instruments and related cash collateral and margin deposits on the Consolidated Balance Sheets that are executed with the same counterparty under master netting arrangements. These netting arrangements include a right to set off or net together purchases and sales of comparable products in the margining or settlement process. In some instances, cross-commodity netting rights were negotiated, which allow for the net presentation of activity with a given counterparty, regardless of product purchased or sold. Cash collateral in support of the derivative instruments is posted and/or received which may also be subject to a master netting arrangement with the same counterparty. The following tables present the fair values of the derivative instruments and the net exposure after offsetting amounts subject to a master netting arrangement with the same counterparty to the derivative instruments recorded on the Consolidated Balance Sheets by location and hedge type (in millions): December 31, 2025 Gross Amounts of Assets and (Liabilities) Gross Amounts Offset on the Consolidated Balance Sheet Net Amount Presented on the Consolidated Balance Sheet(1) Derivative assets: Commodity exchange-traded derivatives contracts $ 972 $ (972) $ — Commodity forward contracts 839 (152) 687 Interest rate derivative instruments 71 — 71 Total current derivative assets(2) 1,882 (1,124) 758 Commodity exchange-traded derivatives contracts 573 (573) — Commodity forward contracts 1,090 (124) 966 Interest rate derivative instruments 35 — 35 Total long-term derivative assets(2) 1,698 (697) 1,001 Total derivative assets $ 3,580 $ (1,821) $ 1,759 Derivative (liabilities): Commodity exchange-traded derivatives contracts $ (1,228) $ 1,228 $ — Commodity forward contracts (362) 134 (228) Interest rate derivative instruments (4) — (4) Total current derivative (liabilities)(2) (1,594) 1,362 (232) Commodity exchange-traded derivatives contracts (918) 918 — Commodity forward contracts (539) 98 (441) Interest rate derivative instruments (6) — (6) Total long-term derivative (liabilities)(2) (1,463) 1,016 (447) Total derivative (liabilities) (3,057) 2,378 (679) Net derivative assets (liabilities) $ 523 $ 557 $ 1,080 59

December 31, 2024 Gross Amounts of Assets and (Liabilities) Gross Amounts Offset on the Consolidated Balance Sheet Net Amount Presented on the Consolidated Balance Sheet(1) Derivative assets: Commodity exchange-traded derivatives contracts $ 1,230 $ (1,230) $ — Commodity forward contracts 685 (216) 469 Interest rate derivative instruments 110 — 110 Total current derivative assets(3) 2,025 (1,446) 579 Commodity exchange-traded derivatives contracts 538 (538) — Commodity forward contracts 531 (119) 412 Interest rate derivative instruments 147 — 147 Total long-term derivative assets(3) 1,216 (657) 559 Total derivative assets $ 3,241 $ (2,103) $ 1,138 Derivative (liabilities): Commodity exchange-traded derivatives contracts $ (1,212) $ 1,212 $ — Commodity forward contracts (515) 201 (314) Interest rate derivative instruments (2) — (2) Total current derivative (liabilities)(3) (1,729) 1,413 (316) Commodity exchange-traded derivatives contracts (570) 570 — Commodity forward contracts (484) 104 (380) Interest rate derivative instruments (8) — (8) Total long-term derivative (liabilities)(3) (1,062) 674 (388) Total derivative (liabilities) (2,791) 2,087 (704) Net derivative assets $ 450 $ (16) $ 434 ____________ (1) As of December 31, 2025, and 2024, there were $(98) million and $(87) million, respectively, of collateral under master netting arrangements that were not offset against our derivative instruments in the Consolidated Balance Sheets primarily related to initial margin requirements. (2) As of December 31, 2025, current and long-term derivative assets are shown net of collateral of $(71) million and $(68) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $308 million and $388 million, respectively. (3) As of December 31, 2024, current and long-term derivative assets are shown net of collateral of $(201) million and $(72) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $169 million and $88 million, respectively. The following tables present the fair values of our derivative assets and liabilities recorded in the Consolidated Balance Sheets (in millions): 60

December 31, 2025 December 31, 2024 Fair Value of Derivative Assets Fair Value of Derivative Liabilities Fair Value of Derivative Assets Fair Value of Derivative Liabilities Derivatives designated as cash flow hedging instruments: Commodity hedging instruments $ — $ — $ 19 $ 166 Interest rate hedging instruments — — 257 10 Total derivatives designated as cash flow hedging instruments $ — $ — $ 276 $ 176 Derivatives not designated as hedging instruments: Commodity derivative instruments $ 1,653 $ 669 $ 862 $ 528 Interest rate derivative instruments 106 10 — — Total derivatives not designated as hedging instruments $ 1,759 $ 679 $ 862 $ 528 Total derivatives $ 1,759 $ 679 $ 1,138 $ 704 Derivatives Included in the Consolidated Statements of Operations Changes in the fair values of our derivative instruments are reflected in cash for option premiums paid or collected, in OCI, net of tax, for derivative instruments which qualify for, and where cash flow hedge accounting treatment was elected, or in the Consolidated Statements of Operations as a component of mark-to-market activity within our earnings. The following tables detail the components of the total activity for both the net realized gain (loss) and the net mark- to-market gain (loss) recognized from the derivative instruments in earnings and where these components were recorded in the Consolidated Statements of Operations for the periods indicated (in millions): Year Ended December 31, 2025 2024 2023 Realized gain (loss)(1)(2)(4) Commodity derivative instruments $ 97 $ (206) $ 488 Interest rate derivative instruments 41 4 27 Total realized gain (loss) $ 138 $ (202) $ 515 Mark-to-market gain (loss)(3)(4) Commodity derivative instruments $ 532 $ 137 $ 883 Interest rate derivative instruments (20) (30) (18) Total mark-to-market gain (loss) $ 512 $ 107 $ 865 Total activity, net $ 650 $ (95) $ 1,380 ___________ (1) Does not include the realized value associated with derivative instruments that settle through physical delivery. (2) Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of the Quail Run Facility. (3) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also include adjustments to reflect changes in credit default risk exposure. (4) Does not include realized or unrealized market change associated with derivatives designated as hedges. 61

Year Ended December 31, 2025 2024 2023 Realized and mark-to-market gain (loss)(1) Derivatives contracts included in operating revenues(2)(3)(4) $ 828 $ 477 $ 2,666 Derivatives contracts included in fuel and purchased energy expense(2)(3)(4) (199) (546) (1,295) Interest rate derivative instruments included in interest expense 21 (26) 9 Total activity, net $ 650 $ (95) $ 1,380 ___________ (1) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also include adjustments to reflect changes in credit default risk exposure. (2) Does not include the realized value associated with derivative instruments that settle through physical delivery. (3) Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of the Quail Run Facility. (4) Does not include realized or unrealized market change associated with derivatives designated as hedges. Derivatives Included in OCI and AOCI The following table details the effect of our net derivative instruments that qualified for hedge accounting treatment and are included in OCI and AOCI for the periods indicated (in millions): (Loss) Gain Recognized in OCI Gain (Loss) Reclassified from AOCI into Income(2)(3) Year Ended December 31, Year Ended December 31, 2025 2024 2023 2025 2024 2023 Affected Line Item on the Consolidated Statements of Operations Interest rate hedging instruments $ (131) $ (52) $ (129) $ 76 $ 138 $ 158 Interest expense Interest rate hedging instruments 2 1 1 (2) (1) (1) Depreciation and amortization expense Commodity hedging instruments (410) (46) 1,221 43 (2) (418) Commodity revenue Commodity hedging instruments 69 329 (718) (29) (300) 67 Commodity expense Total(1) $ (470) $ 232 $ 375 $ 88 $ (165) $ (194) ____________ (1) Income tax benefit (expense) of $117 million, $(59) million and $(94) million for the years ended December 31, 2025, 2024 and 2023, respectively. (2) Cumulative net cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $(439) million, $(86) million and $(259) million for the years ended December 31, 2025, 2024 and 2023, respectively. (3) The year ended December 31, 2025, includes gains of $15 million that were reclassified from AOCI to interest expense related to anticipated paydown of hedged variable rate pursuant to the Constellation Merger, losses of $1 million that were reclassified from AOCI to depreciation expense, gains of $6 million that were reclassified from AOCI to operating revenue, and gains of $6 million that were reclassified from AOCI to fuel and purchased energy expense related to Assets Held for Sale pursuant to the Constellation Merger. There were no amounts that were reclassified from AOCI to either depreciation expense or interest expense for the years ended December 31, 2024 and 2023, respectively, where the hedged transactions became probable of not occurring. As of December 31, 2025, the maximum length of time over which we were hedging using interest rate and commodity derivative instruments as cash flow hedges was 6 years and 5 years, respectively. Effective September 1, 2025, the Company elected to discontinue hedge accounting for all commodity hedges with future changes in the fair value of all such derivatives recorded directly to earnings. It is estimated that pre-tax $13 million in net gains will be reclassified from AOCI into interest expense, $263 million in net losses will be reclassified from AOCI into commodity revenue and $64 million in net gains will be reclassified from AOCI into commodity expense during the next 12 months as the hedged transactions settle; however, the actual amounts that will be reclassified will likely vary based on changes in interest rates and commodity prices. Therefore, it is not possible to predict what the actual reclassification from AOCI into earnings (positive or negative) will be for the next 12 months. 62

11. Use of Collateral Margin deposits, prepayments and letters of credit are used as credit support with and from our counterparties for commodity procurement and risk management activities. In addition, the Company has granted additional first-priority liens on the assets currently subject to first priority liens under various debt agreements as collateral under certain of our power and natural gas agreements and certain of the interest rate derivative instruments in order to reduce the cash collateral and letters of credit that we would otherwise be provided to the counterparties under such agreements. The counterparties under such agreements share the benefits of the collateral subject to such first priority liens pro rata with the lenders under various debt agreements. The table below summarizes the balances outstanding under margin deposits, natural gas and power prepayments and exposure under letters of credit and first priority liens for commodity procurement and risk management activities (in millions): December 31, 2025 2024 Margin deposits(1) $ 706 $ 223 Natural gas and power prepayments 41 37 Total margin deposits and natural gas and power prepayments with our counterparties(2) $ 747 $ 260 Letters of credit issued $ 2,295 $ 1,855 First priority liens under power and natural gas agreements 375 350 Total letters of credit and first priority liens with our counterparties $ 2,670 $ 2,205 Margin deposits posted with us by our counterparties(1)(3) $ 247 $ 327 Letters of credit posted with us by our counterparties 232 128 Total margin deposits and letters of credit posted with us by our counterparties $ 479 $ 455 ___________ (1) The Company offsets fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation; therefore, amounts recognized for the right to reclaim, or the obligation to return, cash collateral are presented net with the corresponding derivative instrument fair values. See Note 10, Derivative Instruments, for further discussion of derivative instruments subject to master netting arrangements. (2) As of December 31, 2025 and 2024, $667 million and $175 million, respectively, amounts were included in current and long-term derivative assets and liabilities, $72 million and $78 million, respectively, were included in margin deposits and other prepaid expense and $8 million and $7 million, respectively, were included in other long-term assets in the Consolidated Balance Sheets. (3) As of December 31, 2025 and 2024, $110 million and $192 million, respectively, amounts were included in current and long-term derivative assets and liabilities, $137 million and $135 million, respectively, were included in other current liabilities, and no material balance was included in other long-term liabilities in the Consolidated Balance Sheets. Future collateral requirements for cash, first priority liens and letters of credit may increase or decrease based on the extent of the Company's involvement in hedging and optimization contracts, movements in commodity prices and also based on Calpine's credit ratings and general perception of creditworthiness in the market. 63

12. Income Taxes Income Tax Expense The jurisdictional components of income from continuing operations before income tax expense attributable to Calpine are as follows (in millions): Year Ended December 31, 2025 2024 2023 The U.S. $ 2,444 $ 2,116 $ 2,125 Foreign 7 6 12 Total $ 2,451 $ 2,122 $ 2,137 The components of income tax expense (benefit) from continuing operations consist of the following (in millions): Year Ended December 31, 2025 2024 2023 Current: Federal $ — $ — $ — State 141 93 43 Foreign 3 — 5 Total current 144 93 48 Deferred: Federal 485 372 393 State (151) (8) 92 Foreign — 3 9 Total deferred 334 367 494 Total income tax expense $ 478 $ 460 $ 542 Income Taxes Paid Income taxes paid (net of refunds) during the year are comprised of the following components (in millions): Year Ended December 31, 2025 US state and local California 56 Delaware 7 Illinois 7 Pennsylvania 6 Other 31 107 Foreign Canada 1 1 Total income taxes paid (net of refunds) $ 108 For the year ended December 31, 2025, effective income tax rate did not bear a customary relationship to statutory income tax rate, primarily as a result of the effect of valuation allowances, state income taxes, and various permanent book and 64

tax differences. A reconciliation of the federal statutory rate of 21.0% to the effective rate from continuing operations is as follows: 2025 Federal statutory tax rate $ 515 21.0 % State income tax expense, net of federal effect(1) (9) (0.4) Foreign tax effects 1 — Effect of changes in tax laws or rates enacted in current period — — Effect of cross-border tax laws — — Tax Credits ITC basis reduction (5) (0.2) ITC (gain) loss on sale 4 0.2 Change in valuation allowance (24) (0.9) Nontaxable or nondeductible items Percentage depletion (4) (0.2) Changes in unrecognized tax benefits Other adjustments — — Effective income tax rate $ 478 19.5 % Year Ended December 31, ___________ (1) 2025 State taxes in Pennsylvania and Delaware made up the majority (greater than 50%) of the tax effect in this category. For the years ended December 31, 2024 and 2023, effective income tax rates did not bear a customary relationship to statutory income tax rates, primarily as a result of the effect of valuation allowances, state income taxes, and various permanent book and tax differences. A reconciliation of the federal statutory rate of 21.0% to the effective rate from continuing operations is as follows: 2024 2023 Federal statutory tax rate 21.0 % 21.0 % State tax expense, net of federal benefit 3.2 5.1 Valuation allowances against future tax benefits (1.8) 0.6 Federal return to provision (0.1) (0.6) Distributions from foreign affiliates and foreign taxes — 0.2 Tax credits 1.6 (1.3) Stock-based compensation — 0.2 Depletion in excess of the basis (0.2) (0.1) ITC basis adjustment (2.1) — Other differences 0.1 0.3 Effective income tax rate 21.7 % 25.4 % Year Ended December 31, 65

Deferred Tax Assets and Liabilities The components of deferred income taxes are as follows (in millions): December 31, 2025 2024 Deferred tax assets: NOL and credit carryforwards $ 465 $ 796 Impairments and development cost 68 55 Limited interest expense carryforward 33 32 Other differences 191 174 Deferred tax assets before valuation allowance 757 1,057 Valuation allowance (42) (91) Total deferred tax assets 715 966 Deferred tax liabilities: Property, plant and equipment (1,530) (1,555) Taxes related to derivative mark-to-market and risk management hedging activities (158) (163) Total deferred tax liabilities (1,688) (1,718) Net deferred tax asset (liability) $ (973) $ (752) NOL Carryforwards — As of December 31, 2025, our NOL carryforwards consisted primarily of federal NOL carryforwards of approximately $1.6 billion gross, of which the majority expire between 2028 and 2037 and NOL carryforwards in 17 states and the District of Columbia totaling approximately $1.1 billion, majority of which expire between 2026 and 2045. A portion of state NOLs is offset with a valuation allowance to address potential limitations on NOL usage prior to expiration. Specifically, certain state NOL carryforwards are subject to limitations on their annual usage in accordance with current state regulations and statutes. Additionally, as a result of the ownership change associated with the merger of Volt Merger Sub, Inc. with and into Calpine, pursuant to the terms of the Volt Merger Agreement on March 8, 2018 (the “Volt Merger”), the Company's ability to utilize certain NOL carryforwards are subject to limitations under Section 382 of the Internal Revenue Code of 1986, as amended Income Tax Audits — The Company remains subject to periodic audits and reviews by taxing authorities; however, these audits are not expected to have a material effect on the tax provision. Any NOLs claimed in future years to reduce taxable income could be subject to IRS examination regardless of when the NOLs were generated. Any adjustment of state or federal returns could result in a reduction of deferred tax assets rather than a cash payment of income taxes in tax jurisdictions where the Company has NOLs. The Company is currently under various state income tax audits for various periods. Valuation Allowance — U.S. GAAP requires that we consider all available evidence, both positive and negative, and future earnings to determine whether, based on the weight of that evidence, a valuation allowance is needed to offset the value of deferred tax assets. As of December 31, 2025, we do not have a valuation allowance on our federal NOLs. We have a valuation allowance on portions of our state and foreign NOLs to address potential limitations on NOL usage prior to expiration. Following the change in calculation of the 163(j) interest deduction limitation under the newly enacted OBBBA discussed below, we released valuation allowance established in prior periods on our 163(j) carryforward where we believe it is more likely than not that we will realize the value of those carryforward. During the years ended December 31, 2025, 2024 and 2023, we recorded a change of worldwide valuation allowance in the amount of $(49) million, $(61) million and $19 million, respectively. Changes are primarily related to the release of the valuation allowance on the interest limitation carryforward from prior periods as well as certain state NOL carryforward. Future realization of the tax benefit of an existing deductible temporary difference or carryforward ultimately depends on the existence of sufficient taxable income of the appropriate character within the carryback or carryforward periods available under the tax law. For purposes of this evaluation, we consider both the existence of future taxable earnings and the future reversal of existing temporary differences. To the extent that future expected sources of earnings materially change, this could result in the reduction or increase in our valuation allowance in future periods. The conditional FERC approval of the merger between Constellation Energy and Calpine Corporation requires the divesting of multiple power plants within PJM (“PJM Facilities”). To ensure efficient and complete divestiture of the PJM Facilities, series of internal transaction steps were completed as of December 31, 2025. This includes consolidating ownership of PJM Facilities under Calpine Corporation through tax-related entity conversions, as well as intercompany installment sales of PJM Facilities to a newly formed holding company. These internal restructurings resulted in a $56 million current tax 66

expense, a $133 million deferred tax benefit and a $15 million reduction to existing valuation allowance. All of which reduced effective tax rate for the year ended December 31, 2025. The Inflation Reduction Act of 2022 — The Inflation Reduction Act of 2022 (the “IRA”) was signed into law on August 16, 2022. The IRA applies to tax years beginning after December 31, 2022, and introduces a 15% corporate alternative minimum tax (“CAMT”) for corporations whose average annual adjusted financial statement income (“AFSI”) for any consecutive three-tax year period preceding the tax year exceeds $1 billion. The IRS has issued multiple interim guidance documents and proposed regulations since CAMT was introduced in 2022. On September 30, 2025, the IRS released Notice 2025-46 and 2025-49, providing additional interim guidance on the corporate alternative minimum tax (“CAMT”). These notices indicate that the IRS intends to partially withdraw the previously proposed regulations and issue revised proposed regulations. Notice 2025-46 offers guidance consistent with the revised proposed regulations' purpose, focusing on domestic corporate transactions, troubled companies, tax consolidated groups, and financial statement net operating losses (“FSNOLs”). Notice 2025-49 outlines rules for reliance, applicable dates, and guidance on specific adjusted financial statement income (“AFSI”) adjustments. Provisions that may impact Calpine include, but are not limited to, goodwill amortization under Section 197 and fair value adjustments for FSI purposes. We are currently evaluating how this guidance affects our CAMT and, accordingly, our future tax expense, cash taxes, and effective tax rate. The IRA includes provisions providing tax credit incentives for emerging technologies. The details of the implementation of these incentives are subject to ongoing regulations both proposed and finalized, by the Department of the Treasury. Calpine is monitoring these developments and will continue to evaluate opportunities to use these incentives in the future. Some of the notable Regulations issued by the IRS included the Final regulation on IRC 48 for Investment Tax Credit issued on December 12, 2024, as well as the Final regulation on IRC 45Y and 48E for tech-neutral ITC issued on January 15, 2025. Calpine continues to assess the impact of these final regulations but does not expect them to have a material impact on our operations. Calpine accounts for the receipt of federal investment tax credits in the period an eligible project achieves commercial operation. Upon receipt of credit, the Company has elected to recognize the value of the credit either as a reduction in the cost basis of the underlying project assets, or as a deferred credit, with a corresponding recognition of a deferred tax asset in the same period. During the tax year ending December 31, 2025, the Company has received approximately $52 million of investment tax credits. Calpine sold $57 million investment tax credits for approximately $53 million, recognizing the discount loss on sale through Income Tax Expense and including within the annual effective tax rate calculation. The loss did not have a material impact to our effective tax rate. All proceeds are reported in the Operating section of the consolidated statement of cash flows. H.R. 1, the One Big Beautiful Bill Act (“OBBBA”) of 2025, also referred to as the budget reconciliation bill, was signed into law on July 4, 2025. We continue to evaluate all components of the Act; however, the OBBBA generally makes the tax provisions of the Tax Cuts and Jobs Act (“TCJA”) permanent. Items impacting Calpine include but are not limited to the permanent extension of a full bonus depreciation deduction for assets acquired and placed in service on or after January 19, 2025, modification of the calculation for determining deductibility of business interest expense under IRC 163j to include depreciation, amortization and depletion to the adjusted taxable income calculation and reinstatement of the full deductibility of research and development costs. There were also numerous changes to energy tax credits enacted under the IRA. We are analyzing these changes, but do not expect them to have a material impact on our operations or 2025 Consolidated Financial Statements. Unrecognized Tax Benefits As of December 31, 2025 and 2024, there were unrecognized tax benefits of $30 million and $25 million, respectively; if recognized, $30 million of unrecognized tax benefits could affect the annual effective tax rate. The Company had accrued interest and penalties of $8 million and $6 million for uncertain tax positions as of December 31, 2025 and 2024, respectively. We recognize interest and penalties related to unrecognized tax benefits in income tax expense (benefit) on the Consolidated Statements of Operations and recorded $1 million, $1 million, and $2 million for the years ended December 31, 2025, 2024 and 2023, respectively. The Company monitors and evaluates any changes in fact that could affect and/or modify the existing unrecognized tax benefit accrual as well as any new tax positions that require unrecognized tax benefits to be recorded. As of December 31, 2025, the Company performed a review of the prior year's uncertain tax position and for new positions. This review did not result in a material change to our recorded unrecognized current tax benefit. A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows (in millions): 67

Year Ended December 31, 2025 2024 2023 Balance, beginning of period $ (25) $ (26) $ (30) Increases related to prior year tax positions (5) — — Decreases related to prior year tax positions — 1 4 Balance, end of period $ (30) $ (25) $ (26) 13. Defined Contribution and Defined Benefit Plans There are two defined contribution savings plans that are intended to be tax-exempt under Sections 401(a) and 501(a) of the Internal Revenue Code (“IRC”). The non-union plan generally covers employees who are not covered by a collective bargaining agreement, and the union plan covers employees who are covered by a collective bargaining agreement. In 2018, an enhanced feature was added to the defined contribution plan for non-union employees consisting of a non-elective contribution for certain eligible employees who are active employees as of December 31. Expenses were recorded for these plans of approximately $29 million, $28 million and $25 million for the years ended December 31, 2025, 2024 and 2023, respectively. Employer matching contributions are 100% of the first 5% of compensation a participant defers for the non-union plan. The employee deferral limit is 75% of eligible compensation under both plans. The Company also maintains defined benefit pension plans whereby retirement benefits are primarily a function of age attained, years of participation, years of service, vesting and level of compensation. Only approximately 3% of employees are eligible to participate in a defined benefit pension plan. As of December 31, 2025 and 2024, there were approximately $30 million and $29 million, respectively, in plan assets and approximately $30 million and $29 million, respectively, in pension liabilities. The net pension liability recorded on the Consolidated Balance Sheets as of December 31, 2025 and 2024, was approximately $0.5 million and $0.1 million, respectively. For the years ended December 31, 2025, 2024 and 2023, net periodic benefit costs of approximately $0.4 million, $0.4 million and $1 million, respectively. Net periodic benefit cost is included in operating and maintenance expense on the Consolidated Statements of Operations. For the years ended December 31, 2025, 2024 and 2023, the total amount recognized in AOCI for actuarial (gains) losses related to pension obligation was approximately $(3) million, $(2) million and $1 million, respectively. Estimates of pension obligation and related costs use discount rates, an increase of compensation rates, and rates of return on assets that are reasonable. Due to the relatively small size of the pension liability (which is not considered material), significant changes in these assumptions would not have a material effect on pension liability. During the years ended December 31, 2025, 2024 and 2023, the Company made contributions of approximately $0.3 million, $0.1 million and $1 million, respectively, and estimated contributions to the pension plan are expected to be approximately $0.3 million in 2026. Estimated future benefit payments to participants in each of the next five years are expected to be approximately $2 million to $2.3 million each year. 14. Capital Structure Common Stock On June 2, 2025, the Company entered into the Sixth Amended and Restated Certificate of Incorporation of Calpine and the Company's Board of Directors authorized the issuance of a new class of common stock, designated as Class C common shares, with a par value of $0.001 per share. As of December 31, 2025, the Company's authorized common stock consists of 1,800,000 shares of Calpine Corporation common stock, consisting of 1,400,000 Class A common shares, 200,000 Class B common shares and 200,000 Class C common shares, all of which have a par value of $0.001 per share. As of December 31, 2024, the Company's authorized common stock consisted of 1,400,000 shares of Calpine Corporation common stock, consisting of 1,200,000 Class A common shares and 200,000 Class B common shares, all of which have a par value of $0.001 per share. During the year ended December 31, 2025, an immaterial amount of Class B common shares were issued by the Company and were forfeited by an employee, resulting in total issued and outstanding Class B shares of 48,654 and 48,651 as of December 31, 2025 and December 31, 2024, respectively. There were no changes to the number of issued and outstanding Class A common shares during the year ended December 31, 2025 which totaled 952,153 at December 31, 2025 and December 31, 2024. There were no issued and outstanding Class C common shares at December 31, 2025 and December 31, 2024. The Class B common shares outstanding in connection with the Sixth Amended and Restated Certificate of Incorporation of Calpine do not have voting rights, and all voting rights continue to be held by CPN Management, L.P. through 68

its ownership of all Class A common shares. All rights and obligations of each class of shares are specified under the Stockholders Agreement and the Sixth Amended and Restated Certificate of Incorporation. 15. Stock-Based Compensation Equity-based compensation agreement – Class B common shares of Calpine Corporation Calpine Corporation issued 47,847 of Class B common shares on June 8, 2022 which were transferred by CPN Management, LP to certain members of Calpine management in exchange for and conversion of all outstanding vested and unvested Class B partnership interests held by such individuals in CPN Management, LP under the Third Amended and Restated Limited Partnership Agreement of CPN Management, LP. During the year ended December 31, 2025, Calpine Corporation granted an immaterial amount of Class B common shares and an immaterial number of shares were forfeited by an employee upon leaving the Company, resulting in a total of 48,654 Class B common shares outstanding at December 31, 2025. During March 2024, Calpine Corporation granted an additional 804 shares of Class B common stock to members of Calpine management. All of these shares granted will vest three years from the grant date. As of December 31, 2025, the Class B common shares issued and outstanding represent approximately 4.9% of total outstanding shares of Calpine stock. All issued shares retain rights to the dividends of Calpine based on the ownership percentage pursuant to the terms in the Stockholders Agreement and the Sixth Amended and Restated Certificate of Incorporation of Calpine. The Class B common shares qualify as an equity-classified award issued to members of Calpine management and resulted in approximately $2 million, $2 million and $18 million of compensation expense recognized in the Consolidated Financial Statements for the years ended December 31, 2025, 2024 and 2023, respectively. Stock-based compensation expense is recognized over the period in which the related employee services are provided. Management used the results of a recently consummated continuation fund transaction among the controlling owners and their limited partner investors in June 2022 as the basis to estimate the fair value of Class B common shares on the grant date for measuring compensation expense. The fair value calculation is based on a discounted cash flow model incorporating key assumptions related to expected future distributions, a terminal value based on the consummated third-party transaction, and a discount rate with an appropriate risk adjustment to address market variability and the subjectivity associated with the key assumptions. For the years ended December 31, 2025, 2024 and 2023 cash payments to the Class B common shareholders were made related to dividends declared and paid by the Company of approximately nil, $1.9 billion and $1.7 billion, respectively. Other Management Compensation In addition to the Class B common shares held by management accounted for as stock-based compensation at December 31, 2025 discussed above, certain members of management hold profit interest rights issued by CPN Management, L.P. These profit interest rights were converted to a B4 profit interest grant in 2025. The second profit interest tranche was granted to members of management in fiscal year 2023. This grant has a service period requirement for management as well as additional financial performance thresholds, both of which must be met for the profit interest grant to vest. Both profit interest grants will be accounted for as stock-based compensation for management, and while the obligation will be held by CPN Management, L.P., which holds a 100% ownership interest in Calpine, any costs will be recognized by Calpine Corporation at the time vesting is deemed probable. No amounts have been recognized during the years ended December 31, 2025, 2024 and 2023. 16. Commitments and Contingencies Long-Term Parts Supply and Construction Agreements As of December 31, 2025, the total estimated commitments related to long-term parts supply and construction agreements associated with the development and construction of development projects, including battery storage and data center facilities, total approximately $138 million, of which no payments have been made to date. These commitments are payable over the remaining terms of the respective agreements over the next 4 years. The future commitment estimates for these agreements are based on the lesser of the statement payment terms in the contract at the time of execution or the termination payment that would be required if the Company terminated the agreement. Long-Term Service Agreements As of December 31, 2025, the total estimated commitments for Long-Term Service Agreements (“LTSAs”) associated with turbine maintenance services at certain facilities that are in operation were approximately $405 million. These commitments are payable over the remaining terms of the respective agreements, which range from 1 to 19 years. LTSA future commitment estimates are based on the stated payment terms in the contracts at the time of execution. Certain of these 69

agreements have terms that allow for cancellation of the contracts for a fee. If such contracts are cancelled, the estimated commitments remaining for LTSAs will be reduced. Production Royalties The Company is obligated under numerous geothermal contracts and right-of-way, easement and surface agreements to pay production royalties from the Geysers Assets. The geothermal contracts generally provide for royalties based on production revenue with reductions for property taxes paid. The right-of-way, easement, and surface agreements are based on flat rates or adjusted based on consumer price index changes and are not material. Under the terms of most geothermal contracts, the royalties accrue as a percentage of power revenues. Certain properties also have net profits and overriding royalty interests in addition to the land base contract royalties. Some contracts contain clauses providing for minimum payments if production temporarily ceases or if production falls below a specified level. Production royalties for geothermal power plants for the years ended December 31, 2025, 2024 and 2023 were $23 million, $25 million and $26 million, respectively. Gregory Power Holdings, LLC Agreement On December 29, 2023, the Company entered into an investment agreement with Gregory Power Holdings, LLC through the execution of an amended and restated Limited Liability Company Agreement for Gregory Power Holdings, LLC. Gregory Power Holdings, LLC, through its wholly-owned subsidiary, owns and operates a 385 MW combined cycle generation facility located in Texas. Under the terms of the LLC Agreement, the Company obtained a 53.52% non-economic (for certain voting rights) and a 43.25% economic interest in Gregory Power Holdings, LLC, with an obligation to fund future cash contributions to Gregory Power Holdings, LLC until such a time as the Company's economic investment interest reached 45% ownership in the entity. After such time, future contributions would be made by the Company and its partner in accordance with the respective ownership interests and the terms of the LLC Agreement. See Note 7, Variable Interest Entities and Unconsolidated Investments and Note 19, Subsequent Events, for further discussion. Commodity Purchases The Company enters into commodity purchase contracts of various terms with third parties to supply fuel to natural gas-fired power plants and power to retail customers. The majority of purchases are made in the spot market or under index- priced contracts. These contracts are accounted for as executory contracts and therefore not recognized as liabilities on our Consolidated Balance Sheets. Contractual Obligations — Our contractual obligations as of December 31, 2025, are as follows (in millions): Total Less than 1 Year 1-3 Years 3-5 Years More than 5 Years Purchase obligations: Commodity purchase obligations(1) $ 1,960 $ 478 $ 564 $ 310 $ 608 LTSA(2) 405 42 79 62 222 Water agreements(3) 418 24 33 32 329 Other purchase obligations(4) 231 63 55 35 78 Total purchase obligations 3,014 607 731 439 1,237 Debt 12,482 279 3,253 3,914 5,036 Other contractual obligations: Interest payments on debt(5) 2,647 612 1,130 716 189 Liability for uncertain tax positions(6) 23 — — — 23 Interest rate hedging instruments(5) 11 4 5 2 — Total other contractual obligations 2,681 616 1,135 718 212 Total contractual obligations $ 18,177 $ 1,502 $ 5,119 $ 5,071 $ 6,485 ___________ (1) The amounts presented here include contractually obligated amounts for the purchase, transportation or storage of commodities accounted for as executory contracts and, therefore, not recognized on our Consolidated Balance Sheets. (2) The amounts presented here are based on estimated payments in accordance with the stated payment terms in the contracts at the time of execution. 70

(3) The amounts presented here are based on contractually obligated amounts over the life of the contracts, including assumed extensions. (4) The amounts presented here include costs to complete construction projects, parts supply agreements, maintenance agreements, information technology agreements and other purchase obligations. (5) Amounts are projected based on market interest rates as of December 31, 2025. (6) The amounts related to the liability for uncertain tax positions are included within the category “More than five years” due to uncertainty relating to the timing of resolution. Guarantees and Indemnifications As part of normal business operations, the Company enters into various agreements providing, or otherwise arranging, financial or performance assurance to third parties on behalf of its subsidiaries in the ordinary course of such subsidiaries’ respective business. Such arrangements include guarantees, standby letters of credit, and surety bonds for power and natural gas purchase and sale arrangements, retail contracts, contracts associated with the development, construction, operation and maintenance of the fleet of power plants and battery storage facilities, and the Accounts Receivable Sales Program. The Accounts Receivable Sales Program is a receivables purchase agreement between Calpine Energy Solutions, LLC and Calpine Receivables, LLC, and the purchase and sale agreement between Calpine Receivables, LLC, and an unaffiliated financial institution, both which allows for the revolving sale of up to $500 million in certain trade accounts receivables to third parties. These arrangements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes. As of December 31, 2025, standbys and the guarantee under the Accounts Receivable Sales Program and their respective expiration dates were as follows (in millions): Guarantee Commitments 2026 2027 2028 2029 2030 Thereafter Total Guarantee of subsidiary obligations(1) $ 6 $ 6 $ 5 $ — $ — $ 12 $ 29 Standby letters of credit(2)(3)(4) 2,395 98 — — — — 2,493 Surety bonds(4) 181 3 — — — 346 530 Guarantee under Accounts Receivable Sales Program(5) 485 — — — — — 485 Total $ 3,067 $ 107 $ 5 $ — $ — $ 358 $ 3,537 ____________ (1) Represents Calpine Corporation guarantees of certain power plant leases and related interest. All guaranteed finance leases are recorded on our Consolidated Balance Sheets. (2) The standby letters of credit disclosed above represent those disclosed in Note 8, Debt. (3) Letters of credit are renewed annually and as such all amounts are reflected in the year of letter of credit expiration. The related commercial obligations extend for multiple years, therefore, renewal of the letter of credit will likely follow the term of the associated commercial obligation. (4) These are contingent off-balance sheet obligations, and the majority of surety bonds do not have expiration or cancellation dates. As of December 31, 2025, no cash collateral is outstanding related to these bonds. (5) Calpine has guaranteed the performance of Calpine Energy Solutions, LLC under the Accounts Receivable Sales Program. The Accounts Receivable Sales Program was renewed on November 14, 2025, and expires on November 13, 2026. Issuance of letters of credit and various forms of surety bonds to third parties are routinely arranged in support of subsidiaries’ contractual arrangements of the types described above and may guarantee the operating performance of some partially-owned subsidiaries up to the Company’s ownership percentage. The letters of credit issued under various credit facilities support risk management and other operational and construction activities. In the event a subsidiary were to fail to perform its obligations under a contract supported by such a letter of credit or surety bond, and the issuing bank or surety were to make payment to the third party, the Company would be responsible for reimbursing the issuing bank or surety within an agreed timeframe, typically a period of one to five days. To the extent liabilities are incurred because of activities covered by letters of credit or surety bonds, such liabilities are included on the Consolidated Balance Sheets. 71

Commercial Agreements — In connection with the purchase and sale of power, natural gas, environmental products and fuel oil to and from third parties with respect to the operation of power plants and retail subsidiaries, there may be a requirement to guarantee a portion of the obligations of certain subsidiaries. The Company may also be required to guarantee performance obligations associated with marketing, hedging, optimization and trading activities to manage its exposure to changes in prices for energy commodities. These guarantees may include future payment obligations and effectively guarantee future performance under certain agreements. Asset Acquisition and Disposition Agreements — In connection with purchase and sale agreements, the Company has frequently provided for indemnification to the counterparty for liabilities incurred as a result of a breach of a representation, warranty, or covenant by the indemnifying party. These indemnification obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or impossible to quantify at the time of the consummation of a particular transaction. The potential exposure under guarantee and indemnification obligations can range from a specified amount to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. The total maximum exposure under our guarantee and indemnification obligations is not estimable due to uncertainty as to whether claims will be made or how any potential claim will be resolved. As of December 31, 2025, there are no material outstanding claims related to guarantee and indemnification obligations, and it is not anticipated that there will be a requirement to make any material payments under these guarantee and indemnification obligations. Litigation The Company is a party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business. At the present time, it is not expected that the outcome of any of these proceedings, individually or in aggregate, will have a material adverse effect on the financial condition, results of operations, or cash flows. On a quarterly basis, litigation activities are reviewed to determine if an unfavorable outcome is considered “remote,” “reasonably possible,” or “probable” as defined by U.S. GAAP. Where an unfavorable outcome is probable and is reasonably estimable, potential litigation losses are accrued. The liability ultimately incurred with respect to such litigation matters, in the event of a negative outcome, may be in excess of amounts currently accrued, if any; however, it is not expected that the reasonably possible outcome of these litigation matters would, individually or in the aggregate, have a material adverse effect on the Company’s financial condition, results of operations or cash flows. Where it is determined an unfavorable outcome is not probable or reasonably estimable, potential litigation losses are not accrued. The ultimate outcome of these litigation matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated. As a result, no assurance is given that such litigation matters would, individually or in the aggregate, not have a material adverse effect on the Company’s financial condition, results of operations, or cash flows. Winter Storm Uri Regulatory Investigations and Other Litigation Matters — In the wake of the extreme weather event, Winter Storm Uri, a significant number of personal injuries, wrongful death and insurance subrogation lawsuits related to Winter Storm Uri were filed against ERCOT and participants in the ERCOT market, some of which name Calpine as a defendant. Calpine is vigorously defending itself against the claims alleged in the lawsuits. The lawsuits are now the subject of a Multi-District Litigation process for pretrial proceedings in the District Court in Harris County, Texas. The District Court ruled on initial motions to dismiss, granting, and denying various claims against Calpine and its subsidiaries in select “Bellwether” cases. Petitions for writs of mandamus appealing the District Court’s denial of the motions to dismiss the remaining claims were filed. The First District Court of Appeals reversed the District Court and dismissed the Bellwether cases against power generators, including Calpine. A motion for rehearing of the First Court’s decision was denied. Petitions for writs of mandamus are now currently pending before the Supreme Court of Texas. The full impact of this litigation on our business, financial condition, results of operations, or cash flows cannot be estimated at this time. Accordingly, we will continue to monitor this situation through the conclusion of the remaining matters. Environmental Matters The Company is subject to complex and stringent environmental laws and regulations related to the operation of power plants. On occasion, environmental fees, penalties and fines associated with the operation of our power plants may be incurred. At the present time, there are no environmental violations or other matters that would have a material effect on the financial condition, results of operations or cash flows or that would significantly change operations. 72

17. Related Party Transactions The Company has entered into various agreements with related parties associated with business operation. A description of these related party transactions is provided below. Accounts Receivable Sales Program On December 1, 2016, in conjunction with the acquisition of Calpine Solutions, the Company entered into the Accounts Receivable Sales Program which, as amended, allows the sale of, at a discount, up to $500 million in certain trade accounts receivable, arising from the sale of power and natural gas, from Calpine Solutions to Calpine Receivables which in turn sells 100% of the receivables to an unaffiliated financial institution, subject to certain contractual limitations. The Accounts Receivable Sales Program was renewed on November 14, 2025, and expires on November 13, 2026. Calpine Solutions services the receivables sold in exchange for a servicing fee, which was $48 million, $19 million and $15 million for the years ended December 31, 2025, 2024 and 2023, respectively. The Company is not the primary beneficiary of Calpine Receivables and, accordingly, does not consolidate this entity in its Consolidated Financial Statements. See Note 7, Variable Interest Entities and Unconsolidated Investments, for further discussion of unconsolidated VIEs. Any portion of the purchase price for the sold receivables which is not paid in cash is recorded as a note receivable. The note receivable is recorded at fair value. It does not materially differ from the carrying value of the trade accounts receivable held prior to the sale due to the short-term nature of the receivables and the high credit quality of the retail customers involved. Receivables sold under the Accounts Receivable Sales Program are accounted for as sales and excluded from accounts receivable on the Consolidated Balance Sheets and reflected as cash provided by operating activities on the Consolidated Statements of Cash Flows. Calpine has guaranteed the performance of Calpine Solutions under the Accounts Receivable Sales Program. See Note 16, Commitments and Contingencies, for a further description of guarantees. Under the Accounts Receivable Sales Program, as of December 31, 2025 and 2024, there were $485 million and $391 million, respectively, in trade accounts receivable outstanding that were sold under the Accounts Receivable Sales Program and $81 million and $75 million, respectively, in notes receivable which were recorded on the Consolidated Balance Sheets as of December 31, 2025 and 2024, respectively. An aggregate of approximately $4,162 million, $3,522 million and $3,537 million in trade accounts receivable was sold and proceeds of approximately $4,133 million, $3,511 million and $3,552 million were recorded during the years ended December 31, 2025, 2024 and 2023, respectively. Interest charges and fees incurred on the sale of trade accounts receivable were $23 million, $22 million and $23 million for the years ended December 31, 2025, 2024 and 2023, respectively. Lyondell — There is a ground lease agreement with Houston Refining, LP (“Houston Refining”), a subsidiary of LyondellBasell Industries N.V. (“Lyondell”), for the Channel Energy Center site from which power, capacity, and steam is sold to Houston Refining under a PPA. The Company also purchases refinery gas and raw water from Houston Refining under a facilities service agreement. One of the entities that has a material ownership interest in Calpine also has an ownership interest in Lyondell, whereby it may significantly influence the management and operating policies of Lyondell. The terms of the PPA with Lyondell were negotiated prior to the Merger closing. For the years ended December 31, 2025, 2024 and 2023, $31 million, $65 million and $67 million in operating revenues was recorded, respectively, and $5 million, $14 million and $19 million in operating expenses was recorded, respectively, associated with Lyondell. As of December 31, 2025 and 2024, the related party receivable associated with the Lyondell contract was $1 million and $8 million, respectively. As of December 31, 2025 and 2024, the related party payable associated with the Lyondell contract was immaterial. In the fourth quarter of 2025, Lyondell continued its previously announced shutdown activities associated with its Houston refinery. With this change, we expect Lyondell to take less steam and electricity under the Energy Sales Agreement (“ESA”). Based on preliminary evaluation, the change in cash flows associated with lower volumes of steam and electricity sold to Lyondell do not have a material effect on the future expected cash flows of Channel and thus the fair value of the facility is not less than Channel’s current carrying value. Accordingly, we have not recognized any impairment loss associated with this event during the year ended December 31, 2025. Pasadena Performance Products — In October 2019, one of Calpine's subsidiaries entered into a steam contract with Pasadena Performance Products, LLC, a subsidiary of Next Wave Energy Partners, LP (“Next Wave”), to sell steam over an initial term of ten years commencing with the commercial operations of a chemical facility. One of the entities which has a material ownership interest in Calpine also has an ownership interest in Next Wave, whereby it may significantly influence the management and operating policies of Next Wave. The chemical facility met commercial operations on December 28, 2023, resulting in the commencement of the steam contract. During the year ended December 31, 2025 we recorded operating revenues of $28 million for the sale of steam. During the year ended December 31, 2024, we recorded operating revenues of $24 million for the sale of steam and $5 million related to the successful completion of the construction of the interconnection from the chemical facility to our power plant. As of December 31, 2025 and 2024, the related party receivable was $2 million 73

and nil. As of December 31, 2025 and 2024, the related party payables associated with the Pasadena Performance Products contracts were immaterial. Gregory Power Holdings, LLC — During the year ended December 31, 2025, the Company made cash contributions of $84 million to Gregory Power Holdings, LLC. The revenues recognized for providing management services to Gregory Power Holdings, LLC for the year ended December 31, 2025 and 2024, were immaterial. There were no revenues recognized for providing management services to Gregory Power Holdings, LLC during the years ended December 31, 2023. As of December 31, 2025 and 2024, the related party receivables and payables associated with Gregory Power Holdings, LLC were immaterial. Other — Other related party contracts for the sale or purchase of power, natural gas, capacity, steam and RECs were identified which are entered into in the ordinary course of business. Most of these contracts relate to the sale or purchase of commodities and capacity for varying tenors. For the years ended December 31, 2025, 2024 and 2023, $3 million, $6 million and $3 million in operating revenues were recorded, respectively, and $18 million, $24 million and $24 million in operating expenses were recorded, respectively, associated with these related party transactions. For the years ended December 31, 2025, 2024 and 2023, the Company purchased $20 million, $14 million and $7 million, respectively, of RECs from related parties. The Company has also entered into a long-term land lease agreement with a related party. As of December 31, 2025 and 2024, the related party receivable and payable associated with these transactions were immaterial. 18. Segment and Significant Customer Information Segment reporting is based on the management approach, using the method that management organizes the Company’s reportable segments for which separate financial information is made available to, and evaluated regularly by, the Company’s chief operating decision maker (“CODM”) in allocating resources and in assessing performance. The Company’s CODM is its Chief Executive Officer. The Company's business is assessed on a regional basis because differing characteristics of each region impact financial performance, particularly with respect to competition, regulation and other factors affecting supply and demand. As of December 31, 2025, geographic reportable segments for the Wholesale business are West (including geothermal), Texas, East (including Canada) and the Retail business. The Company continues to evaluate the optimal manner in which performance is assessed, including segments, and future changes may result in changes to the geographic segments composition. Corporate (including consolidation and elimination entries) represents the remaining non-segment operations, consisting of general corporate expenses, interest, taxes and other expenses related to support functions that provide shared services to operating segments as well as the elimination of intercompany activity. The Company’s CODM evaluates financial performance of each segment using a variety of measures including Commodity Margin, Gross Margin, Net Income (Loss), Adjusted Net Income, Adjusted Free Cash Flow, Adjusted Unlevered Free Cash Flow and the allocation of capital. For the purposes of the disclosure, we have included the measures most closely aligned with GAAP. The tables below show financial data for the segments which is evaluated by the CODM for the periods indicated (in millions): 74

Year Ended December 31, 2025 Wholesale West Texas East Retail Consolidation and Elimination Total Operating revenues: Commodity revenue $ 3,765 $ 3,888 $ 2,871 $ 5,382 $ (2,372) $ 13,534 Mark-to-market gain (loss) 290 (199) 13 656 (59) 701 Other revenue 23 86 27 — (71) 65 Operating revenues $ 4,078 $ 3,775 $ 2,911 $ 6,038 $ (2,502) $ 14,300 Operating expenses: Fuel and purchased energy expense Commodity expense 2,045 2,408 1,920 4,489 (2,372) 8,490 Mark-to-market (gain) loss (16) 133 54 57 (59) 169 Fuel and purchased energy expense 2,029 2,541 1,974 4,546 (2,431) 8,659 Operating and maintenance expense associated with margin generation activities 518 396 333 220 — 1,467 Depreciation and amortization expense associated with margin generation activities 325 221 186 37 — 769 Gross margin $ 1,206 $ 617 $ 418 $ 1,235 $ (71) $ 3,405 Operating and maintenance expense associated with general corporate cost 14 17 13 27 (70) 1 Depreciation and amortization expense associated with general corporate cost — — — — 29 29 General and other administrative expense 35 70 44 16 — 165 Other operating expenses 60 106 43 6 — 215 Loss (gain) on sale of assets, net 1 (129) 1 — — (127) Loss (income) from unconsolidated subsidiaries — 15 — (24) — (9) Income (loss) from operations 1,096 538 317 1,210 (30) 3,131 Interest expense (income) 187 243 179 3 (5) 607 Loss on extinguishment of debt 2 3 2 — — 7 Other expense, net (1) (2) (1) 66 4 66 Income (loss) before income taxes 908 294 137 1,141 (29) 2,451 Income tax expense 109 223 144 2 — 478 Net income (loss) $ 799 $ 71 $ (7) $ 1,139 $ (29) $ 1,973 75

Year Ended December 31, 2024 Wholesale West Texas East Retail Consolidation and Elimination Total Operating revenues: Commodity revenue $ 3,901 $ 3,351 $ 2,675 $ 4,645 $ (2,325) $ 12,247 Mark-to-market gain (loss) 307 90 (207) (103) 31 118 Other revenue 32 49 56 — (68) 69 Operating revenues $ 4,240 $ 3,490 $ 2,524 $ 4,542 $ (2,362) $ 12,434 Operating expenses: Fuel and purchased energy expense Commodity expense 1,914 2,146 1,490 3,925 (2,326) 7,149 Mark-to-market loss (gain) 176 (13) (197) (16) 31 (19) Fuel and purchased energy expense 2,090 2,133 1,293 3,909 (2,295) 7,130 Operating and maintenance expense associated with margin generation activities 510 369 381 203 — 1,463 Depreciation and amortization expense associated with margin generation activities 293 204 209 37 — 743 Gross margin $ 1,347 $ 784 $ 641 $ 393 $ (67) $ 3,098 Operating and maintenance expense associated with general corporate cost 14 16 11 22 (68) (5) Depreciation and amortization expense associated with general corporate cost — — — — 27 27 General and other administrative expense 46 65 43 16 — 170 Other operating expenses 59 26 11 4 — 100 Impairment losses — 13 — — — 13 Loss from unconsolidated subsidiaries — — — 4 — 4 Income (loss) from operations 1,228 664 576 347 (26) 2,789 Interest expense (income) 220 208 157 3 (4) 584 Loss on extinguishment of debt 16 23 13 — — 52 Other expense, net 1 (13) (4) 43 4 31 Income (loss) before income taxes 991 446 410 301 (26) 2,122 Income tax expense 137 196 121 6 — 460 Net income (loss) $ 854 $ 250 $ 289 $ 295 $ (26) $ 1,662 76

Year Ended December 31, 2023 Wholesale West Texas East Retail Consolidation and Elimination Total Operating revenues: Commodity revenue $ 3,812 $ 4,071 $ 2,316 $ 4,511 $ (3,203) $ 11,507 Mark-to-market gain (loss) 1,923 37 217 675 (721) 2,131 Other revenue 24 34 51 — (60) 49 Operating revenues $ 5,759 $ 4,142 $ 2,584 $ 5,186 $ (3,984) $ 13,687 Operating expenses: Fuel and purchased energy expense Commodity expense 2,387 3,008 1,256 3,863 (3,203) 7,311 Mark-to-market loss (gain) 551 16 518 884 (721) 1,248 Fuel and purchased energy expense 2,938 3,024 1,774 4,747 (3,924) 8,559 Operating and maintenance expense associated with margin generation activities 495 320 330 194 — 1,339 Depreciation and amortization expense associated with margin generation activities 278 203 191 38 — 710 Gross margin $ 2,048 $ 595 $ 289 $ 207 $ (60) $ 3,079 Operating and maintenance expense associated with general corporate cost 20 20 16 18 (60) 14 Depreciation and amortization expense associated with general corporate cost — — — — 25 25 General and other administrative expense 46 60 44 18 — 168 Other operating expenses 44 23 30 5 — 102 (Income) loss from unconsolidated subsidiaries — — (12) 9 — (3) Income (loss) from operations 1,938 492 211 157 (25) 2,773 Interest expense (income) 209 198 150 3 (5) 555 Loss on extinguishment of debt 6 6 4 — — 16 Other expense, net 9 7 8 37 4 65 Income (loss) before income taxes 1,714 281 49 117 (24) 2,137 Income tax expense 154 211 171 6 — 542 Net income (loss) $ 1,560 $ 70 $ (122) $ 111 $ (24) $ 1,595 Significant Customers For the years ended December 31, 2025, 2024 and 2023, no customer individually accounted for more than 10% of consolidated revenues. 77

19. Subsequent Events The following significant events occurred during 2025 and through the financial statement available for issuance date of February 26, 2026, as further described in the Consolidated Financial Statements: Constellation Merger Closing: On January 7, 2026, Constellation completed the previously announced transactions contemplated by the Agreement and Plan of Merger, dated January 10, 2025 between Constellation and Calpine. Constellation acquired 100% of the outstanding equity of Calpine for a purchase price of approximately $22 billion. The merger consideration consisted of 50 million newly issued Constellation common stock and $4.5 billion in cash. As a result of the transactions contemplated by the Merger Agreement, Calpine became a wholly-owned subsidiary of Constellation and was converted from a corporate formation to a limited liability company, Calpine LLC. Common Stock Exchange: On January 6, 2006, the holders of Class A Common Stock, par value $0.001, of Calpine, Class B Common Stock, par value $0.001, of Calpine and restricted stock units issued by Calpine pursuant to the Calpine Corporation 2024 Equity Incentive Plan (each such unit, a “Calpine Restricted Stock Unit”) became holders of Class A Common Stock, par value $0.001, of New Company (“Class A Common Stock”), Class B Common Stock, par value $0.001, of New Company, and restricted stock units issued by New Company in respect of the Calpine Restricted Stock Units, respectively, in the same quantities and classes of Equity Interests that they held in Calpine immediately prior to the merger. Immediately before the closing of the merger, in accordance with the Plan of Merger Agreement, Subscriber (“CPN Management LP”) held 952,153 shares of Class A Common Stock. Whereas 100,000 of such shares of Class A Common Stock held by Subscriber (the “Exchange Class A Common Stock”) were exchanged for 100,000 shares of Class C Common Stock, par value $0.001 per share, of New Company (“Class C Common Stock”). In addition, immediately prior to the merger effective date, the Company purchased from certain management shareholders a portion of their Calpine stock, thus resulting in Calpine retaining treasury stock prior to merger close. Newly Executed Debt Transactions: Upon merger closing, a sequence of debt transactions were executed culminating in the redemption, payoff and or dissolution of various Calpine debt instruments. A summary of all such activity is provided below: On January 9, 2026, Constellation used proceeds from newly issued Constellation notes, along with cash on hand and short-term debt and repaid $2.510 billion of Calpine's First Lien Term Loans. In December 2025, Constellation commenced a private exchange offer and related consent solicitations ("Exchange Offers") with respect to certain outstanding debt of Calpine. Pursuant to the Exchange Offers, Constellation issued new notes in January 2026, effectively replacing $2.290 billion of Calpine's senior unsecured and secured notes. Upon closing of the Constellation acquisition of Calpine, Constellation has elected to dissolve the $2.5 billion Calpine Corporate Revolving Facility as well as the $1.65 billion Calpine Commodity-Linked Revolving Facility with additional capacity added to the Constellation facilities effective at the merger close date. Gregory Power Plant Sale: On January 14, 2026, pursuant to the DOJ resolution the Company sold its $115 million net investment interest the Gregory Power Plant for $136 million, resulting in a gain of approximately $21 million. Freestone Data Center: In February 2026, we executed a new 380 MW power supply agreement with Dallas-based CyrusOne to serve a new data center adjacent to the Freestone Energy Center in Freestone County, Texas. The agreement provides CyrusOne with access to power, grid connectivity and site infrastructure needed to support development of the new facility. 78

UNAUDITED SUPPLEMENTARY DATA CALPINE CORPORATION AND SUBSIDIARIES SCHEDULE OF VALUATION AND QUALIFYING ACCOUNTS (Unaudited) Description Balance at Beginning of Year Charged to Expense Charged to Other Accounts Deductions(1) Balance at End of Year (in millions) Year Ended December 31, 2025 Allowance for doubtful accounts $ 12 $ 5 $ (11) $ — $ 6 Deferred tax asset valuation allowance $ 91 $ (49) $ — $ — $ 42 Year Ended December 31, 2024 Allowance for doubtful accounts $ 13 $ 5 $ (6) $ — $ 12 Deferred tax asset valuation allowance $ 152 $ (61) $ — $ — $ 91 ____________ (1) Deductions related to the allowance for doubtful accounts represent write-offs of accounts considered to be uncollectible and previously reserved. Deductions related to the valuation allowance represent write-offs of the deferred tax asset balances that have expired and were previously reserved. 79

UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL INFORMATION On January 7, 2026 (the "Closing Date"), Constellation Energy Corporation, a Pennsylvania corporation ("CEG Parent") and Constellation Energy Generation, LLC (“Constellation”, together with CEG Parent, the "Company") completed the acquisition of Calpine Corporation, a Delaware corporation ("Calpine"). As a result of the transactions contemplated by the Agreement and Plan of Merger, dated January 10, 2025 ("the Merger Agreement"), Calpine was converted into a limited liability company, Calpine LLC, and became an indirect, wholly owned subsidiary of Constellation. The following unaudited pro forma condensed combined financial information is presented to reflect the estimated effects of the Merger in accordance with the Merger Agreement. Under the terms of the Merger Agreement, the merger consideration consisted of (A) 50 million newly issued shares of CEG Parent common stock, no par (the "Stock Consideration") and (B) $4,500 million in cash (the "Cash Consideration" and together with the Stock Consideration, "Merger Consideration"). The Merger Consideration is subject to transaction related adjustments effected at the closing of the Merger and certain adjustments as specified in the Merger Agreement. The Unaudited Pro Forma Condensed Combined Statements of Operations for the year ended December 31, 2025, give effect to the Merger as if it was completed on January 1, 2025. The Unaudited Pro Forma Condensed Combined Balance Sheets give effect to the Merger as if it was completed on December 31, 2025. The unaudited pro forma condensed combined financial information (“unaudited pro forma financial statements”) has been derived from, and should be read in conjunction with, (i) the historical audited consolidated financial statements of the Company and accompanying notes included in the Company's annual report on Form 10-K as of and for the year ended December 31, 2025 and (ii) the historical audited consolidated financial statements of Calpine and accompanying notes as of and for the year ended December 31, 2025, filed as Exhibit 99.1 to this Current Report on Form 8-K. In accordance with Article 11 of Regulation S-X, the unaudited pro forma financial statements are prepared for illustrative and informational purposes only and are not intended to represent what the combined results of operations would have been had the acquisition occurred on the date indicated, or what they will be for any future periods. In order to satisfy regulatory requirements, the Company has agreed to divest certain Calpine plants, as well as Calpine's interest in an equity method investment. The unaudited pro forma financial statements have been adjusted to reflect the planned divestitures. The unaudited pro forma financial statements do not reflect the realization of any expected cost savings or other synergies as a result of the Merger. In connection with the Merger, Constellation completed the previously announced private exchange offers (the "Exchange Offers") in January 2026. Upon closing, $2,290 million of aggregate principal amount of fixed rate Constellation debt was exchanged for certain outstanding indebtedness of Calpine (the "Debt Exchange"). In addition, following the Closing Date, Constellation issued $2,750 million of new predominantly fixed-rate debt (the “Debt Issuance”), the proceeds from which were used to pay down Calpine debt assumed. The Debt Exchange and Debt Issuance, inclusive of subsequent pay downs of Calpine debt, did not have a material impact; accordingly, no pro forma adjustments related to these transactions have been reflected in the accompanying unaudited pro forma financial statements. The unaudited pro forma financial statements have been prepared using the acquisition method of accounting for business combinations under generally accepted accounting principles in the United States (“US GAAP”) whereby CEG Parent is considered the accounting acquirer. Under the acquisition method of accounting, the Merger Consideration will be allocated to the identifiable assets acquired and liabilities assumed based upon their estimated fair values as of the closing of the Merger, and any excess value of the Merger Consideration over the acquired net assets will be recognized as goodwill, if applicable. The assets acquired and liabilities assumed of Calpine have been measured based on various preliminary estimates using assumptions that the Company believes are reasonable, based on information that is currently available. The Company expects to complete the final purchase price allocation during the 12-month period following the Closing Date. Due to the unaudited pro forma financial statements being prepared based on preliminary estimates of the net assets acquired as of December 31, 2025, the final purchase price allocation and the resulting effect on financial position and results of operations may differ significantly from the unaudited pro forma amounts included herein. As a result, the pro forma adjustments are preliminary and are subject to change as additional information becomes available and as additional analysis is performed, and these changes may be material. 1

CONSTELLATION ENERGY CORPORATION AND SUBSIDIARY COMPANIES UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET As of December 31, 2025 (in millions) Historical CEG Parent Historical Calpine as Conformed (Note 3) Acquisition Accounting Adjustments Note Pro Forma Combined LIABILITIES AND EQUITY Current liabilities Short-term borrowings $ 1,650 $ — $ — $ 1,650 Long-term debt due within one year 92 279 — 371 Accounts payable and accrued expenses 4,294 1,685 33 (4G) 6,012 Derivative liabilities 467 232 71 (4C) 770 Renewable energy credit obligation 1,075 223 — 1,298 Other 366 335 287 (4C) (4E) 988 Total current liabilities 7,944 2,754 391 11,089 Long-term debt 7,250 12,203 69 (4H) 19,522 Deferred credits and other liabilities Deferred income taxes and unamortized ITCs 3,544 973 2,988 (4I) 7,505 Asset retirement obligations 13,193 259 106 (4J) 13,558 Pension obligations and non- pension postretirement benefit obligations 1,977 — — 1,977 Payables related to Regulatory Agreement Units 5,334 — — 5,334 Derivative liabilities 414 447 (59) (4C) 802 Other 2,740 554 1,335 (4E) 4,629 Total deferred credits and other liabilities 27,202 2,233 4,370 33,805 Total liabilities 42,396 17,190 4,830 64,416 Commitments and contingencies Equity Common stock 11,043 9,933 7,574 (4K) 28,550 Retained earnings (deficit) 5,899 (6,865) 6,817 (4K) 5,851 Accumulated other comprehensive income (loss), net (2,425) (462) 462 (4K) (2,425) Total shareholders' equity 14,517 2,606 14,853 31,976 Noncontrolling interests 336 — — 336 Total equity 14,853 2,606 14,853 32,312 Total liabilities and shareholders' equity $ 57,249 $ 19,796 $ 19,683 $ 96,728 See notes to unaudited pro forma condensed combined financial statements 3

CONSTELLATION ENERGY CORPORATION AND SUBSIDIARY COMPANIES UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS For the year ended December 31, 2025 (in millions, except per share data) Historical CEG Parent Historical Calpine as Conformed (Note 3) Acquisition Accounting Adjustments Note Pro Forma Combined Operating revenues $ 25,533 $ 13,011 $ (1,732) (4E) (4L) $ 36,812 Operating expenses Purchased power and fuel 14,681 7,488 (1,581) (4E) (4L) 20,588 Operating and maintenance 6,159 1,686 103 (4G) (4M) 7,948 Depreciation and amortization 985 798 174 (4N) 1,957 Taxes other than income taxes 622 104 — 726 Total operating expenses 22,447 10,076 (1,304) 31,219 Gain (loss) on sales of assets and businesses — 127 — 127 Operating income (loss) 3,086 3,062 (428) 5,720 Other income and (deductions) Interest expense, net (511) (607) 68 (4O) (1,050) Loss on extinguishment of debt — (7) — (7) Other, net 936 (6) — 930 Total other income and (deductions) 425 (620) 68 (127) Income (loss) before income taxes 3,511 2,442 (360) 5,593 Income tax (benefit) expense 1,187 478 (91) (4I) 1,574 Equity in income (losses) of unconsolidated affiliates (1) 9 — 8 Net income (loss) 2,323 1,973 (269) 4,027 Net income (loss) attributable to noncontrolling interests 4 — — 4 Net income (loss) attributable to common shareholders $ 2,319 $ 1,973 $ (269) $ 4,023 Average shares of common stock outstanding: Basic 313 50 (4P) 363 Diluted 314 50 (4P) 364 Earnings per average common share Basic $ 7.40 (4P) $ 11.08 Diluted $ 7.40 (4P) $ 11.05 See notes to unaudited pro forma condensed combined financial statements 4

CONSTELLATION ENERGY GENERATION, LLC AND SUBSIDIARY COMPANIES UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET As of December 31, 2025 (in millions) Historical Constellation Historical Calpine as Conformed (Note 3) Acquisition Accounting Adjustments Note Pro Forma Combined LIABILITIES AND EQUITY Current liabilities Short-term borrowings $ 1,650 $ — $ — $ 1,650 Long-term debt due within one year 92 279 — 371 Accounts payable and accrued expenses 4,033 1,685 33 (4G) 5,751 Payables to affiliates 365 — — 365 Derivative liabilities 467 232 71 (4C) 770 Renewable energy credit obligation 1,075 223 — 1,298 Other 358 335 287 (4C)( 4E) 980 Total current liabilities 8,040 2,754 391 11,185 Long-term debt 7,250 12,203 69 (4H) 19,522 Deferred credits and other liabilities Deferred income taxes and unamortized ITCs 3,544 973 2,988 (4I) 7,505 Asset retirement obligations 13,193 259 106 (4J) 13,558 Pension obligations and non- pension postretirement benefit obligations 1,977 — — 1,977 Payables related to Regulatory Agreement Units 5,334 — — 5,334 Derivative liabilities 414 447 (59) (4C) 802 Other 2,583 554 1,335 (4E) 4,472 Total deferred credits and other liabilities 27,045 2,233 4,370 33,648 Total liabilities 42,335 17,190 4,830 64,355 Commitments and contingencies Equity Membership interest 10,144 9,933 7,574 (4K) 27,651 Undistributed earnings (deficit) 6,808 (6,865) 6,817 (4K) 6,760 Accumulated other comprehensive income (loss), net (2,425) (462) 462 (4K) (2,425) Total member's equity 14,527 2,606 14,853 31,986 Noncontrolling interests 336 — — 336 Total equity 14,863 2,606 14,853 32,322 Total liabilities and member's equity $ 57,198 $ 19,796 $ 19,683 $ 96,677 See notes to unaudited pro forma condensed combined financial statements 6

CONSTELLATION ENERGY GENERATION, LLC AND SUBSIDIARY COMPANIES UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS For the year ended December 31, 2025 (in millions, except per share data) Historical Constellation Historical Calpine as Conformed (Note 3) Acquisition Accounting Adjustments Note Pro Forma Combined Operating revenues $ 25,533 $ 13,011 $ (1,732) (4E) (4L) $ 36,812 Operating expenses Purchased power and fuel 14,681 7,488 (1,581) (4E) (4L) 20,588 Operating and maintenance 6,159 1,686 103 (4G) (4M) 7,948 Depreciation and amortization 985 798 174 (4N) 1,957 Taxes other than income taxes 622 104 — 726 Total operating expenses 22,447 10,076 (1,304) 31,219 Gain (loss) on sales of assets and businesses — 127 — 127 Operating income (loss) 3,086 3,062 (428) 5,720 Other income and (deductions) Interest expense, net (511) (607) 68 (4O) (1,050) Loss on extinguishment of debt — (7) — (7) Other, net 936 (6) — 930 Total other income and (deductions) 425 (620) 68 (127) Income (loss) before income taxes 3,511 2,442 (360) 5,593 Income tax (benefit) expense 1,187 478 (91) (4I) 1,574 Equity in income (losses) of unconsolidated affiliates (1) 9 — 8 Net income (loss) 2,323 1,973 (269) 4,027 Net income (loss) attributable to noncontrolling interests 4 — — 4 Net income (loss) attributable to membership interest $ 2,319 $ 1,973 $ (269) $ 4,023 See notes to unaudited pro forma condensed combined financial statements 7

Notes to Unaudited Pro Forma Condensed Combined Financial Statements 1. Basis of Presentation The unaudited pro forma financial statements were derived from historical consolidated financial statements of the Company and Calpine which were prepared in accordance with US GAAP. Amounts disclosed relate to CEG Parent and Constellation unless specifically noted. Certain accounting policy alignment and reclassification adjustments were made to conform Calpine's historical financial statement presentation with the Company's historical financial statement presentation, see Note 3 - Accounting Policy Alignment and Reclassification Adjustments for additional information. The Merger is being accounted for as a business combination using the acquisition method of accounting under US GAAP, which requires assets acquired and liabilities assumed to be recorded at their acquisition date fair value. The initial accounting for the Merger is not complete because the valuations necessary to assess the fair values of certain assets acquired and liabilities assumed are preliminary. Therefore, the allocation of the purchase price as reflected in the unaudited pro forma financial statements is based upon management's preliminary estimates of the fair value of the assets acquired and liabilities assumed. The preliminary amounts recognized are subject to revision until the valuations are completed and to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. Differences between these preliminary estimates and the final acquisition accounting may occur and these differences could have a material impact on the accompanying unaudited pro forma financial statements and the combined company’s future results of operations and financial position. 2. Preliminary Purchase Price Allocation The table below represents the preliminary calculation of estimated Merger Consideration for the purposes of the unaudited pro forma financial statements. (in millions) Estimated fair value of CEG Parent common stock issued (1) $ 17,603 Less: Estimated fair value of certain common stock subject to vesting attributable to post-combination expense(2) (96) Purchase price from Stock Consideration $ 17,507 Cash Consideration (3) 4,342 Effective settlement of pre-existing relationships (14) Total Estimated Merger Consideration $ 21,835 __________ (1) Represents the fair value of 50 million shares of CEG Parent common stock issued pursuant to the Merger Agreement, net of transaction related adjustments executed in connection with the closing of the Merger, calculated using CEG Parent's closing stock price of $354.58 on January 6, 2026. (2) Certain CEG Parent common stock issued to Calpine employees is subject to a vesting period up to 26 months and thus has been excluded from the merger consideration and instead will be accounted for post-Merger as stock-based compensation expense in accordance with US GAAP (see Note 4L). (3) Represents cash paid to Calpine shareholders in connection with the Merger. The amount is equal to the Cash Consideration reduced by certain adjustments based on contractual terms specified in the Merger Agreement. Under the acquisition method of accounting, the identifiable assets acquired and liabilities assumed from Calpine are recognized and measured at fair value. The purchase price allocation is preliminary and is based on available information and certain assumptions, which the Company believes are reasonable. 8

The following table presents a preliminary allocation of the estimated Merger Consideration to the fair values of the identifiable assets acquired and liabilities assumed from Calpine, measured as of the Closing Date, based on Calpine's balance sheet as of December 31, 2025, as adjusted for accounting policy alignment and reclassification adjustments as well as acquisition accounting adjustments shown below. (in millions) January 07, 2026 Total estimated Merger Consideration for Calpine Acquisition $ 21,835 Cash and cash equivalents 1,702 Restricted cash and cash equivalents 261 Accounts receivable 758 Derivative assets 1,902 Inventories 942 Assets held for sale 5,654 Property, plant, and equipment 18,790 Renewable energy credits 180 Unamortized energy contracts 2,133 Other assets 678 Total estimated fair value of assets acquired $ 33,000 Accounts payable and accrued expenses 1,683 Debt 12,551 Derivative liabilities 695 Renewable energy credit obligation (1) 302 Deferred income taxes and unamortized ITCs 3,961 Asset retirement obligations 365 Unamortized energy contracts 1,790 Other liabilities 642 Total estimated fair value of liabilities assumed $ 21,989 Estimated net assets acquired $ 11,011 Goodwill $ 10,824 __________ (1) Includes $79 million related to the long term-portion of renewable energy credit obligation. This obligation is classified within Other liabilities (non- current) on the Unaudited Pro Forma Condensed Combined Balance Sheets. 9

3. Accounting Policy Alignment and Reclassification Adjustments Certain reclassification and accounting policy alignment adjustments have been made to conform Calpine's historical financial statement presentation to the Company's historical financial statement presentation and accounting policies. During the preparation of these unaudited pro forma financial statements, the Company performed a preliminary analysis of Calpine’s historical financial information to identify any differences in accounting policies that would require reclassification of Calpine's historical financial statement presentation to conform to the Company's accounting policies. Aside from the accounting policy alignment and reclassification adjustments identified herein, the Company is not aware of any material differences between the accounting policies of the Company and Calpine. The following reflects the accounting policy alignment and reclassification adjustments made to present Calpine’s historical consolidated balance sheet as of December 31, 2025 in conformity with that of the Company: Calpine Corporation and Subsidiaries Consolidated Condensed Balance Sheet As of December 31, 2025 (In millions) Presentation in Historical Financial Statements Conformance with CEG Parent and Constellation Presentation Calpine Historical Reclassification Note Historical Calpine as Conformed Assets Cash and cash equivalents Cash and cash equivalents $ 1,859 $ — $ 1,859 Accounts receivable, net Accounts receivable, net 1,134 (363) (i) 771 Inventories Inventories, net 875 67 (ii) (iv) 942 Margin deposits and other prepaid expense 116 (116) (iii) — Restricted cash, current Restricted cash and cash equivalents 261 — 261 Derivative assets, current Derivative assets (current) 758 — 758 Renewable energy credits 180 (ii) 180 Current assets held for sale AAssets held for sale 1,586 — 1,586 Other current asset Other assets (current) 30 116 (iii) 146 Property, plant and equipment, net Property, plant, and equipment, net 11,624 (164) (iv) 11,460 Restricted cash, net of current portion 1 (1) — Long-term derivative assets Derivative assets (non- current) 1,001 — 1,001 Intangible assets, net 155 (155) (v) — Goodwill Goodwill 242 — 242 Investments in equity interests 136 (136) (vi) — Deferred income tax assets 163 (163) (vii) — Other assets Other assets (non-current) 381 209 (iv) (v) (vi) 590 Total Assets $ 20,322 $ 19,796 8

Calpine Corporation and Subsidiaries Consolidated Condensed Balance Sheet As of December 31, 2025 (In millions) Presentation in Historical Financial Statements Conformance with CEG Parent and Constellation Presentation Calpine Historical Reclassification Note Historical Calpine as Conformed Liabilities Accounts payable Accounts payable and accrued expenses $ 1,260 425 (i) (viii) $ 1,685 Accrued interest payable 87 (87) (viii) — Debt, current portion Long-term debt due within one year 279 — 279 Derivative liabilities, current Derivative liabilities (current) 232 — 232 Current liabilities held for sale 54 (54) (x) Other current liabilities Other liabilities (current) 1,205 (870) (viii) (ix) (x) 335 Renewable energy credit obligation — 223 (ix) 223 Debt, net of current portion Long-term debt 12,203 — 12,203 Deferred income tax liability Deferred income taxes and unamortized ITCs 1,136 (163) (vii) 973 Long-term derivative liabilities Derivative liabilities (non- current) 447 — 447 Other long-term liabilities Other liabilities (non-current) 813 (259) (xi) 554 Asset retirement obligations — 259 (xi) 259 Stockholder's Equity — Common stock Common stock or Membership interest [a] — 9,933 (xii) 9,933 Additional paid-in capital 9,933 (9,933) (xii) — Accumulated deficit Retained earnings (deficit) or Undistributed earnings (deficit) (a) (6,865) — (6,865) Accumulated other comprehensive loss Accumulated other comprehensive income (loss), net (462) — (462) Total Liabilities and Stockholder's Equity $ 20,322 $ 19,796 (a) The “or” designation denotes the presentation for CEG Parent or for Constellation as applicable under each entity’s capital structure in the unaudited pro forma financial statements. (i) Relates to reclassification of $363 million from Accounts receivable, net to Accounts payable and accrued expenses to conform with the Company's historical presentation of unbilled counterparty balances on a net basis. (ii) Relates to reclassification of $180 million from Inventories to Renewable energy credits. (iii) Relates to reclassification of $116 million from Margin deposits and other prepaid expense to Other assets (current). (iv) Relates to reclassification of $247 million of spare parts from Property, plant and equipment, net to Inventories, net partially offset by $83 million of deposits from Other assets to Property, plant and equipment, net. (v) Primarily relates to reclassification of $155 million from Intangible assets, net to Other assets (non-current). (vi) Relates to reclassification of $136 million from Investment in equity interests to Other assets (non-current). (vii) Reclassification of $163 million from Deferred income tax assets to Deferred income taxes and unamortized ITCs) (viii) Reclassification of $701 million from Other current liabilities and $87 million from Accrued interest payable to Accounts payable and accrued expenses. (ix) Reclassification of $223 million from Other current liabilities to Renewable energy credit obligation. (x) Reclassification of $54 million from Current liabilities held for sale to Other liabilities (current). (xi) Reclassification of $259 million from Other long-term liabilities to Asset retirement obligations. (xii) Reclassification of $9,933 million from Additional paid-in capital to Common stock or Membership interest. 9

The following accounting policy alignment and reclassification adjustments were made to present Calpine’s historical consolidated statement of operations for the year ended December 31, 2025 in conformity with that of the Company: Calpine Corporation and Subsidiaries Consolidated Condensed Statement of Operations For the year ended December 31, 2025 (In millions) Presentation in Historical Financial Statements Conformance with CEG Parent and Constellation Presentation Calpine Historical Reclassification Note Historical Calpine as Conformed Commodity revenue Operating revenues $ 13,534 $ (523) (i) (ii) $ 13,011 Mark-to-market (loss) gain - Operating revenue 701 (701) (i) — Other revenue 65 (65) (i) — Commodity expense Purchased power and fuel 8,490 (1,002) (ii) (iii) (iv) 7,488 Mark-to-market loss (gain) - Operating expense 169 (169) (iii) — Operating and maintenance expense Operating and maintenance 1,468 218 (iv) (v) 1,686 Depreciation and amortization expense Depreciation and amortization 798 — 798 General and other administrative expense 165 (165) (v) — Other operating expense 215 (215) (v) — Taxes other than income taxes — 104 (v) 104 Loss on sale of assets. net Gain (loss) on sales of assets and businesses (127) — 127 (Income) loss from unconsolidated subsidiaries Equity in income (losses) of unconsolidated affiliates (9) — 9 Interest expense Interest expense, net 607 — 607 Loss on extinguishment of debt Loss on extinguishment of debt 7 — 7 Other expense, net Other, net 66 (60) (v) 6 Income tax expense Income tax (benefit) expense 478 — 478 Net income $ 1,973 $ 1,973 __________ (i) Reclassification of $701 million from Mark-to-market (loss) gain - Operating revenues and $65 million from Other revenue to Operating revenues. (ii) Adjustment reflects a decrease in both Operating revenues and Purchased power and fuel of $1,289 million in order to conform with the Company's historical presentation of the classification of derivative revenues and expenses, netting of retail transmission and distribution fees, and netting of ISO capacity by region. (iii) Reclassification of $169 million from Mark-to-market loss (gain) - Operating expense to Purchased power and fuel. (iv) Reclassification of $118M from Operating and maintenance to Purchased power and fuel for certain variable, production-related costs, to conform with the Company’s historical presentation. (v) Relates to reclassification of $165 million from General and other administrative expense, $215 million from Other operating expense and $60 million of income from letter of credit fees reclassified from Other expense, net to Operating and maintenance expense; in addition to $104 million in property taxes reclassified from Operating and maintenance expense to Taxes other than income taxes . 10

4. Adjustments to Unaudited Pro Forma Financial Statements A. Reflects a reduction of $4,499 million primarily to reflect the cash portion of the Merger Consideration. B. Reflects effective settlement of pre-existing arrangements and related balances between the Company and Calpine in connection with the acquisition. C. Primarily relates to the adjustment to measuring the impact of the derivative instruments at fair value as of the Closing Date and a reclassification to conform the presentation of collateral allocation and derivative netting to the Company's historical presentation. D. Reflects a step-up of $7,330 million in the fair value of property, plant and equipment acquired and a step-up of $4,068 million in the fair value of assets held for sale. Fair value was estimated using significant assumptions about operating strategies and estimates of future cash flows, which required assessments of current and projected market conditions. Forecasting future cash flows requires assumptions regarding forecasted commodity prices for the sale of power and purchases of fuel and the expected operations of assets. The estimated remaining useful lives of the acquired property, plant and equipment range from 2 to 40 years. The cash flows were discounted using rates between 9% and 15%, depending on the related technology and market in which each respective asset operates, and reflect the risks inherent in the future cash flows. A 0.5% change in the discount rates would increase or decrease the fair value of the property, plant, and equipment by approximately $630 million. E. Primarily relates to adjustments to measure acquired unamortized energy contracts at their preliminary estimated fair value. Unamortized energy contracts totaling $517 million and $367 million are included in Other assets (current) and Other liabilities (current), respectively. Unamortized energy contracts totaling $1,616 million and $1,423 million are included in Other assets (non-current) and Other liabilities (non-current), respectively. Unamortized energy contracts represent non-derivative energy contracts acquired from Calpine. The initial amount recorded for the unamortized energy contracts represents the fair value of the contracts as of the Closing Date. The unamortized energy contract assets and liabilities are amortized over the life of the contract in accordance with the expected realization of the underlying cash flows. The estimated weighted average useful life of Unamortized Energy Contracts is approximately 6 years. Amortization of the unamortized energy contract assets and liabilities is recorded in Operating revenues or Purchased power and fuel expense, depending on the nature of the underlying contract. For the year ended December 31, 2025, the amortization of Unamortized Energy Contracts resulted in a net decrease of $239 million to Operating revenue and a net decrease of $88 million to Purchased power and fuel expense. The following table summarizes the estimated future amortization related to the unamortized energy contracts for each of the next 5 calendar years. The amounts below reflect a net increase (decrease) to Operating income (pre-tax). (in millions) Net Estimated Amortization 2026 $ (151) 2027 88 2028 61 2029 27 2030 14 F. Reflects the elimination of Calpine's historical goodwill and the recognition of preliminary estimated goodwill as a result of the Merger. Refer to Note 2 for the preliminary purchase price allocation. G. Primarily represents the estimated Merger-related transaction costs yet to be expensed or accrued in the Company's historical financial statements through December 31, 2025. Estimated Merger-related transaction costs include investment banker, advisory, legal, valuation and other professional fees. The Company's total estimated Merger-related transaction costs amount to $105 million, with $57 million in expense recognized to date, resulting in a pro forma adjustment of $48 million. H. Reflects an adjustment to measure the long-term debt, net of amounts due within one year, at its estimated fair value. I. Represents the estimated tax impact of the pro forma adjustments based on an assumed tax rate of 25.3%. The assumed tax rate reflects a blended average statutory rate based on the assumed jurisdiction for the pro forma adjustments and current structure. The effective tax rate of the Company following the acquisition could be different depending on post-acquisition activities, including cash needs, the geographical mix of income, and changes in tax law. Because the tax rates used for the unaudited pro forma condensed combined statement of operations are estimated, the blended rate will likely vary from the actual effective tax rate in periods subsequent to the completion of the acquisition. This determination is preliminary and subject to change based upon the final determination of the fair value of the acquired assets and assumed liabilities. J. Reflects an increase of $106 million to asset retirement obligations, primarily due to updated estimated decommissioning costs and the application of the relevant Company discount rates as of the Closing Date. The impact to accretion expense related to the asset retirement obligations adjustment was not material for the year ended December 31, 2025. 12

K. The following tables summarize the transaction accounting adjustments impacting the equity balances of CEG Parent and Constellation as combined with Calpine: (in millions) Elimination of Historical Calpine's Equity Stock Consideration (refer to Note 2) Transaction Adjustments Total Pro Forma Adjustments CEG Parent Shareholders’ Equity Common stock $ (9,933) $ 17,507 $ 7,574 Retained earnings (deficit)(1) 6,865 — (48) 6,817 Accumulated other comprehensive income (loss), net 462 — — 462 Total $ (2,606) $ 17,507 $ (48) $ 14,853 __________ (1) Reflects adjustment to retained earnings for post-combination transaction costs expected to be incurred within 12-months following the anticipated closing date of the Merger. (in millions) Elimination of Historical Calpine's Equity Transaction Adjustments Total Pro Forma Adjustments Constellation Member's Equity Membership interest(1) $ (9,933) $ 17,507 $ 7,574 Undistributed earnings (deficit)(2) 6,865 (48) 6,817 Accumulated other comprehensive income (loss), net 462 — 462 Total $ (2,606) $ 17,459 $ 14,853 __________ (1) The increase in membership interest reflects the additional investment of CEG Parent in Constellation as a result of the acquisition. (2) Reflects adjustment to undistributed earnings for post-combination transaction costs expected to be incurred within 12-months following the anticipated closing date of the Merger. L. This adjustment primarily reflects the impact to the combined company of reporting the sale and purchase of electricity in the spot market on a net hourly basis in either Operating revenues or Purchased power and fuel expense within each region, depending on our net hourly position. Operating revenues and Purchased power and fuel both decreased by $1,287 million for the year ended December 31, 2025, respectively. Additionally, Operating revenues and Purchased power and fuel both decreased by $206 million for the year ended December 31, 2025, respectively, to align with the Company's classification of derivative revenues and expenses. M. Reflects adjustment for stock-based compensation related to the issuance of CEG Parent's common stock to certain members of Calpine's management, with the stock awards subject to vesting based on continued employment. N. Reflects incremental depreciation expense related to the fair value of property, plant, and equipment acquired, net of assets held for sale. Depreciation is ceased for assets held for sale, thus Calpine's historical depreciation expense is eliminated for those assets. O. Reflects an adjustment to decrease interest expense by $68 million for the year ended December 31, 2025, primarily driven by lower interest rates. P. The unaudited pro forma combined basic and diluted earnings per share calculations are based on the average basic and diluted shares of CEG Parent. The following table summarizes the computation of the unaudited pro forma basic and diluted earnings per share: (Amounts and shares in millions) Year ended December 31, 2025 Numerator: Pro forma net income $ 4,023 Basic and diluted pro forma net income attributable to CEG Parent's common shareholders 4,023 Denominator: Historical basic average CEG Parent's shares outstanding 313 Shares of CEG Parent's common stock issued 50 Pro forma basic average CEG Parent's shares outstanding 363 Assumed exercise and/or distributions of stock-based awards 1 Pro forma diluted average CEG Parent's shares outstanding 364 Pro forma basic earnings per share $ 11.08 Pro forma diluted earnings per share $ 11.05 13

Source: View Original Filing on SEC EDGAR

FAQ

What did Constellation Energy (CEG) pay to acquire Calpine?

Constellation acquired 100% of Calpine’s equity for approximately $22 billion. The merger consideration included 50 million newly issued Constellation common shares plus $4.5 billion in cash, making it a large-scale combination in the U.S. power generation sector.

How did Calpine perform financially in 2025 before the Constellation merger?

In 2025, Calpine reported operating revenues of $14.3 billion and net income of $1.97 billion. Operating expenses totaled $11.3 billion, and income from operations was $3.13 billion, highlighting a substantial, profitable generation and retail platform prior to acquisition.

What pro forma financial information did Constellation Energy (CEG) file for the Calpine deal?

Constellation filed unaudited pro forma condensed combined financial statements for CEG Parent and Constellation as of and for the year ended December 31, 2025. These statements, in Exhibit 99.2, show how the combined company’s balance sheet and earnings might look after the Calpine acquisition.

What generating capacity and technologies does Calpine add to Constellation Energy (CEG)?

Calpine brings approximately 28 GW of capacity, including natural gas, geothermal, solar and battery storage assets. Its fleet includes 60 gas-fired plants, a 732 MW geothermal complex at The Geysers, and major storage like the 680 MW Nova battery project in California.

Were any asset divestitures required for Constellation’s acquisition of Calpine?

Yes. Regulatory resolutions required divestitures in PJM and ERCOT, including York 2, Jack Fusco Energy Center, a minority interest in the Gregory Power Plant, and several PJM plants such as Hay Road, Edge Moor, Bethlehem and York 1, to address market overlap concerns.

How is Calpine’s business organized and what markets does it serve?

Calpine operates four segments: West, Texas, East and Retail. It serves wholesale and retail power markets in California, Texas, the Northeast and Mid-Atlantic, selling electricity, capacity, steam and related products to utilities, ISOs, industrials, municipalities and retail customers.

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Constellation Energy (Nasdaq: CEG) completes $22B merger with Calpine

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