Exhibit 99.2

Quarterly Report

For the quarterly period ended September 30, 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

QUARTERLY REPORT

For the Quarter Ended September 30, 2025

INDEX

	Page
Definitions	ii
Forward-Looking Statements	viii
Where You Can Find Other Information	ix
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements (Unaudited)	1
Consolidated Condensed Statements of Operations	1
Consolidated Condensed Statements of Comprehensive Income	2
Consolidated Condensed Balance Sheets	3
Consolidated Condensed Statements of Stockholders’ Equity	4
Consolidated Condensed Statements of Cash Flows	5
Notes to Consolidated Condensed Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
Forward-Looking Information	39
Introduction and Overview	39
Results of Operations	50
Commodity Margin by Segment	54
Liquidity and Capital Resources	57
Risk Management and Commodity Accounting	62
Item 3. Quantitative and Qualitative Disclosures About Market Risk	64
PART II – OTHER INFORMATION
Item 1. Legal Proceedings	65
Item 1A. Risk Factors	65
Item 5. Other Information	65
Item 6. Exhibits	65
Signatures	66

i

DEFINITIONS

As used in this report for the quarter ended September 30, 2025 (this “Report”), the following abbreviations and terms have the meanings as listed below. Additionally, the terms “Calpine,” “we,” “us” and “our” 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.

ABBREVIATION	DEFINITION
2024 Annual Report	Calpine Corporation’s Annual Report for the year ended December 31, 2024, posted to our website on February 18, 2025.
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
AB 32	California Assembly Bill 32
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.

ii

ABBREVIATION	DEFINITION
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.
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.
Cap-and-Trade	A government-imposed emissions reduction program that would place a cap on the amount of emissions that may be emitted from certain sources, such as power plants. In its simplest form, the cap amount is set as a reduction from the total emissions during a base year, and for each year over a period of years, the cap amount would be reduced to achieve the targeted overall reduction by the end of the period. Allowances or credits for emissions equal to the cap would be issued or auctioned to companies with facilities, allowing emissions up to a specified cap during each applicable period. After allowances have been distributed or auctioned, allowances may be transferred or traded.
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
CARB	California Air Resources Board
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.
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.
CFTC	Commodities Futures Trading Commission
Chapter 11	Chapter 11 of the United States (“U.S.”) Bankruptcy Code
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.
CO2	Carbon dioxide

iii

ABBREVIATION	DEFINITION
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.
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.
CPUC	California Public Utilities Commission
DCF	Discounted Cash Flow
EGU	Electric Generating Units
EIA	Energy Information Administration of the U.S. Department of Energy
EPA	U.S. Environmental Protection Agency
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.
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.

iv

ABBREVIATION	DEFINITION
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.
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.
GHG(s)	Greenhouse gas(es), primarily carbon dioxide (CO2), and including methane (CH4), nitrous oxide (N2O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs).
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.
Lyondell	LyondellBasell Industries N.V.
Market Heat Rate(s)	The regional power price divided by the corresponding regional natural gas price.
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.
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.
NEPOOL	New England Power Pool
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.

v

ABBREVIATION	DEFINITION
Nova Credit Agreement	A credit agreement issued by Nova Power, LLC on December 21, 2023, comprising of certain credit facilities totaling more than $1 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.
NOx	Nitrogen oxides
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 a 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)
Risk Management Policy	Calpine’s policy applicable to all employees, contractors, representatives and agents, which defines the risk management framework and corporate governance structure for commodity risk, interest rate risk, currency risk and other risks.
RGGI	Regional Greenhouse Gas Initiative
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.
SEC	U.S. Securities and Exchange Commission
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
SOx	Sulfur oxides
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.

vi

ABBREVIATION	DEFINITION
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.
U.S. GAAP	Generally accepted accounting principles in the U.S.
VIE(s)	Variable interest entity(ies)
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.

vii

Forward-Looking Statements

This Report includes “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the U.S. Securities Act of 1933, as amended, and Section 21E of the U.S. Securities Exchange Act of 1934, as amended. Forward-looking statements may appear throughout this Report, including, without limitation, the “Management’s Discussion and Analysis” section. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will,” “should,” “estimate,” “potential,” “project” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. We believe that the forward-looking statements are based upon reasonable assumptions and expectations. However, you are cautioned that any such forward-looking statements are not guarantees of future performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to:

· Financial results that may be volatile and may not reflect historical trends due to, among other things, seasonality and other changes in demand, fluctuations in prices for commodities such as natural gas and power, changes in U.S. macroeconomic conditions, fluctuations in liquidity and volatility in the energy commodities markets and our ability and the extent to which we hedge risks;

· Laws, regulations and market rules in the wholesale and retail markets in which we participate and our ability to effectively respond to changes in laws, regulations or market rules or the interpretation thereof, including those related to the environment, derivative transactions and market design in the regions in which we operate;

· Our ability to manage interest rate risk, our liquidity needs, including collateral requirements, access the capital markets when necessary and comply with covenants under our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes, Corporate Revolving Facility, Calpine Development Holdings, LLC Credit Agreement, Calpine Construction Finance Company, L.P. Term Loan, Geysers Power Company Term Loan and other existing financing obligations;

· Risks associated with the operation, construction and development of power plants, battery storage facilities and carbon capture facilities, including unscheduled outages or delays and plant efficiencies;

· Risks related to our geothermal resources, including the adequacy of our steam reserves, unusual or unexpected steam field well and pipeline maintenance requirements, variables associated with the injection of water to the steam reservoir and potential regulations or other requirements related to seismicity concerns that may delay or increase the cost of developing or operating geothermal resources;

· Extensive competition in our wholesale and retail businesses, including challenges from renewable sources of power, interference by states in competitive power markets through subsidies or similar support for new or existing power plants, new and existing federal subsidies, lower prices and other incentives offered by retail competitors, and other risks associated with marketing and selling power in the evolving energy markets;

· Structural changes in the supply and demand of power, resulting from the development of new fuels or technologies and continued development of demand-side management tools (such as power storage, distributed generation and other technologies);

· The expiration or early termination of our PPAs and the related results on revenues;

· Future capacity revenue may not occur at expected levels;

· Natural disasters, such as hurricanes, earthquakes, droughts, floods, extreme winter weather and wildfires, acts of terrorism or cyber attacks that may affect our power plants and battery storage facilities or the markets our power plants, battery storage facilities or retail operations serve and our corporate offices as well as pandemics, such as COVID-19, and the impact on our business, suppliers, customers, employees and supply chains;

· Disruptions in or limitations on the transportation of natural gas or fuel oil and the transmission of power;

· Our ability to manage our counterparty and customer exposure and credit risk, including our commodity positions or if a significant customer were to seek bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code;

· Our ability to attract, motivate and retain key employees;

viii

· The impact of federal and state legislative actions and executive branch actions, including Presidential Executive Orders, tariffs, changes to agency regulations or changes to tax laws individually or in the aggregate, could adversely affect our development efforts, operations, cash flows or cost of capital in the credit markets and ultimately our financial condition and results of operations;

· Present and possible future claims and litigation, including litigation arising out of Winter Storm Uri and enforcement actions that may arise from noncompliance with market rules promulgated by the SEC, CFTC, FERC and other regulatory bodies; and

· Other risks are identified in this Report and our 2024 Annual Report.

Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of the date of this Report. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise.

Where You Can Find Other Information

Our website is www.calpine.com. The information contained on our website is not part of this Report. All future financial reports will be posted on our website.

ix

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS

(Unaudited)

(in millions)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2025			2024		2025			2024
Operating revenues:
Commodity revenue	$	3,759		$	3,610	$	10,128		$	9,340
Mark-to-market (loss) gain		(184	)		305		(310	)		167
Other revenue		42			5		55			63
Operating revenues		3,617			3,920		9,873			9,570
Operating expenses:
Fuel and purchased energy expense:
Commodity expense		2,225			1,867		6,118			5,347
Mark-to-market (gain) loss		(49	)		106		109			30
Fuel and purchased energy expense		2,176			1,973		6,227			5,377
Operating and maintenance expense		354			336		1,063			1,047
Depreciation and amortization expense		203			193		611			568
General and other administrative expense		43			46		121			121
Other operating expenses		122			21		186			63
Total operating expenses		2,898			2,569		8,208			7,176
(Gain) loss on sale of assets, net		(127	)		13		(127	)		13
(Income) loss from unconsolidated subsidiaries		(4	)		2		(10	)		6
Income from operations		850			1,336		1,802			2,375
Interest expense		160			154		474			426
Loss on extinguishment of debt		—			8		—			38
Other expense, net		21			5		55			23
Income before income taxes		669			1,169		1,273			1,888
Income tax expense		162			260		325			439
Net income	$	507		$	909	$	948		$	1,449

The accompanying notes are an integral part of these Consolidated Condensed Financial Statements.

1

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(in millions)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2025			2024			2025			2024
Net income	$	507		$	909		$	948		$	1,449
Cash flow hedging activities:
(Loss) gain on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income		(161	)		109			(366	)		45
Reclassification adjustment for gain (loss) on cash flow hedges realized in net income		104			166			(15	)		197
Unrealized actuarial losses arising during period		—			1			—			1
Foreign currency translation (loss) gain		—			(1	)		1			(1	)
Deferred income tax benefit (expense)		14			(70	)		95			(61	)
Other comprehensive (loss) income		(43	)		205			(285	)		181
Comprehensive income	$	464		$	1,114		$	663		$	1,630

The accompanying notes are an integral part of these Consolidated Condensed Financial Statements.

2

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited)

(in millions)

	September 30,			December 31,
	2025			2024
ASSETS
Current assets:
Cash and cash equivalents ($64 and $38 attributable to VIEs)	$	1,149		$	706
Accounts receivable, net of allowance of $7 and $12		1,163			1,038
Inventories ($135 and $127 attributable to VIEs)		967			955
Margin deposits and other prepaid expense		121			144
Restricted cash, current ($107 and $140 attributable to VIEs)		292			278
Derivative assets, current		431			579
Current assets held for sale		952			—
Other current assets ($2 and $15 attributable to VIEs)		38			23
Total current assets		5,113			3,723
Property, plant and equipment, net ($4,271 and $4,033 attributable to VIEs)		12,005			12,579
Restricted cash, net of current portion ($1 and nil attributable to VIEs)		1			1
Investments in unconsolidated subsidiaries		157			77
Long-term derivative assets ($28 and $69 attributable to VIEs)		530			559
Intangible assets, net		164			189
Goodwill		242			242
Other long-term assets ($27 and $73 attributable to VIEs)		364			425
Total assets	$	18,576		$	17,795
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	1,142		$	1,132
Accrued interest payable		29			87
Debt, current portion ($194 and $166 attributable to VIEs)		274			355
Derivative liabilities, current		339			316
Current liabilities held for sale		4			—
Other current liabilities ($100 and $98 attributable to VIEs)		1,064			1,345
Total current liabilities		2,852			3,235
Debt, net of current portion ($3,998 and $4,132 attributable to VIEs)		11,781			11,807
Deferred income tax liability		915			752
Long-term derivative liabilities		484			388
Other long-term liabilities		895			629
Total liabilities		16,927			16,811
Commitments and contingencies (see Note 10)
Stockholders’ equity:
Common stock (see Note 12)
Class A shares: par value $.001; number of shares authorized at September 30, 2025 -
1,400,000 and December 31, 2024 - 1,200,000; number of shares issued and outstanding at
September 30, 2025 - 952,153 and December 31, 2024 - 952,153
Class B shares: par value $.001; number of shares authorized at September 30, 2025 -
200,000 and December 31, 2024 - 200,000; number of shares issued and outstanding at
September 30, 2025 - 48,654 and December 31, 2024 - 48,651
Class C shares: par value $.001; number of shares authorized at September 30, 2025 -
200,000 and December 31, 2024 - nil; number of shares issued and outstanding at
September 30, 2025 - nil and December 31, 2024 - nil		—			—
Additional paid-in capital		9,933			9,931
Accumulated deficit		(7,890	)		(8,838	)
Accumulated other comprehensive loss		(394	)		(109	)
Total stockholders’ equity		1,649			984
Total liabilities and stockholders’ equity	$	18,576		$	17,795

The accompanying notes are an integral part of these Consolidated Condensed Financial Statements.

3

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited)

(in millions)

	Common Stock		Additional Paid-In Capital		Accumulated Deficit			Accumulated Other Comprehensive Loss			Total Stockholders’ Equity
Balance, December 31, 2024	$	—	$	9,931	$	(8,838	)	$	(109	)	$	984
Net income		—		—		195			—			195
Other comprehensive loss		—		—		—			(240	)		(240	)
Balance, March 31, 2025	$	—	$	9,931	$	(8,643	)	$	(349	)	$	939
Stock-based compensation		—		1		—			—			1
Net income		—		—		246			—			246
Other comprehensive loss		—		—		—			(2	)		(2	)
Balance, June 30, 2025	$	—	$	9,932	$	(8,397	)	$	(351	)	$	1,184
Stock-based compensation		—		1		—			—			1
Net income		—		—		507			—			507
Other comprehensive income		—		—		—			(43	)		(43	)
Balance, September 30, 2025	$	—	$	9,933	$	(7,890	)	$	(394	)	$	1,649

	Common Stock		Additional Paid-In Capital		Accumulated Deficit			Accumulated Other Comprehensive Loss			Total Stockholders’ Equity
Balance, December 31, 2023	$	—	$	9,929	$	(8,601	)	$	(285	)	$	1,043
Net income		—		—		302			—			302
Other comprehensive income		—		—		—			29			29
Balance, March 31, 2024	$	—	$	9,929	$	(8,299	)	$	(256	)	$	1,374
Stock-based compensation		—		1		—			—			1
Net income		—		—		238			—			238
Other comprehensive loss		—		—		—			(53	)		(53	)
Balance, June 30, 2024	$	—	$	9,930	$	(8,061	)	$	(309	)	$	1,560
Net income		—		—		909			—			909
Other comprehensive income		—		—		—			205			205
Balance, September 30, 2024	$	—	$	9,930	$	(7,152	)	$	(104	)	$	2,674

The accompanying notes are an integral part of these Consolidated Condensed Financial Statements.

4

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

(in millions)

	Nine Months Ended September 30,
	2025			2024
Cash flows from operating activities:
Net income	$	948		$	1,449
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense(1)		637			603
Loss on extinguishment of debt		—			30
Gain on sale of Bosque land		(117	)		—
Deferred income taxes		250			326
Proceeds from sale of ITC		53			353
Mark-to-market activity, net		454			(120	)
(Income) loss from unconsolidated subsidiaries		(10	)		6
Stock-based compensation		2			1
Other		(53	)		14
Change in operating assets and liabilities:
Accounts receivable		(1	)		78
Accounts payable and accrued expenses		84			(143	)
Margin deposits and other prepaid expense		3			(74	)
Other assets and liabilities, net		(204	)		203
Derivative instruments, net		(526	)		180
Net cash provided by operating activities		1,520			2,906
Cash flows from investing activities:
Purchases of property, plant and equipment(2)		(854	)		(762	)
Acquisition of power plants, net of cash acquired, and other		—			(334	)
Cash contributions to unconsolidated subsidiaries		(70	)		(6	)
Other		2			(2	)
Net cash used in investing activities		(922	)		(1,104	)
Cash flows from financing activities:
Borrowings under CCFC Term Loan and First Lien Term Loans		—			651
Repayments of CCFC Term Loan, Corporate First Lien Term Loan and Corporate First Lien Notes		(140	)		(11	)
Borrowings under revolving facilities		237			200
Repayments of borrowings under revolving facilities		(106	)		(331	)
Borrowings under construction loan facilities, project financing, notes payable and other		—			306
Repayments of borrowings under construction loan facilities, project financing, notes payable and other		(127	)		(290	)
Debt issuance costs		—			(24	)
Other		(5	)		(10	)
Net cash (used in) provided by financing activities		(141	)		491
Net increase in cash, cash equivalents and restricted cash		457			2,293
Cash, cash equivalents and restricted cash, beginning of period		985			348
Cash, cash equivalents and restricted cash, end of period(3)	$	1,442		$	2,641

The accompanying notes are an integral part of these Consolidated Condensed Financial Statements.

5

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS — (CONTINUED)

(Unaudited)

(in millions)

	Nine Months Ended September 30,
	2025			2024
Cash paid during the period for:
Interest, net of amounts capitalized	$	467		$	469
Income taxes	$	84		$	66
Supplemental disclosure of non-cash investing and financing activities:
Capital expenditures included in accounts payable and accrued expenses and other assets and liabilities, net	$	221		$	171
Capital expenditures transferred from other assets to property, plant and equipment, net(2)	$	(179	)	$	(119	)
Contribution to Calpine Receivables, LLC	$	—		$	15
Extended maturity of loans related to master securities lending transaction	$	—		$	(95	)
Recognition of loans related to master securities lending transaction	$	—		$	95
Recognition of investment tax credits(4)	$	49		$	42

(1)	Includes amortization recorded in commodity revenue and commodity expense in the Consolidated Condensed Statements of Operations associated with intangible assets amortization. Additionally, includes amortization of debt issuance costs and discounts recorded in interest expense in the Consolidated Condensed 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 Condensed Balance Sheets and as a cash outflow within operating activities in our Consolidated Condensed Statements of Cash Flows. These amounts are subsequently transferred from other assets to property, plant and equipment, net in our Consolidated Condensed 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 Condensed 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 Condensed Balance Sheets.
(4)	Recognition of investment tax credits related to Geysers assets in 2025 and Nova battery storage facility in 2024 and 2025.

The accompanying notes are an integral part of these Consolidated Condensed Financial Statements.

6

CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation and Summary of Significant Accounting Policies

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.

Basis of Interim Presentation

The accompanying unaudited, interim Consolidated Condensed Financial Statements of Calpine Corporation and consolidated subsidiaries have been prepared in accordance with U.S. GAAP, including reporting requirements for non-public companies. In the opinion of management, the Consolidated Condensed Financial Statements include the normal, recurring adjustments necessary for a fair statement of the information required to be set forth therein. Certain information and note disclosures, normally included in annual financial statements prepared in accordance with U.S. GAAP, have been condensed or omitted from these statements pursuant to such rules and, accordingly, these financial statements should be read in conjunction with our audited Consolidated Financial Statements for the year ended December 31, 2024, included in our 2024 Annual Report. The results for interim periods are not indicative of the results for the entire year primarily due to acquisitions and disposals of assets, seasonal fluctuations in our revenues and expenses, timing of major maintenance expense, variations resulting from the application of the method to calculate the provision for income taxes for interim periods, volatility of commodity prices and mark-to-market gains and losses from commodity and interest rate derivative contracts.

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.

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 Condensed Balance Sheets.

7

The table below represents the components of restricted cash as of September 30, 2025 and December 31, 2024 (in millions):

	September 30, 2025						December 31, 2024
	Current		Non-Current		Total		Current		Non-Current		Total
Construction/major maintenance	$	107	$	—	$	107	$	140	$	—	$	140
Security/project/insurance		179		—		179		133		—		133
Other		6		1		7		5		1		6
Total	$	292	$	1	$	293	$	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 Condensed Statements of Cash Flows to the total of the same amounts reported in the Consolidated Condensed Balance Sheets as of September 30, 2025 and December 31, 2024 (in millions):

	September 30, 2025		December 31, 2024
Cash and cash equivalents	$	1,149	$	706
Restricted cash included in current and non-current assets		293		279
Total cash and cash equivalents and restricted cash	$	1,442	$	985

Business Interruption Proceeds

The Company records business interruption insurance proceeds when amounts are realizable. We recorded no business interruption proceeds in operating revenues in the three and nine months ended September 30, 2025 and 2024.

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 $7 million and $12 million as of September 30, 2025 and December 31, 2024, respectively.

Property, Plant and Equipment, Net

As of September 30, 2025 and December 31, 2024, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):

	September 30, 2025			December 31, 2024			Depreciable Lives
Buildings, machinery and equipment	$	16,542		$	17,921		1.5    –     35     Years
Geothermal properties		1,864			1,811		13    –     58     Years
Other		489			407		3    –     35     Years
		18,895			20,139
Less: Accumulated depreciation		(7,845	)		(8,237	)
		11,050			11,902
Land		110			115
Construction in progress		845			562
Property, plant and equipment, net	$	12,005		$	12,579

Capitalized Interest

The total amount of interest capitalized was $8 million and $7 million during the three months ended September 30, 2025 and 2024, respectively, and $21 million and $38 million during the nine months ended September 30, 2025 and 2024, respectively.

8

Current Environmental Liability

As of September 30, 2025 and December 31, 2024, the Company's current environmental liability is $276 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 Condensed Balance Sheets.

Leases

Lessee — Supplemental balance sheet information related to operating and finance leases is as follows (in millions):

	Location on Consolidated Condensed Balance Sheets	September 30, 2025		December 31, 2024
Right-of-use assets – operating leases	Other long-term assets	$	141	$	140
Right-of-use assets – finance leases	Property, plant and equipment, net	$	61	$	61
Operating lease obligation, current	Other current liabilities	$	8	$	9
Operating lease obligation, long-term	Other long-term liabilities	$	149	$	145
Finance lease obligation, current	Debt, current portion	$	6	$	5
Finance lease obligation, long-term	Debt, net of current portion	$	18	$	16

Lessor — The Company applies lease accounting to PPAs and certain land leases that meet the definition of a lease and determines lease classification treatment at commencement of the agreement. Revenue recognized related to fixed lease payments on operating leases was $74 million and $54 million during the three months ended September 30, 2025 and 2024, respectively, and $152 million and $106 million during the nine months ended September 30, 2025 and 2024, respectively.

Goodwill

In accordance with ASC 350, Intangibles—Goodwill and Other, 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 September 30, 2025 and December 31, 2024. As of September 30, 2025 and December 31, 2024, the Company's goodwill is $242 million and $242 million, respectively. The Company did not record any impairment losses during either of the three and nine months ending September 30, 2025 or 2024.

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 (“Constellation”), 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.

9

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 the line items current assets held for sale and current liabilities held for sale in the Consolidated Condensed Balance Sheets.

Subsequent Events

We have evaluated subsequent events through November 3, 2025, the date the financial statements were available to be issued and have disclosed all material subsequent events in Note 15, Subsequent Events.

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 ASU is effective for fiscal years beginning after December 15, 2024, for public business entities, with early adoption permitted, and can be applied prospectively or retrospectively. While the Company is not a public company, it is currently assessing the impact of adopting ASU 2023-09 on its Consolidated Condensed Financial Statement disclosure and we do not believe there will be a material effect to Calpine..

Compensation—Stock Compensation — In March 2024, the FASB issued ASU 2024-01, “Compensation—Stock Compensation (Topic 718): Scope Application of Profits Interest and Similar Awards (“ASU 2024-01”). ASU 2024-01 adds an example to Topic 718 which illustrates how to apply the scope guidance to determine whether profits interests and similar awards should be accounted for as share-based payment arrangements under Topic 718 or under other U.S. GAAP. ASU 2024-01 is effective for annual periods beginning after December 15, 2025, although early adoption is permitted. Upon adoption, ASU 2024-01 is not expected to have an impact on the Company's financial statements.

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 Condensed Financial Statement disclosure.

10

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 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 Condensed Financial Statement disclosure.

2. 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 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 Company funded the acquisition 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. As the Company closed on this acquisition during September 2024, the incremental impact of Quail Run Energy Center on the results of operations for the three months ended September 30, 2024 was not material.

There were no acquisitions during the nine months ended September 30, 2025.

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 secures power, grid connection and land to support the second facility and brings total MW’s under contract with CyrusOne to 400 MW’s.

Assets Held For Sale

The assets and liabilities of Bethlehem Energy Center, York Energy Center Unit 1, Hay Road Energy Center and Edge Moor Energy Center, which are part of our East segment, were reclassified to current assets held for sale and current liabilities held for sale in our Consolidated Condensed Balance Sheets at September 30, 2025. The conclusion to reclassify all balances is reached following conditional FERC approval for the Plan of Merger Agreement between Constellation Energy Group and Calpine Corporation in July 2025. The Plan of Merger Agreement identified these four assets for sale to address market power concerns arising from the transaction. Calpine did not recognize any gains or losses upon reclassification of all balances to held for sale during the three and nine months ended September 30, 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.

11

The table below presents the carrying amounts of the major classes of assets and liabilities included as part of the expected sale (in millions):

	September 30, 2025
Inventories	$	25
Other prepaid expense		1
Property, plant and equipment		926
Total current assets held for sale	$	952
Other current liabilities	$	1
Other long-term liabilities		3
Total current liabilities held for sale	$	4

The pre-tax income for the disposal group included in Calpine’s Condensed Statements of Operations was not material.

3. Revenue from Contracts with Customers

The following tables represent a disaggregation of revenue by reportable segment (in millions). See Note 14, Segment Information for a description of these segments.

	Three Months Ended September 30, 2025
	Wholesale
	West		Texas		East		Retail		Elimination			Total
Third-Party:
Energy & other products	$	274	$	362	$	418	$	327	$	—		$	1,381
Capacity		240		125		200		—		—			565
Revenues relating to physical or executory contracts – third-party	$	514	$	487	$	618	$	327	$	—		$	1,946
Affiliate(1):	$	100	$	106	$	16	$	10	$	(232	)	$	—
Revenues relating to leases and derivative instruments(2)												$	1,671
Total operating revenues												$	3,617

	Three Months Ended September 30, 2024
	Wholesale
	West		Texas		East		Retail		Elimination			Total
Third-Party:
Energy & other products	$	277	$	319	$	425	$	315	$	—		$	1,336
Capacity		234		93		106		—		—			433
Revenues relating to physical or executory contracts – third-party	$	511	$	412	$	531	$	315	$	—		$	1,769
Affiliate(1):	$	54	$	97	$	17	$	13	$	(181	)	$	—
Revenues relating to leases and derivative instruments(2)												$	2,151
Total operating revenues												$	3,920

12

	Nine Months Ended September 30, 2025
	Wholesale
	West		Texas		East		Retail		Elimination			Total
Third-Party:
Energy & other products	$	675	$	941	$	1,278	$	847	$	—		$	3,741
Capacity		605		375		418		—		—			1,398
Revenues relating to physical or executory contracts – third-party	$	1,280	$	1,316	$	1,696	$	847	$	—		$	5,139
Affiliate(1):	$	173	$	263	$	50	$	35	$	(521	)	$	—
Revenues relating to leases and derivative instruments(2)												$	4,734
Total operating revenues												$	9,873

	Nine Months Ended September 30, 2024
	Wholesale
	West		Texas		East		Retail		Elimination			Total
Third-Party:
Energy & other products	$	674	$	925	$	1,220	$	814	$	—		$	3,633
Capacity		480		278		278		—		—			1,036
Revenues relating to physical or executory contracts – third-party	$	1,154	$	1,203	$	1,498	$	814	$	—		$	4,669
Affiliate(1):	$	143	$	222	$	51	$	45	$	(461	)	$	—
Revenues relating to leases and derivative instruments(2)												$	4,901
Total operating revenues												$	9,570

(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 three and nine months ended September 30, 2025 and 2024. Revenue related to derivative instruments includes revenue recorded in Commodity revenue and mark-to-market gain (loss) within operating revenues in the Consolidated Condensed 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.

13

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.

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 three and nine months ended September 30, 2025 and 2024, 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 September 30, 2025 and December 31, 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 $892 million and $891 million, as of September 30, 2025 and December 31, 2024, respectively, and is included within accounts receivable, net in the Consolidated Condensed 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 September 30, 2025 and December 31, 2024, 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 Condensed Balance Sheets. The balance outstanding as of September 30, 2025 and December 31, 2024 was $149 million and $112 million, respectively. Revenue recognized during the three and nine months ended September 30, 2025, relating to the deferred revenue balance at the beginning of the period, was $33 million and $43 million, respectively, and resulted from performance under our customer contracts. The change in the deferred revenue balance as of September 30, 2025 and December 31, 2024, was primarily due to the timing difference of when consideration was received and when the related good or service was transferred.

14

Contract Costs

For certain retail contracts, third-party incremental broker costs are incurred and are capitalized on the Consolidated Condensed 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 September 30, 2025 and December 31, 2024, respectively, the capitalized contract cost balance was not material. There were no impairment losses or changes in amortization during the three and nine months ended September 30, 2025, and amortization of contract costs during these periods was immaterial.

Performance Obligations not yet Satisfied

As of September 30, 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 $195 million, $854 million, $584 million, $298 million and $236 million, that will be recognized during the years ending December 31, 2025, 2026, 2027, 2028 and 2029, respectively, and $493 million thereafter. Revenues under these contracts will be recognized as control of the commodities is transferred to customers.

4. Variable Interest Entities and 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 nine months ended September 30, 2025. See Note 7, Variable Interest Entities and Unconsolidated Investments in the 2024 Annual Report for further information regarding these existing VIEs.

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 on September 30, 2025 and December 31, 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 either of the three and nine months ended September 30, 2025 or 2024.

U.S. GAAP requires separate disclosure on the face of the Consolidated Condensed 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.

15

Unconsolidated VIEs and Investments in Unconsolidated Subsidiaries

Calpine Receivables and Gregory Power Holdings, LLC are unconsolidated investments as of September 30, 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 Condensed Financial Statements but instead uses the equity method of accounting to record the net interest in Calpine Receivables.

As of September 30, 2025, the Company has a 52.8% non-economic (for certain voting rights) and 42.7% economic interest in Gregory Power Holdings, LLC with an obligation to fund future cash contributions to Gregory Power Holdings, LLC, until such time as its economic investment interest reaches 45% ownership in the entity. The Company made $70 million in cash contributions to Gregory Power Holdings, LLC during the nine months ended September 30, 2025. The Company's net interest in Gregory Power Holdings, LLC is accounted for as an equity method investment on September 30, 2025. The Company does not consolidate Gregory Power Holdings, LLC because it does not exert significant influence over the investment.

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 Condensed Balance Sheets. As of September 30, 2025 and December 31, 2024, the Company's investments included in the Consolidated Condensed Balance Sheets were comprised of the following (in millions):

	Ownership Interest as of September 30, 2025			September 30, 2025		December 31, 2024
Calpine Receivables(1)		100	%	$	43	$	25
Gregory Power Holdings, LLC(2)		42.7	%		107		44
Total investment in unconsolidated subsidiaries under equity method of accounting(3)				$	150	$	69

(1)	The Company's ownership interest as of September 30, 2025 and December 31, 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 September 30, 2025 and December 31, 2024 was 42.7% and 28.5%, respectively. The Company's investment in Gregory Power Holdings, LLC is 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 of as of September 30, 2025 and December 31, 2024, respectively.

The Company's risk of loss related to its investment in Calpine Receivables is $77 million and $100 million as of September 30, 2025 and December 31, 2024, respectively, which consists of notes receivable from Calpine Receivables and its investment associated with Calpine Receivables. The Company has $45 million and $45 million as of September 30, 2025 and December 31, 2024, respectively, of related party debt outstanding with Calpine Receivables offset against its investment in the entity. See Note 11, 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 our unconsolidated investments is not reflected on the Consolidated Condensed Balance Sheets at either September 30, 2025 or December 31, 2024.

16

The Company's equity interest in the net (income) loss from its investments in unconsolidated subsidiaries for the three and nine months ended September 30, 2025 and 2024 is recorded in (income) loss from unconsolidated subsidiaries in the Consolidated Condensed Statements of Operations. The following table reflects (income) loss from unconsolidated subsidiaries for the periods indicated (in millions):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2025			2024		2025			2024
Calpine Receivables	$	(7	)	$	2	$	(17	)	$	6
Gregory Power Holdings, LLC		3			—		7			—
Total	$	(4	)	$	2	$	(10	)	$	6

The Company did not have any distributions from its investments during the three and nine months ended September 30, 2025 and 2024.

5. Debt

The Company's debt is summarized in the table below (in millions):

	September 30, 2025			December 31, 2024
Revolving facilities(1) (2)	$	278		$	148
First Lien Term Loans		2,487			2,484
CCFC Term Loan (3)		1,866			1,864
GPC Term Loan		1,398			1,486
Construction loan facilities, project financing, notes payable and other		975			997
Senior Unsecured Notes		2,888			2,886
First Lien Notes(4)		2,139			2,276
Finance lease obligations		24			21
Subtotal		12,055			12,162
Less: Current maturities		(274	)		(355	)
Total long-term debt	$	11,781		$	11,807

(1) On January 31, 2024, the Company extended the term on our Corporate Revolving Facility from January 2027 to January 2029 for a total notional amount of $2.225 billion, with the remaining $275 million expiring in January 2027. On December 16, 2024, the Company amended the Corporate Revolving Facility commitments with $2.400 billion expiring January 2029 and the remaining $100 million expiring January 2027.

(2) As of September 30, 2025 and December 31, 2024, total outstanding debt consisted of $278 million and $148 million, respectively, under the CDHI Credit Agreement.

(3) On June 6, 2024, the Company, through its wholly-owned subsidiary, Calpine Construction Finance Company, L.P., completed a repricing of the CCFC Term Loan to reduce the applicable spread over the SOFR rate and remove the quarterly principal payments prior to the maturity of the debt. Subsequently, on September 16, 2024, the Company completed a refinancing to increase the total notional principal amount of the CCFC Term Loan from $1.244 billion to $1.875 billion. The term of the credit agreement remains unchanged through July 2030.

(4) On January 9, 2025, the Company redeemed the remaining outstanding balance on our 2026 First Lien Notes with a payment of approximately $140 million funded primarily from proceeds associated with the upsizing of our First Lien Term Loan transaction executed during December 2024.

The effective interest rate on consolidated debt, including the cash settlement contribution of interest rate hedging instruments, was 5.0% and 4.9% as of September 30, 2025 and December 31, 2024, respectively. The effective interest rate excludes the impacts of capitalized interest and unrealized mark-to-market gains and losses on interest rate derivative instruments that economically hedge interest rate exposure.

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Letter of Credit Facilities

The letters of credit issued under revolving credit agreements and other letter of credit facilities on September 30, 2025 and December 31, 2024 are summarized in the table below (in millions):

	September 30, 2025		December 31, 2024
Corporate Revolving Facility(1)	$	682	$	273
CDHI Credit Agreement(2)		524		640
Project financing facilities		315		290
Other corporate facilities(3)		724		849
Total(4)	$	2,245	$	2,052

(1) The Corporate Revolving Facility represents our primary revolving facility.

(2) As of September 30, 2025 and December 31, 2024, CDHI Credit Agreement has a total capacity of approximately $1.2 billion and $1.2 billion, respectively, and matures on March 29, 2028. The facility can be used for general corporate purposes with a limit of up to $400 million for construction loans.

(3) The Company has unsecured letter of credit facilities with a total capacity of approximately $200 million and $325 million at September 30, 2025 and December 31, 2024, respectively. In June 2025, the Goldman Sachs Credit Default Swaps (“CDS”) backed letter of credit facility totaling approximately $125 million expired and was not renewed. The Company also has four secured bilateral letter of credit agreements for up to $525 million and $525 million of capacity with varying tenors at September 30, 2025 and December 31, 2024, respectively.

(4) This amount does not include any debt balances drawn under our credit agreements.

First Lien Term Loans

First Lien Term Loans are summarized in the table below (in millions):

	September 30, 2025		December 31, 2024
2032 First Lien Term Loans (1)	$	852	$	851
2031 First Lien Term Loans (2)		1,635		1,633
Total	$	2,487	$	2,484

(1) In December 2024, a refinancing of the 2032 First Lien Term Loans was completed, extending the maturity on the new $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.

(2) 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, and the original term remains unchanged through January 2031.

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):

	September 30, 2025		December 31, 2024
Nova (1)	$	587	$	607
Pasadena (2)		3		4
Bethpage Energy Center 3		—		7
Greenfield		338		332
Other (3)		47		47
Total	$	975	$	997

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(1) 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 First Lien Term Loan is used to finance the construction of the Nova Power Battery Facility and is secured by the assets of Nova Power Holdco.

(2) Represents a failed sale-leaseback transaction that is accounted for as a financing transaction under U.S. GAAP.

(3) As of September 30, 2025 and December 31, 2024, the Company has $45 million and $45 million related party debt outstanding with Calpine Receivables offset against its investment in the entity.

Senior Unsecured Notes

The Senior Unsecured Notes amounts are summarized in the table below (in millions):

	September 30, 2025		December 31, 2024
2028 Senior Unsecured Notes	$	1,396	$	1,395
2029 Senior Unsecured Notes		647		646
2031 Senior Unsecured Notes		845		845
Total	$	2,888	$	2,886

First Lien Notes

The First Lien Notes are summarized in the table below (in millions):

	September 30, 2025		December 31, 2024
2026 First Lien Notes	$	—	$	139
2028 First Lien Notes		1,245		1,244
2031 First Lien Notes		894		893
Total	$	2,139	$	2,276

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):

	September 30, 2025				December 31, 2024
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Unsecured Notes	$	2,890	$	2,888	$	2,750	$	2,886
First Lien Term Loans		2,507		2,487		2,502		2,484
First Lien Notes		2,103		2,139		2,139		2,275
CCFC Term Loan		1,876		1,866		1,870		1,864
GPC Term Loan		1,416		1,398		1,508		1,486
Construction loan facilities, project financing, notes payable and other(1)		992		972		1,014		993
Revolving facilities		278		278		148		148
Total	$	12,062	$	12,028	$	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.

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6. 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 Condensed 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 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 our 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 our 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 our 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 our 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.

20

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 September 30, 2025 and December 31, 2024, by level within the fair value hierarchy (in millions):

	Assets and Liabilities with Recurring Fair Value Measures as of
	September 30, 2025
	Level 1			Level 2			Level 3			Total
Assets:
Cash equivalents(1)	$	495		$	—		$	—		$	495
Commodity instruments:
Commodity exchange traded derivatives contracts		1,797			—			—			1,797
Commodity forward contracts(2)		—			407			757			1,164
Interest rate derivative instruments		—			125			—			125
Effect of netting and allocation of collateral(3)(4)		(1,797	)		(284	)		(44	)		(2,125	)
Total assets	$	495		$	248		$	713		$	1,456
Liabilities:
Commodity instruments:
Commodity exchange traded derivatives contracts	$	2,282		$	—		$	—		$	2,282
Commodity forward contracts(2)		—			643			489			1,132
Interest rate derivative instruments		—			13			—			13
Effect of netting and allocation of collateral(3)(4)		(2,282	)		(285	)		(37	)		(2,604	)
Total liabilities	$	—		$	371		$	452		$	823

	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 September 30, 2025 and December 31, 2024, there were cash equivalents of $217 million and $35 million included in cash and cash equivalents and $278 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 presented net with the corresponding derivative instrument fair values. See Note 7, Derivative Instruments, for further discussion of the 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 $485 million, $1 million and $(7) million, respectively, as of September 30, 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, at December 31, 2024.

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As of September 30, 2025 and December 31, 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 our Level 3 fair value measurements as of September 30, 2025 and December 31, 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
	September 30, 2025
	Fair Value,
	Net Asset		Valuation	Significant Unobservable
	(Liability)		Technique	Input	Range	Average
Power Contracts(1)	$	176	DCF	Market price (per MWh)	$2.79 - $329.17 / MWh	$63.66 / MWh
Power Congestion Products	$	35	DCF	Market price (per MWh)	($20.41) - $145.91 / MWh	$5.24 / MWh
Natural Gas Contracts	$	50	DCF	Market price (per MMBtu)	($1.83) - $15.43 / MMBtu	$2.03 / 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	)	DCF	Market price (per MWh)	$3.83 - $269.92/MWh	$63.78/ MWh
Power Congestion Products	$	32		DCF	Market price (per MWh)	$(26.03) - $125.37/MWh	$(3.20)/ MWh
Natural Gas Contracts	$	65		DCF	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.

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):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2025			2024			2025			2024
Balance, beginning of period	$	159		$	(13	)	$	32		$	150
Realized and mark-to-market gains (losses):
Included in net income:
Included in operating revenues		(23	)		40			167			(73	)
Included in fuel and purchased energy expense		26			8			23			33
Changes in collateral		(1	)		(20	)		(10	)		(20	)
Purchases and issuances:
Purchases		7			9			20			12
Issuances		(1	)		—			(1	)		—
Settlements		94			90			12			17
Transfers into and/or out of Level 3:(1)
Transfers into Level 3(2)		—			7			3			1
Transfers out of Level 3(3)		—			—			15			1
Balance, end of period	$	261		$	121		$	261		$	121
Change in unrealized gains (losses) included in net income relating to instruments still held at the end of the period	$	3		$	48		$	190		$	(40	)

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(1) 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 for the three months ended September 30, 2025 and 2024, respectively. There were no transfers into or out of Level 1 for the nine months ended September 30, 2025 and 2024, respectively.

(2) There were nil and $7 million in gains transferred out of Level 2 into Level 3 for the three months ended September 30, 2025 and 2024, respectively. There were $3 million and $1 million in gains transferred out of Level 2 into Level 3 for the nine months ended September 30, 2025 and 2024, respectively.

(3) There were nil and nil transferred out of Level 3 into Level 2 for the three months ended September 30, 2025 and 2024, respectively. There were $(15) million and $(1) million in losses transferred from Level 3 into Level 2 for the nine months ended September 30, 2025 and 2024, respectively.

7. 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 our market knowledge, all of which benefit our asset hedging activities. Trading results were not material for each of the three and nine months ended September 30, 2025 and 2024.

Interest Rate Instruments — A portion of our debt is indexed to base rates, currently primarily SOFR. 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.

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:

	Notional Amounts
Derivative Instruments	September 30, 2025			December 31, 2024			Unit of Measure
Power (MWh)		(329	)		(288	)	Million MWh
Natural gas (MMBtu)		1,427			1,536		Million MMBtu
Environmental credits (Tonnes)		17			25		Million Tonnes
Interest rate derivative instruments	$	4.8		$	5.8		Billion U.S. dollars

Certain of our derivative instruments contain credit risk-related contingent provisions that require maintaining collateral balances consistent with the Company's credit ratings. If our 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 September 30, 2025 was $185 million, for which we have posted collateral of $54 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 $22 million of additional collateral would be required and that no counterparty could request immediate, full settlement.

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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 Condensed 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 our derivatives are presented in the same category as the item being hedged (or economically hedged) within operating activities in the Consolidated Condensed 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 our 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 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 with 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. At September 30, 2025, approximately $474 million in commodity 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. 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 and are separately stated in the Consolidated Condensed 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 Condensed Balance Sheets

Fair value amounts are offset, which are associated with our derivative instruments and related cash collateral and margin deposits on the Consolidated Condensed 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 our derivative instruments is posted and/or received which may also be subject to a master netting arrangement with the same counterparty.

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The following tables present the fair values of our derivative instruments and the net exposure after offsetting amounts subject to a master netting arrangement with the same counterparty to our derivative instruments recorded on the Consolidated Condensed Balance Sheets by location and hedge type (in millions):

	September 30, 2025
	Gross Amounts of Assets and (Liabilities)			Gross Amounts Offset on the Consolidated Condensed Balance Sheets			Net Amount Presented on the Consolidated Condensed Balance Sheets(1)
Derivative assets:
Commodity exchange-traded derivatives contracts	$	1,152		$	(1,152	)	$	—
Commodity forward contracts		528			(177	)		351
Interest rate derivative instruments		80			—			80
Total current derivative assets(2)		1,760			(1,329	)		431
Commodity exchange-traded derivatives contracts		645			(645	)		—
Commodity forward contracts		636			(151	)		485
Interest rate derivative instruments		45			—			45
Total long-term derivative assets(2)		1,326			(796	)		530
Total derivative assets	$	3,086		$	(2,125	)	$	961
Derivative (liabilities):
Commodity exchange-traded derivatives contracts	$	(1,279	)	$	1,279		$	—
Commodity forward contracts		(509	)		173			(336	)
Interest rate derivative instruments		(3	)		—			(3	)
Total current derivative (liabilities)(2)		(1,791	)		1,452			(339	)
Commodity exchange-traded derivatives contracts		(1,003	)		1,003			—
Commodity forward contracts		(623	)		149			(474	)
Interest rate derivative instruments		(10	)		—			(10	)
Total long-term derivative (liabilities)(2)		(1,636	)		1,152			(484	)
Total derivative (liabilities)		(3,427	)		2,604			(823	)
Net derivative (liabilities) assets	$	(341	)	$	479		$	138

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	December 31, 2024
	Gross Amounts of Assets and (Liabilities)			Gross Amounts Offset on the Consolidated Condensed Balance Sheets			Net Amount Presented on the Consolidated Condensed Balance Sheets(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 (liabilities)	$	450		$	(16	)	$	434

(1) As of September 30, 2025 and December 31, 2024, there were $(67) million and $(87) million, respectively, of collateral under master netting arrangements that were not offset against our derivative instruments in the Consolidated Condensed Balance Sheets primarily related to initial margin requirements.

(2) As of September 30, 2025, current and long-term derivative assets are shown net of collateral of $(35) million and $(57) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $157 million and $414 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.

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The following tables present the fair values of our derivative assets and liabilities recorded in the Consolidated Condensed Balance Sheets (in millions):

	September 30, 2025				December 31, 2024
	Fair Value		Fair Value		Fair Value		Fair Value
	of Derivative		of Derivative		of Derivative		of Derivative
	Assets		Liabilities		Assets		Liabilities
Derivatives designated as cash flow hedging instruments:
Commodity hedging instruments	$	—	$	—	$	19	$	166
Interest rate hedging instruments		125		13		257		10
Total derivatives designated as cash flow hedging instruments		125		13		276		176
Derivatives not designated as hedging instruments:
Commodity derivative instruments		836		810		862		528
Total derivatives not designated as hedging instruments		836		810		862		528
Total derivatives	$	961	$	823	$	1,138	$	704

Derivatives Included in the Consolidated Condensed 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 Condensed Statements of Operations as a component of mark-to-market activity within our earnings.

The following tables detail the components of our total activity for both the net realized gain (loss) and the net mark-to-market (loss) gain recognized from our derivative instruments in earnings and where these components were recorded in the Consolidated Condensed Statements of Operations for the periods indicated (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2025			2024			2025			2024
Realized gain (loss)(1)(2)(4)
Commodity derivative instruments	$	46		$	(63	)	$	77		$	(85	)
Interest rate derivative instruments		—			—			—			4
Total realized gain (loss)		46			(63	)		77			(81	)
Mark-to-market (loss) gain(3)(4)
Commodity derivative instruments		(135	)		199			(419	)		137
Interest rate derivative instruments		(11	)		(12	)		(34	)		(18	)
Total mark-to-market (loss) gain		(146	)		187			(453	)		119
Total activity, net	$	(100	)	$	124		$	(376	)	$	38

(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 (loss) gain 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.

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2025			2024			2025			2024
Realized and mark-to-market (loss) gain(1)
Derivatives contracts included in operating revenues(2)(3)(4)	$	(98	)	$	350		$	(202	)	$	508
Derivatives contracts included in fuel and purchased energy expense(2)(3)(4)		9			(214	)		(140	)		(456	)
Interest rate derivative instruments included in interest expense(4)		(11	)		(12	)		(34	)		(14	)
Total activity, net	$	(100	)	$	124		$	(376	)	$	38

(1) In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market (loss) gain 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						(Loss) Gain Reclassified from AOCI into Income(2)
	Three Months Ended September 30,						Three Months Ended September 30,						Affected Line Item on the Consolidated Condensed
	2025			2024			2025			2024			Statements of Operations
Interest rate hedging instruments	$	(12	)	$	(147	)	$	12		$	36		Interest expense
Commodity hedging instruments		(11	)		429			(84	)		(159	)	Commodity revenue
Commodity hedging instruments		(34	)		(7	)		(32	)		(43	)	Commodity expense
Total(1)	$	(57	)	$	275		$	(104	)	$	(166	)

	(Loss) Gain Recognized in OCI						Gain (Loss) Reclassified from AOCI into Income(2)
	Nine Months Ended September 30,						Nine Months Ended September 30,						Affected Line Item on the Consolidated Condensed
	2025			2024			2025			2024			Statements of Operations
Interest rate hedging instruments	$	(102	)	$	(126	)	$	48		$	114		Interest expense
Interest rate hedging instruments		1			—			(1	)		—		Depreciation and amortization expense
Commodity hedging instruments		(341	)		240			(17	)		(56	)	Commodity revenue
Commodity hedging instruments		61			128			(15	)		(255	)	Commodity expense
Total(1)	$	(381	)	$	242		$	15		$	(197	)

(1) We recorded income tax benefit (expense) of $14 million and $(70) million for the three months ended September 30, 2025 and 2024, respectively, and income tax benefit (expense) of $95 million and $(61) million for the nine months ended September 30, 2025 and 2024, respectively.

(2) Cumulative net cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $372 million and $86 million as of September 30, 2025 and December 31, 2024, respectively.

As of September 30, 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. Note that 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 $35 million in net gains will be reclassified from AOCI into interest expense, $(208) million in net losses will be reclassified from AOCI into commodity revenue, and $34 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.

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8. 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 our 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):

	September 30, 2025		December 31, 2024
Margin deposits(1)	$	577	$	223
Natural gas and power prepayments		51		37
Total margin deposits and natural gas and power prepayments with our counterparties(2)	$	628	$	260
Letters of credit issued	$	2,036	$	1,855
First priority liens under power and natural gas agreements		438		350
Total letters of credit and first priority liens with our counterparties	$	2,474	$	2,205
Margin deposits posted with us by our counterparties(1)(3)	$	165	$	327
Letters of credit posted with us by our counterparties		211		128
Total margin deposits and letters of credit posted with us by our counterparties	$	376	$	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 7, Derivative Instruments, for further discussion of derivative instruments subject to master netting arrangements.

(2) As of September 30, 2025 and December 31, 2024, $556 million and $175 million, respectively, amounts were included in current and long-term derivative assets and liabilities, $65 million and $78 million, respectively, were included in margin deposits and other prepaid expense and $7 million and $7 million, respectively, were included in other long-term assets in the Consolidated Condensed Balance Sheets.

(3) As of September 30, 2025 and December 31, 2024, $77 million and $192 million, respectively, amounts were included in current and long-term derivative assets and liabilities, $88 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 Condensed 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.

9. Income Taxes

Income Tax Expense

The table below shows the consolidated income tax expense and the effective tax rates for the periods indicated (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2025			2024			2025			2024
Income tax expense	$	162		$	260		$	325		$	439
Effective tax rate		24	%		22	%		26	%		23	%

For interim tax reporting, an annual effective tax rate is estimated which is applied to the year-to-date ordinary income. Tax effects of significant unusual or infrequently occurring items are excluded from the estimated annual effective tax rate calculation and recognized in the interim period in which they occur. The effective income tax rates do not bear a customary relationship to statutory income tax rates, primarily as a result of the effect of income tax credits, valuation allowances and state income taxes. For the three and nine months ended September 30, 2025 and 2024, the income tax expense recognized resulted from the application of the interim period reporting rules to the results of operations.

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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 September 30, 2025, we estimate that, by the end of the year, we will have federal NOLs available to offset future income tax obligations recognized as deferred tax assets of $1.6 billion with no related valuation allowance. However, we continue to report a partial valuation allowance on state and foreign NOLs where we do not believe it is more likely than not that we will realize the value of the existing NOL balances. We also continue to report a full valuation allowance on federal and state 163(j) carryforward. Following the change in calculation of the 163(j) interest deduction limitation under the newly enacted OBBBA discussed below, we continue to assess the existing valuation allowance established in prior periods on our 163(j) carryforward. Valuation allowance will be released when it is more likely than not that we will be able to utilize the 163(j) carryforward in future periods. 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 a reduction or increase in our valuation allowance in future periods.

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, offering additional interim guidance on the corporate alternative minimum tax (“CAMT”). These notices indicate that the IRS plans to partially withdraw the previously proposed regulations and issue revised proposed regulations. Notice 2025-46 provides guidance consistent with the revised proposed regulations' intent, 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 affect Calpine include, but are not limited to, goodwill amortization under Section 197 and fair value adjustments for FSI purposes. We are currently evaluating how these guidance items could impact our CAMT, and consequently, 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 nine months ended September 30, 2025, the Company has received approximately $52 million of investment tax credits. Year-to-date, Calpine sold $57 million investment tax credits for approximately $53 million, recognizing the discount loss on sale through Income Tax Expense and including it within our 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 Statements 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.

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Unrecognized Tax Benefits — As of September 30, 2025 and December 31, 2024, we have unrecognized tax benefits of $30 million and $25 million, respectively. We monitor and evaluate any changes in fact that could affect and/or modify our unrecognized tax benefit accrual. For the three and nine months ended September 30, 2025, our unrecognized tax benefits and accrued interest balance are $5 million and $6 million, respectively.

10. Commitments and Contingencies

Litigation

The Company is party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business. At the present time, Calpine does not expect that the outcome of any of these proceedings, individually or in the aggregate, will have a material adverse effect on the financial condition, results of operations or cash flows.

On a quarterly basis, the Company reviews litigation activities and determines if an unfavorable outcome is considered “remote,” “reasonably possible” or “probable” as defined by U.S. GAAP. Where the Company determines an unfavorable outcome is probable and is reasonably estimable, it accrues for potential litigation losses. The liability the Company may ultimately incur with respect to such litigation matters, in the event of a negative outcome, may be in excess of amounts currently accrued, if any; however, the Company does not expect that the reasonably possible outcome of these litigation matters would, individually or in the aggregate, have a material adverse effect on the financial condition, results of operations or cash flows. Where the Company determines an unfavorable outcome is not probable or reasonably estimable, it does not accrue for any potential litigation loss. 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, the Company gives no assurance that such litigation matters would, individually or in the aggregate, not have a material adverse effect on the 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 “Bellweather” 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 Bellweather 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, which has ordered full briefing on the merits.

The full impact of the remaining litigation on the Company's 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 their financial condition, results of operations or cash flows or that would significantly change operations.

Guarantees and Indemnifications

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 Company's total maximum exposure under 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 September 30, 2025, there are no material outstanding claims related to guarantee and indemnification obligations and the Company does not anticipate that it will be required to make any material payments under guarantee and indemnification obligations. There have been no material changes to guarantees and indemnifications from those disclosed in Note 16, Commitments and Contingencies of the 2024 Annual Report.

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11. 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:

Calpine Receivables — Under the Accounts Receivable Sales Program, as of September 30, 2025 and December 31, 2024, the Company had $491 million and $391 million, respectively, in trade accounts receivable outstanding that were sold to Calpine Receivables. As of September 30, 2025 and December 31, 2024, the Company had notes receivable from Calpine Receivables of $34 million and $75 million respectively, which were recorded in the Consolidated Condensed Balance Sheets. During the nine months ended September 30, 2025 and 2024, the Company sold an aggregate of $3.1 billion and $2.6 billion, respectively, in trade accounts receivable and recorded $3.1 billion and $2.6 billion, respectively, in proceeds. For a further discussion of the Accounts Receivable Sales Program and Calpine Receivables, see Note 7, Variable Interest Entities and Unconsolidated Investments and Note 17, Related Party Transactions in the 2024 Annual Report.

Lyondell — There is a ground lease agreement with Houston Refining LP (“Houston Refining”), a subsidiary of LyondellBasell Industries NV (“Lyondell”), for the Channel Energy Center (“Channel”) 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 services agreement. A certain entity that has a material ownership interest in Calpine also has an ownership interest in Lyondell, whereby that entity may significantly influence the management and operating policies of Lyondell.

The Company recorded $1 million and $15 million in operating revenues during the three months ended September 30, 2025 and 2024, respectively and $28 million and $42 million in operating revenues during the nine months ended September 30, 2025 and 2024, respectively, associated with the Lyondell contract. The Company recorded $1 million and $4 million in operating expenses during the three months ended September 30, 2025 and 2024, respectively and $4 million and $10 million in operating expenses during the nine months ended September 30, 2025 and 2024, respectively, associated with the Lyondell contract. As of September 30, 2025 and December 31, 2024, the related party receivable associated with the Lyondell contract was $1 million and $8 million, respectively. The related party payables associated with the Lyondell contracts was nil and immaterial as of September 30, 2025 and December 31, 2024.

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 three and nine months ended September 30, 2025.

Pasadena Performance Products — In October 2019, a certain Calpine subsidiary 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. A certain entity that 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 operation on December 28, 2023 resulting in the commencement of the steam contract. The Company recorded $8 million and $4 million in operating revenues during the three months ended September 30, 2025 and 2024, respectively and $22 million and $16 million in operating revenues during the nine months ended September 30, 2025 and 2024, respectively, for the sale of steam. The Company also recorded $5 million related to the successful completion of the construction of the interconnection from the chemical facility to its power plant during the nine months ended September 30, 2024. As of September 30, 2025 and December 31, 2024, the related party receivables and payables associated with the Pasadena Performance Products contracts were immaterial.

Gregory Power Holdings, LLC — During the nine months ended September 30, 2025 and 2024, the Company made cash contributions of $70 million and $6 million, respectively, to Gregory Power Holdings, LLC as further discussed in Note 4, Variable Interest Entities and Investments. Additionally, the revenues recognized for providing management services to Gregory Power Holdings, LLC during the three and nine months ended September 30, 2025 and 2024 were immaterial. As of September 30, 2025, the related party receivables and payables associated with Gregory Power Holdings, LLC were immaterial and nil, respectively. As of December 31, 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 our business. These contracts primarily relate to the sale or purchase of commodities and capacity for varying tenors. For the three months ended September 30, 2025 and 2024, $10 million and $5 million, respectively, in operating expenses were recorded associated with these related party transactions. For the nine months ended September 30, 2025 and 2024, $28 million and $14 million, respectively, in operating expenses were recorded associated with these related party transactions. Additionally, the Company purchased RECs of $3 million and $3 million, respectively for the three months ended September 30, 2025 and 2024 and $17 million and $13 million, respectively during the nine months ended September 30, 2025 and 2024. The Company has also entered into a long-term land lease agreement with a related party. The operating revenues recognized related to this related party transaction during the three and nine months ended September 30, 2025 and 2024 were immaterial. As of September 30, 2025 and December 31, 2024, the related party receivables and payables associated with these transactions were immaterial.

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12.          Capital Structure

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 $.001 per share. As of September 30, 2025, the Company's authorized common stock consists of 1.8 million 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 $.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 $.001 per share. During the nine months ended September 30, 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 September 30, 2025 and December 31, 2024, respectively. There were no changes to the number of issued and outstanding Class A common shares during the nine months ended September 30, 2025 which totaled 952,153 at September 30, 2025 and December 31, 2024. There were no issued and outstanding Class C common shares at September 30, 2025 and December 31, 2024.

13.          Stock-Based Compensation

Equity-based compensation agreement – Class B common shares of Calpine Corporation

Calpine Corporation issued 47,847 of Class B common shares in 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 nine months ended September 30, 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 September 30, 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 September 30, 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 equity-based awards to members of management and accordingly stock-based compensation expense was recognized over the period in which the related employee services were provided. The Company recognized an immaterial amount of compensation expense in the Consolidated Condensed Financial Statements during the three and nine months ended September 30, 2025 and 2024. There were no cash payments made associated with the Class B common shares during the three and nine months ended September 30, 2025 or 2024.

14.           Segment 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 September 30, 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, primarily 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):

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	Three Months Ended September 30, 2025
	Wholesale											Consolidation
	West		Texas			East			Retail			Elimination			Total
Operating revenues:
Commodity revenue	$	1,153	$	1,062		$	735		$	1,468		$	(659	)	$	3,759
Mark-to-market gain (loss)		88		(255	)		1			61			(79	)		(184	)
Other revenue		5		45			7			—			(15	)		42
Operating revenues		1,246		852			743			1,529			(753	)		3,617
Operating expenses:
Fuel and purchased energy expense:
Commodity expense		566		621			448			1,249			(659	)		2,225
Mark-to-market loss (gain)		5		(24	)		(10	)		60			(80	)		(49	)
Fuel and purchased energy expense		571		597			438			1,309			(739	)		2,176
Operating and maintenance expense associated with margin generation activities		125		87			87			55			—			354
Depreciation and amortization expense associated with margin generation activities		84		55			47			11			—			197
Gross margin		466		113			171			154			(14	)		890
Operating and maintenance expense associated with general corporate cost		3		3			3			6			(15	)		—
Depreciation and amortization expense associated with general corporate cost		—		—			—			—			6			6
General and other administrative expense		9		17			13			3			1			43
Other operating expenses		29		69			22			1			1			122
(Gain) loss on sale of assets, net		—		(128	)		1			—			—			(127	)
Loss (income) from unconsolidated subsidiaries		—		3			—			(7	)		—			(4	)
Income (loss) from operations		425		149			132			151			(7	)		850
Interest expense		55		59			47			—			(1	)		160
Other expense, net		2		(2	)		2			19			—			21
Income (loss) before income taxes		368		92			83			132			(6	)		669
Income tax expense (benefit)		38		77			48			(1	)		—			162
Net income (loss)	$	330	$	15		$	35		$	133		$	(6	)	$	507

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	Three Months Ended September 30, 2024
	Wholesale										Consolidation
	West		Texas			East			Retail		Elimination			Total
Operating revenues:
Commodity revenue	$	1,273	$	1,013		$	677		$	1,313	$	(666	)	$	3,610
Mark-to-market gain (loss)		150		177			(110	)		249		(161	)		305
Other revenue		8		9			6			—		(18	)		5
Operating revenues		1,431		1,199			573			1,562		(845	)		3,920
Operating expenses:
Fuel and purchased energy expense:
Commodity expense		548		555			331			1,099		(666	)		1,867
Mark-to-market loss (gain)		41		(7	)		42			191		(161	)		106
Fuel and purchased energy expense		589		548			373			1,290		(827	)		1,973
Operating and maintenance expense associated with margin generation activities		121		78			82			55		—			336
Depreciation and amortization expense associated with margin generation activities		75		50			53			9		—			187
Gross margin		646		523			65			208		(18	)		1,424
Operating and maintenance expense associated with general corporate cost		5		5			3			3		(16	)		—
Depreciation and amortization expense associated with general corporate cost		—		—			—			—		6			6
General and other administrative expense		14		16			12			4		—			46
Other operating expenses		12		5			2			1		1			21
Loss on sale of assets, net		—		13			—			—		—			13
Loss from unconsolidated subsidiaries		—		—			—			2		—			2
Income from operations		615		484			48			198		(9	)		1,336
Interest expense		63		51			40			1		(1	)		154
Loss on extinguishment of debt		1		4			3			—		—			8
Other expense, net		2		(6	)		(4	)		12		1			5
Income before income taxes		549		435			9			185		(9	)		1,169
Income tax expense		83		111			65			1		—			260
Net income (loss)	$	466	$	324		$	(56	)	$	184	$	(9	)	$	909

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	Nine Months Ended September 30, 2025
	Wholesale												Consolidation
	West			Texas			East			Retail			Elimination			Total
Operating revenues:
Commodity revenue	$	2,828		$	3,026		$	2,118		$	3,978		$	(1,822	)	$	10,128
Mark-to-market (loss) gain		(164	)		(357	)		(4	)		239			(24	)		(310	)
Other revenue		14			71			20			—			(50	)		55
Operating revenues		2,678			2,740			2,134			4,217			(1,896	)		9,873
Operating expenses:
Fuel and purchased energy expense:
Commodity expense		1,410			1,858			1,339			3,333			(1,822	)		6,118
Mark-to-market loss (gain)		73			(22	)		59			24			(25)			109
Fuel and purchased energy expense		1,483			1,836			1,398			3,357			(1,847	)		6,227
Operating and maintenance expense associated with margin generation activities		384			273			252			154			—			1,063
Depreciation and amortization expense associated with margin generation activities		241			168			154			27			—			590
Gross margin		570			463			330			679			(49	)		1,993
Operating and maintenance expense associated with general corporate cost		10			13			9			20			(52	)		—
Depreciation and amortization expense associated with general corporate cost		—			—			—			—			21			21
General and other administrative expense		21			53			35			11			1			121
Other operating expenses		48			96			36			5			1			186
(Gain) loss on sale of assets, net		—			(128	)		1			—			—			(127	)
Loss (income) from unconsolidated subsidiaries		—			8			—			(18	)		—			(10	)
Income (loss) from operations		491			421			249			661			(20	)		1,802
Interest expense		140			191			144			2			(3	)		474
Other expense, net		1			1			1			50			2			55
Income (loss) before income taxes		350			229			104			609			(19	)		1,273
Income tax expense		62			156			107			—			—			325
Net income (loss)	$	288		$	73		$	(3	)	$	609		$	(19	)	$	948

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	Nine Months Ended September 30, 2024
	Wholesale											Consolidation
	West		Texas			East			Retail			Elimination			Total
Operating revenues:
Commodity revenue	$	3,008	$	2,608		$	2,041		$	3,464		$	(1,781	)	$	9,340
Mark-to-market gain (loss)		221		129			(181	)		(10	)		8			167
Other revenue		25		39			51			—			(52	)		63
Operating revenues		3,254		2,776			1,911			3,454			(1,825	)		9,570
Operating expenses:
Fuel and purchased energy expense:
Commodity expense		1,449		1,648			1,108			2,923			(1,781	)		5,347
Mark-to-market loss (gain)		75		2			(49	)		(5	)		7			30
Fuel and purchased energy expense		1,524		1,650			1,059			2,918			(1,774	)		5,377
Operating and maintenance expense associated with margin generation activities		364		258			281			144			—			1,047
Depreciation and amortization expense associated with margin generation activities		215		150			157			27			—			549
Gross margin		1,151		718			414			365			(51	)		2,597
Operating and maintenance expense associated with general corporate cost		12		13			9			17			(51	)		—
Depreciation and amortization expense associated with general corporate cost		—		—			—			—			19			19
General and other administrative expense		31		46			32			12			—			121
Other operating expenses		40		14			5			4			—			63
Loss on sale of assets, net		—		13			—			—			—			13
Loss from unconsolidated subsidiaries		—		—			—			6			—			6
Income from operations		1,068		632			368			326			(19	)		2,375
Interest expense		152		155			120			2			(3	)		426
Loss on extinguishment of debt		9		18			11			—			—			38
Other expense, net		3		(9	)		(5	)		31			3			23
Income before income taxes		904		468			242			293			(19	)		1,888
Income tax expense		131		191			116			1			—			439
Net income	$	773	$	277		$	126		$	292		$	(19	)	$	1,449

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15.          Subsequent Events

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. On October 27, 2025 we completed a first draw on the facility for approximately $203 million.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Information

This Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the accompanying Consolidated Condensed Financial Statements and accompanying notes thereto and the Company’s Annual Report for the year ended December 31, 2024. See the cautionary statement regarding forward-looking statements at the beginning of this Report for a description of important factors that could cause actual results to differ from expected results.

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 and operate approximately 28 Gigawatts (“GW”) of power facilities, enough to power approximately 27 million homes, consisting of natural gas, geothermal, solar and battery storage assets. Our Company employs approximately 2,500 people.

Proposed Merger

On January 10, 2025, the Company announced that it entered into an Agreement and Plan of Merger (the “Plan of Merger Agreement”) with Constellation Energy Corporation (“Constellation”). The Plan of Merger Agreement provides for a series of Reorganization-related transactions on terms set forth in the Plan of Merger Agreement. As a result of the Reorganization and Merger, Calpine will become an indirect, wholly-owned subsidiary of Constellation. Subject to the terms and conditions of the Plan of Merger Agreement, Constellation will acquire Calpine in a cash and stock transaction valued at an equity purchase price of approximately $16.4 billion at date of signing, composed of 50 million shares of Constellation stock and $4.5 billion in cash plus the assumption of approximately $12.7 billion of Calpine net debt. After accounting for cash that is expected to be generated by Calpine between signing and the expected closing date, as well as the value of tax attributes at Calpine, the net purchase price is $26.6 billion. See Note 19, Subsequent Events and Item 1A. Risk Factors of the 2024 Annual Report for additional details relating to the Plan of Merger Agreement.

Pursuant to the Merger Agreement, on June 10, 2025, the Company amended and restated its Fifth Amended and Restated Certificate of Incorporation (the “Company A&R Charter”), following requisite stockholder Board of Directors approval, to, among other matters, create and authorize a new class of non-voting common stock denominated as Class C Common Stock, which will facilitate the Reorganization contemplated by the Plan of Merger Agreement. The issuance of such stock will only occur as part of the Reorganization-related transactions set forth in the Plan of Merger Agreement.

On January 24, 2025, Constellation and the Company (together, “Applicants”) filed a joint application with FERC under Section 203 of the Federal Power Act requesting authorization for Constellation to acquire Calpine. As part of the FERC filing, Applicants propose to divest 3,550 MW of combined cycle generation in PJM to address potential market power concerns related to the transaction. The plants to be divested are: Bethlehem Energy Center, York Energy Center Unit 1, Hay Road Energy Center and Edge Moor Energy Center. On July 23, 2025, FERC issued an order conditionally approving the Constellation/Calpine merger transaction, subject to the consummation of the Applicants' proposed divestiture plan and adherence to certain mitigation measures agreed upon with the PJM market monitor. The Department of Justice review of the merger transaction remains ongoing.

Business and Strategy

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

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

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

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

Reportable Segments

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

· 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; and

· Retail: Includes our retail operations throughout the country.

Inclusive of our power generation portfolio and our retail sales platforms, we serve customers in 21 states in the U.S. and in Canada. See Note 14, Segment Information, to the Consolidated Condensed Financial Statements included herein, for a discussion of financial information by reportable segment and geographic area and significant customer information for the three and nine months ended September 30, 2025 and 2024.

Our Core Business Functions

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

Our Markets

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

CAISO

CAISO covers customers primarily in California, managing the dispatch of installed capacity to 32 million customers. Approximately 7.3 GW, or 26% of our generation fleet as measured by net interest with peaking, operates within CAISO as of September 30, 2025. Our portfolio within CAISO is 10% geothermal, 79% natural gas-fired and 11% storage. Operating as a fully functioning ISO since 1998, CAISO is a competitive wholesale electricity market with day-ahead and real-time energy markets, ancillary services and congestion revenue rights. The CAISO also operates a real-time imbalance market across much of the West. Although CAISO does not operate a centralized capacity market, it does prescribe mandatory resource requirements supported through bilateral contracts in its Resource Adequacy (“RA”) program.

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ERCOT

ERCOT coordinates the movement of electricity to 27 million customers in Texas. Approximately 9.8 GW, or 35% of our generation fleet, as measured by net interest with peaking, operates within ERCOT as of September 30, 2025. Our portfolio in ERCOT is comprised entirely of natural gas generation. ERCOT is a competitive electricity market that manages approximately 90% of Texas’ load and an electric grid covering approximately 75% of the state. ERCOT oversees transactions associated with Texas’ competitive wholesale and retail power markets and does not operate a capacity market.

PJM

PJM serves a population of 65 million in all or parts of 13 states and the District of Columbia. Approximately 5.3 GW, or 19% of our generation fleet, as measured by net interest with peaking, operates within PJM as of September 30, 2025. Our portfolio within PJM is 86% gas-fired generation and 14% steam as of September 30, 2025. All of our gas-fired generation facilities in PJM are dual-fuel systems that can also run on oil. This enables our fleet to continue operating during periods when gas may be constrained, such as recent winter storms. PJM is a competitive wholesale electricity market that consists of a locationally based energy market, a forward capacity market and ancillary service markets.

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

ISO-NE

ISO-NE manages installed capacity across six states — Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont. Approximately 2.0 GW, or 7% of our generation fleet, as measured by net interest with peaking, operates within ISO-NE as of September 30, 2025. ISO-NE is a competitive wholesale electricity market with broad authority over the day-day operation of the transmission system. ISO-NE operates a day-ahead and real-time wholesale energy market, a forward capacity market and an ancillary services market.

Other Markets

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

Further discussions on our power plants are included in the sections titled Power Plant Operational Excellence — Description of our Operations — Table of Operating Power Plants, Battery Storage Facilities and Projects Under Construction.” within Part I, Item 1. Business of the 2024 Annual Report.

Significant Events

The following significant events occurred during 2025, as further described within this Management’s Discussion and Analysis and the Consolidated Condensed Financial Statements and accompanying Notes thereto included herein:

2025

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.

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 three and nine months ended September 30, 2025.

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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.

2024

For significant events which occurred during 2024, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Significant Events of the 2024 Consolidated Financial Statements for the 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 $491 billion in power sales in the United States in 2023. Despite its centrality to the economy, United States power demand has been relatively flat for the past 20 years, growing at a low compounded annual growth rate. However, power demand in the United States is now expected to increase rapidly. This expected increase in power demand can be attributed primarily to three independent factors:

· 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 $480 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.

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

Key Operating Metrics

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

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

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

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

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

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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 tables present the operational performance of our retail and generation segments for the three and nine months ended September 30, 2025 and 2024.

	Three Months Ended September 30,
	West						Texas						East							Retail
	2025			2024			2025			2024				2025			2024			2025		2024
Production Volumes:
(MWh in thousands)
MWh Generated(1)		9,694			10,000			16,130			15,918				11,772			11,461			n/a		n/a
Average Total MW in Operations(1)		8,464			8,250			9,750			9,139				9,763			9,713			n/a		n/a
Availability, Heat Rate, & Capacity Factor:
Average Availability		95.2	%		97.0	%		94.2	%		94.3	%			92.9	%		93.4	%		n/a		n/a
Average Capacity Factor, excluding peakers and Geysers		55.0	%		57.4	%		74.9	%		78.2	%			63.4	%		63.3	%		n/a		n/a
Steam Adjusted Heat Factor (Btu/ KWh)		7,276			7,345			7,401			7,301				7,645			7,658			n/a		n/a
Retail Sales Volumes
(MW)
Average Commercial and Industrial																					6,416		6,319
Average Residential Sales																					432		471
Average Total Retail Electric Sales																					6,848		6,790

	Nine Months Ended September 30,
	West						Texas						East						Retail
	2025			2024			2025			2024			2025			2024			2025		2024
Production Volumes:
(MWh in thousands)
MWh Generated(1)		21,014			23,562			40,511			39,759			29,574			29,443			n/a		n/a
Average Total MW in Operations(1)		8,409			7,909			9,721			9,083			9,751			9,791			n/a		n/a
Availability, Heat Rate, & Capacity Factor:
Average Availability		83.4	%		87.1	%		87.9	%		86.2	%		88.2	%		89.2	%		n/a		n/a
Average Capacity Factor, excluding peakers and Geysers		40.5	%		47.8	%		63.6	%		66.3	%		54.3	%		54.7	%		n/a		n/a
Steam Adjusted Heat Factor (Btu/ KWh)		7,340			7,385			7,413			7,322			7,643			7,602			n/a		n/a
Retail Sales Volumes
(MW)
Average Commercial and Industrial																				6,222		5,982
Average Residential Sales																				341		348
Average Total Retail Electric Sales																				6,563		6,330

(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.

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Market Pricing

	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Average Market On-Peak Power Prices ($/MWh)(1):
CAISO NP 15	$	41.18	$	44.83	$	34.78	$	38.88
ERCOT Houston	$	42.55	$	33.98	$	40.97	$	37.34
ERCOT North	$	41.00	$	33.54	$	38.02	$	35.33
PJM West Hub	$	61.48	$	49.70	$	58.13	$	41.07
ISO-NE	$	62.77	$	45.87	$	72.48	$	42.62
Natural Gas Prices ($/MMBtu)(2):
NYMEX Henry Hub	$	4.51	$	2.08	$	4.28	$	2.18
PG&E Citygate	$	3.48	$	2.79	$	3.33	$	2.96
Houston Ship Channel	$	2.69	$	1.80	$	2.96	$	1.79
TETCOM 3	$	2.26	$	1.50	$	3.70	$	1.97
Algonquin Citygate	$	2.95	$	1.75	$	5.91	$	2.56
Carbon Prices ($/Ton)(2):
AB32 Posted Price	$	29.11	$	34.86	$	29.52	$	38.67
Average Annual Market Spark Spread ($/MWh)(3):
CAISO NP 15 to PG&E Citygate Spark Spread	$	5.93	$	12.24	$	0.38	$	3.67
ERCOT Houston to Houston Ship Channel Spark	$	23.72	$	21.41	$	20.27	$	24.81
ERCOT North to Houston Ship Channel Spark	$	22.17	$	20.97	$	17.32	$	22.80
PJM West Hub to Tetco M 3 Spark Spread	$	42.25	$	36.93	$	26.66	$	24.34
ISO-NE to Algonquin Spark Spread	$	42.15	$	33.61	$	31.13	$	24.72

(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 excludes the effect of carbon costs given different state participation in each program.

Governmental and Regulatory Matters

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

Federal

Since President Trump took office on January 20, 2025, the Trump Administration has issued a series of Executive Orders, directives and agency memoranda generally intended to pause and review Biden-era programs and spending (to include renewable energy and environmental programs, as well as diversity, inclusion and equity initiatives); reshape the federal government and workforce; and advance new priorities, to include supporting traditional energy exploration and production and ensuring AI dominance. For example, in a “day one” Executive Order, the Trump Administration paused the disbursement of IRA and Infrastructure Investment and Jobs Act (“IIJA”) funding, subject to future review and approval. In later Executive Orders, among other actions, President Trump has: directed federal agencies to repeal, revise or sunset regulations that are deemed to be unconstitutional or otherwise unlawful, including regulations promulgated by FERC and EPA; directed the U.S. Attorney General to take swift action to stop the enforcement of state laws deemed to be contrary to the Administration’s energy dominance agenda, including laws addressing climate change or imposing carbon Cap-and-trade programs, specifically calling out California’s AB32 cap-and-trade program; directed the Secretary of Energy and the National Energy Dominance Council to identify and retain, through emergency powers, generation resources deemed to be critical to grid reliability and to take other measures protective of the coal generation fleet; and directed independent agencies to include FERC, CFTC, NRC and similarly structured agencies to, among other things, coordinate with the White House on legal and policy matters. The Trump Administration also has imposed new tariffs and announced its intent to impose additional new tariffs, creating a shifting landscape for trade that could affect Calpine’s businesses.

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In recent months, following these directives, the Department of Energy has issued orders pursuant to FPA Section 202(c) to forestall the planned retirement, for at least 90 days (subject to extension), of several power generation facilities, including facilities in MISO and PJM. The extent to which DOE will issue additional 202(c) orders, and the rules surrounding such units’ market participation, are unclear; hence we cannot predict how these actions will impact on the markets in which Calpine operates. The Department of Energy also has sent letters terminating grant funding for several energy projects, including Calpine’s Baytown and Sutter carbon capture demonstrations projects. Such terminations are subject to review through an ongoing administrative appeal process, the outcome of which Calpine cannot predict and which remains ongoing.

In June 2025 the EPA issued for public comment a proposal to repeal, either in whole or in part, the Biden-era GHG Rules, and to repeal certain Biden-era amendments to Mercury and Air Toxics Standards. Subsequently, in July 2025, the EPA proposed to repeal the 2009 “endangerment finding”, which is a scientific and legal determination that greenhouse gas emissions pose risks to public health and welfare, a move that, if finalized, would strip the EPA of its legal authority to regulate GHG’s under the Clean Air Act. In addition, in September 2025, the EPA proposal to repeal the “Greenhouse Gas Reporting Program” eliminating reporting requirements for most entities that were previously covered by the program. Any finalized changes to these and other environmental regulations EPA administers could impact Calpine’s current fleet, our development projects and the power generation sector and power markets more broadly. Calpine is monitoring these developments and expects significant and protracted legal challenges in this area.

There remains significant uncertainty regarding how DOE, EPA and other federal agencies will continue to carry out the various Presidential directives and Executive Orders. We are evaluating the impacts of the Executive Orders and other presidential directives to Calpine’s businesses and to the competitive markets in which we operate.

President Trump signed into law on July 4, 2025, the OBBBA. Among other things, the OBBBA makes the tax provisions of the TCJA permanent. The OBBBA also includes, but is not limited to, the permanent extension of full bonus depreciation for capital projects achieving commercial operations on or after January 19, 2025; modification of the interest deduction limitation calculation as provided for in IRC 163j; and reinstating full expensing of R&D costs. The OBBBA also alters the energy tax credit provisions included within the Inflation Reduction Act of 2022 (“IRA”), which underpin elements of our current development growth programs. Among other things, the OBBBA preserves the IRA’s expanded 45Q tax credits, which benefit Calpine’s efforts to commercialize CCS for natural gas power generation; maintains technology-neutral tax credits for geothermal and certain other non-solar and non-wind investments; and adds new provisions related to certain “Foreign Entities of Concern” that limit the availability of tax credits in some circumstances. As of this writing, we cannot predict the ultimate impact of these legislative changes to our businesses, nor can we predict the outcome of any agency rulemaking to implement these provisions or future legislative changes to these provisions as they relate to Calpine; however, we do not expect any impact on our recently completed projects or projects already under construction. To the extent these energy tax credit provisions stay in place in whole or in part in the future, they could influence Calpine’s project development posture, the power markets in which Calpine operates and development opportunities.

Texas

ERCOT

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

Several bills were passed in the 2023 and 2025 Texas Legislative sessions that will impact the competitive wholesale electricity market in Texas, and implementation work is ongoing. House Bill 1500, which emanated from the 2023 legislative session, requires ERCOT to create a new ancillary service called Dispatchable Reliability Reserve Service (“DRRS”) for dispatchable resources to provide flexibility to address intra-hour operational challenges. ERCOT is designing the DRRS to potentially provide additional revenues to firm, dispatchable generation resources; however, implementation is not expected until late 2026 or 2027 at the earliest. Additionally, House Bill 1500 instructed the Commission to implement rules for capacity installed after January 1, 2027, to be subject to firming requirements including penalties for non-compliance. ERCOT and the PUCT are currently working on implementing DRRS and firming requirements. Both changes are favorable for Calpine’s fleet.

In November 2023, Texas voters approved a state constitutional amendment to create the Texas Energy Fund (“TEF”), which will provide up to $7.2 billion for 3% loans and completion bonuses for a maximum of 10 GW of new dispatchable generation in Texas. Project selections were announced in Fall 2024, including Calpine's 460 MW Pin Oak Creek peaking facility. Calpine successfully closed on the loan agreement with the TEF on October 14.

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In 2025 the Texas Legislature passed Senate Bill 6 which impacts how large electricity consumers with a peak capacity greater than 75 MW connect to the ERCOT grid. The bill addresses the oversight of these large energy users during emergencies and includes additional approval requirements for large loads that may collocate with existing generation, with some exceptions. SB6 also requires the PUCT to evaluate and update cost allocation rules to ensure these major consumers contribute to the costs of grid infrastructure upgrades needed to support their demands, while also supporting reliability and providing the state with more control during emergencies. Both the PUCT and ERCOT will be implementing rule changes through 2026 to conform to rules and protocols with the new law. Pending clarity about implementation details, we view Senate Bill 6 as supportive of further large load development in ERCOT.

ERCOT is also in a multi-year project to upgrade systems to optimize energy and ancillary services simultaneously. Market trials began in Spring 2025, with full implementation expected by December 5, 2025. At this point, in isolation, we would expect the RTC project to put downward pressure on market clearing prices. However, this may be potentially offset by uplift associated implementation of DRRS as noted above and market reforms associated with the PUCT review of the ERCOT reliability standard in 2026.

East

PJM

We have an extensive portfolio of generation in PJM, the majority of which will be divested as part of our acquisition by Constellation Energy.

PJM operates wholesale power markets including an energy market, a forward capacity market and ancillary service markets in all or parts of 13 states and the District of Columbia. PJM also performs transmission planning and operation for the region. The rules and regulations affecting PJM power markets and transmission are subject to change. For example, PJM is in the process of revising the demand curves that it uses in the capacity market and recently initiated consideration of a seasonal capacity market. Due to these continuing market rule revisions, it is difficult to assess the cumulative impact of all the changes on our portfolio, including the facilities planned for divestiture as part of the merger with Constellation.

In December 2024, Pennsylvania Governor Josh Shapiro filed a FERC complaint against PJM seeking to lower PJM’s capacity market price cap. The complaint drew support from the governors of Delaware, Illinois, Maryland, and New Jersey. In April 2025, FERC approved a settlement to resolve the complaint by implementing a price collar with an approximate $325/MW-day cap and $175/MW-day floor for the 2026-27 Base Residual Auction (BRA), which was held this past Spring, and 2027-28 BRA, which will be held in December, 2025. We cannot predict at this time whether the December 2025 auction would have otherwise cleared outside the FERC approved collar, so the impact on Calpine is unknown.

On April 14, 2025, a coalition of Consumer Advocates filed a complaint against PJM asserting that PJM's Base Residual Auction for the 2025/2026 Delivery Year produced unjust and unreasonable results. The complaint alleges that the auction omitted existing capacity, had non-price barriers to new entry, failed to mitigate supplier market power, and imposed inflated charges on customers without any reliability benefit. The Advocates are seeking a refund at just and reasonable replacement rates. We cannot at this time predict the outcome of this proceeding, which remains pending.

In addition, PJM is currently the subject of FERC proceedings to examine the adequacy of, and provide clarity regarding, the region’s rules governing co-located load arrangements for data centers and other large loads. FERC launched the proceeding after stakeholders filed at FERC a series of contested filings and complaints involving such arrangements. FERC has yet to act on these filings.

Relatedly, PJM recently initiated a process to address the interconnection of large loads such as data centers and their impact on the capacity market and other PJM markets. It is unclear what market rule changes may emerge from this process.

Illinois

In September 2021, Illinois Governor JB Pritzker signed into law the Climate and Equitable Jobs Act, which, among other things, establishes a schedule for eliminating CO2 emissions by EGUs. Under that schedule, privately owned natural gas units that exceed an established level of NOx and SOx emissions and are located within three miles of an environmental justice community, or an equity investment-eligible community must permanently eliminate CO2 emissions by January 1, 2030, subject to certain reliability exceptions. Left unchanged, this legislation will impact our Zion Energy Center and could require it to eliminate its CO2 emissions or shut down by January 2030.

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Pennsylvania

As previously reported, the Pennsylvania Department of Environmental Protection finalized its CO2 Budget Trading Program regulations in the fall of 2021, establishing Pennsylvania’s participation in the Regional Greenhouse Gas Initiative (“RGGI”). The Senate and House Republicans subsequently filed with the Commonwealth Court claims against the Environmental Quality Board (“EQB”) seeking to permanently block the promulgation of the RGGI regulations because the EQB does not have the authority to implement the regulations. The legislators also filed a Petition for Preliminary Injunction. A second complaint and Petition for Preliminary Injunction were filed on April 25, 2022, by various industry groups, including labor and coal interests. On July 8, 2022, the Commonwealth Court granted the Petitions for Preliminary Injunction and, as a result, the Pennsylvania RGGI regulations, including Calpine’s obligation to purchase allowances for CO2 emissions, were stayed. On November 1, 2023, the Commonwealth Court issued a decision granting the petitions for a permanent injunction, finding EQB’s regulations directing Pennsylvania to join RGGI are void and unenforceable. As a result of this decision, the EQB is barred from enforcing the Pennsylvania RGGI regulations. The EQB and non-governmental organizations appealed the Commonwealth Court’s decision to the Pennsylvania Supreme Court. Oral argument was held on May 13, 2025. We cannot predict at this time whether the Pennsylvania Supreme Court will grant the appeal or, if it does, whether the Commonwealth will continue the process of RGGI participation. While ultimate Pennsylvania participation in RGGI would not be positive for Calpine, we are unable to predict the ultimate effect on our financial condition, results of operations or cash flows.

Draft legislation was introduced in the PA House earlier this year to modify existing legislation to allow utilities to build and own generation. Similar legislation was introduced in the Senate this summer. Neither chamber has held hearings on the proposed bills and neither bill has much legislative support. While we cannot predict whether these bills will pass or will be signed by the Governor, legislation that results in utility ownership of generation would have a detrimental impact on competitive wholesale and retail electricity markets in the region.

New Jersey

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

In March, NJ Assemblyman Wayne DeAngelo introduced legislation, A5439, that is aimed at restructuring New Jersey's energy market in response to rising power prices. A key focus of this legislation is to allow utility companies like PSE&G to build their own power plants, a shift from the state's reliance on competitive electricity markets. A similar bill has been introduced in the New Jersey Senate. On June 30, the Assembly passed a bill requiring the NJ BPU to study alternatives to PJM’s capacity market or alternatives to PJM membership. The bill requires the BPU to work with neighboring states, to study and recommend collective action. A similar bill was introduced in the Senate on June 30. Also in June, the legislature passed a resolution directing the BPU to investigate PJM’s capacity market and directing New Jersey to collaborate with neighboring states to promote affordable energy practices, and to urge PJM to implement market reforms and expeditiously review new electricity generation applications. The resolution does not require action by the Governor. While we cannot predict whether any of these bills will ultimately pass or will be signed by the Governor, legislation that results in reinstated regulation utility ownership of generation would have a detrimental impact on competitive wholesale and retail electricity markets in the region.

ISO-NE

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

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

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NYISO

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

West

Our power plants and battery storage facilities in our West segment are primarily located in California, in the CAISO region. We also own one power plant in Arizona and one power plant in Oregon. The various wholesale markets in which our subsidiaries operate are subject to CAISO, CPUC and other rules, which are subject to regulatory change.

The CPUC addresses grid reliability through procurement mandates for almost 19 GW of new capacity (primarily storage). The CPUC is also considering new long-term “programmatic” procurement requirements for capacity and clean energy. It issued a revised proposal with multiple options for long-term capacity procurement requirements, one that would encompass new and existing capacity in the same requirement and another with separate requirements for new capacity, and a clean energy standard to address clean energy requirements. The proposal was not well received, and next steps are unclear. In addition, the CPUC recently authorized (but did not mandate) “central procurement” of 10.6 GW of long lead-time resources, including geothermal, offshore wind and long-duration storage, with on-line dates in the 2030s. This procurement provides additional development opportunities. On the other hand, the additional new capacity from the procurement is likely to depress energy and capacity prices for our existing assets.

The CPUC also administers a Resource Adequacy program, which requires load-serving entities to procure capacity through bilateral contracting. The CPUC recently adopted new rules that entail capacity requirements that vary by month and hour-of-day. The planning reserve margin for the program determines procurement requirements. CPUC recently approved a higher planning reserve margin and continues to consider even higher planning reserve margins. In addition, CAISO is considering changes to the aspects of the RA program it administers, including requirements to replace capacity on planned outages and availability incentives. Further, the CPUC and CAISO continue to express interest in derating the capacity that can be sold from gas generation and other dispatchable resources, including storage and geothermal, to reflect its historical forced outage performance.

In September 2025, California’s legislature passed two important pieces of legislation. The first is an extension of the state’s GHG cap-and-trade program (renamed “cap-and-invest”) through 2045, replacing its prior 2030 sunset. The program’s emissions cap will continue declining, and revenues created by sale of the allowances will be codified to guarantee funding for priorities like highs-peed rail, affordable housing, and community air protection. The second piece of important legislation is a bill that sets the stage for lifting the state’s moratorium on CO2 pipelines once new safety regulations are in place. The bill directs the Office of the State Fire Marshall to adopt CO2 pipeline rules, at least as stringent as pending federal standards, by April 2026. This change is helpful to our continued effort to develop CCS projects in California.

In October 2023, California Governor Gavin Newsom signed into law two state Senate Bills that collectively require certain public and private U.S. companies that perform certain business activities in California to disclose information related to their GHG emissions and climate-related financial risks. These laws could impact Calpine.

First, SB 253, the “Climate Corporate Data Accountability Act,” requires CARB to adopt regulations, which would require us to annually disclose our scope 1 and scope 2 emissions from the prior fiscal year beginning in 2026 and scope 3 emissions by 2027. The regulations promulgated by CARB also require various levels of assurance of the reported emissions over time for the different emission scopes. SB 253 would require us to publish emissions data on a public digital platform. Second, SB 261 would require us to (1)prepare a climate-related financial risk report following the Task Force on Climate-Related Financial Disclosures framework and (2)indicate the measures adopted to reduce and/or adapt to these risks on or before January 1, 2026, and to update the report every subsequent two years. The report must be made publicly available on our website.

Subsequently, in September 2024, SB 219 (Wiener, Statutes of 2024, Chapter 766) amended state law to extend the date for CARB to adopt the regulations specified in SB 253 from January 1, 2025, to July 1, 2025. To date, CARB has not yet promulgated final regulations pursuant to SB 253 and SB 261, which are both now subject to litigation. We believe we are subject to these laws and will continue to assess our reporting and disclosure requirements as the regulations are developed.

Non-GAAP Financial Measures

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

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

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RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2025 AND 2024

Below are our results of operations for the three months ended September 30, 2025, as compared to the same period in 2024 (in millions, except for percentages and operating performance metrics). In the comparative tables below, increases in revenue/income or decreases in expense (favorable variances) are shown without brackets while decreases in revenue/income or increases in expense (unfavorable variances) are shown with brackets.

	2025			2024		Change			% Change
Operating revenues:
Commodity revenue	$	3,759		$	3,610	$	149			4
Mark-to-market (loss) gain		(184	)		305		(489	)		#
Other revenue		42			5		37			#
Operating revenues		3,617			3,920		(303	)		-8
Operating expenses:
Fuel and purchased energy expense:
Commodity expense		2,225			1,867		(358	)		(19	)
Mark-to-market (gain) loss		(49	)		106		155			#
Fuel and purchased energy expense		2,176			1,973		(203	)		(10	)
Operating and maintenance expense		354			336		(18	)		-5
Depreciation and amortization expense		203			193		(10	)		(5	)
General and other administrative expense		43			46		3			7
Other operating expenses		122			21		(101	)		#
Total operating expenses		2,898			2,569		(329	)		(13	)
(Gain) loss on sale of assets, net		(127	)		13		140			#
(Income) loss from unconsolidated subsidiaries		(4	)		2		6			#
Income from operations		850			1,336		(486	)		(36	)
Interest expense		160			154		(6	)		(4	)
Loss on extinguishment of debt		—			8		8			#
Other expense, net		21			5		(16	)		#
Income before income taxes		669			1,169		(500	)		(43	)
Income tax expense		162			260		98			38
Net income	$	507		$	909	$	(402	)		(44	)

	2025			2024			Change			% Change
Operating Performance Metrics:
MWh generated (in thousands)(1)(2)		37,596			37,379			217			1
Average availability(1)(2)		94.1	%		94.7	%		(0.6	)		(1	)
Average total MW in operation(1)		27,978			27,102			876			3
Average capacity factor, excluding peakers(1)		65.2	%		67.0	%		(1.8	)		(3	)
Steam Adjusted Heat Rate, excluding peakers and Geysers(1)(2)(3)		7,449			7,423			(26	)		—

#	Variance of 100% or greater
(1)	Represents generation and capacity from power plants that we both consolidate and operate. See “— Description of Our Operations – Table of Operating Power Plants, Battery Storage Facilities and Projects Under Construction” in our 2024 Annual Report for our total equity generation and capacities.
(2)	Generation, Average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive.
(3)	Steam Adjusted Heat Rate excludes our Geysers and battery storage facilities.

We evaluate our Commodity revenue and Commodity expense on a collective basis because the price of power and natural gas tend to move together as the price for power is generally determined by the variable operating cost of the next marginal generator to be dispatched to meet demand. The spread between our Commodity revenue and Commodity expense represents a significant portion of our Commodity Margin. Our financial performance is correlated to how we maximize our Commodity Margin through management of our portfolio of power plants, as well as our hedging and optimization activities. See additional segment discussion in “Commodity Margin by Segment” below.

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Commodity revenue, net of Commodity expense, decreased $209 million for the three months ended September 30, 2025, compared to the three months ended September 30, 2024, primarily due to (favorable variances are shown without brackets while unfavorable variances are shown with brackets):

(in millions)
$	(243	)	Lower contribution from energy and capacity, driven partly from our West region as a result of lower market capacity revenues and less favorable hedge pricing. These impacts were partly related to the shaping of hedges from newly executed hedge contracts with tenors that span across multiple years. In other regions, including our Retail segment, less favorable hedge pricing compared to the previous year also contributed to lower results. These decreases were partially offset by the incremental contribution of portfolio changes including the acquisition of the Quail Run Energy Center and commencement of commercial operation at our Nova battery facility and our Bear Canyon and West Ford Flat battery facilities.
	46		Higher regulatory capacity revenues in our East segment
	(12	)	Period-over-period change in contract amortization, lease levelization related to tolling contracts, and other(1)
$	(209	)

(1) Commodity Margin excludes amortization expense related to contracts recorded at fair value, non-cash GAAP-related adjustments to levelize revenues from tolling agreements and other unusual items or non-recurring items.

Mark-to-market gain/loss, net from hedging our future generation, fuel supply requirements and retail activities had an unfavorable variance of $334 million primarily driven by the reversal of previously recognized gains on outstanding hedges at the beginning of the period as well as the negative effect of changes in forward market commodity prices on our existing commodity hedge portfolio.

Other revenue increased $37 million for the three months ended September 30, 2025, as compared to the three months ended September 30, 2024, primarily due to increased revenue recognition associated with completion of the initial phases of the Bosque Data Center construction project during the three-month period ending September 30, 2025.

Our normal, recurring operating and maintenance expense, after excluding the effect of scheduled maintenance costs, portfolio changes, performance-based employee compensation and stock-based compensation costs, increased $10 million for the three months ended September 30, 2025, as compared to the three months ended September 30, 2024. This increase was primarily related to higher salaries and wages related to annual compensation adjustments.

Depreciation and amortization expense increased by $10 million for the three months ended September 30, 2025, as compared to the three months ended September 30, 2024, primarily resulting from the acquisition of the Quail Run Energy Center, achievement of commercial operation on Phases I through IV at the Nova battery storage and Bear Canyon and West Ford Flat battery facilities, and newly installed parts associated with normally scheduled maintenance events and newly constructed development projects.

Our normal, recurring general and other administrative expense, after excluding non-recurring compensation costs, decreased $5 million for the three months ended September 30, 2025, compared to the three months ended September 30, 2024, primarily related to lower legal costs.

Other operating expense increased by $101 million for the three months ended September 30, 2025, compared to the three months ended September 30, 2024, primarily due to accrued transaction and legal costs related to the Plan of Merger Agreement between Calpine Corporation and Constellation Energy Group announced in January 2025.

Income from unconsolidated investments increased $6 million for the three months ended September 30, 2025, compared to the three months ended September 30, 2024, primarily due to lower administrative fees associated with our retail accounts receivable (“AR”) securitization facility.

Gain on sale of assets increased $140 million primarily driven by the approximately $117 million gain recognized on the sale of land at our Thad Hill Energy Center as a component of the newly executed data center deal.

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Interest expense, after excluding the effect of non-cash mark-to-market gains and losses, increased $6 million for the three months ended September 30, 2025, compared to the three months ended September 30, 2024, primarily driven by lower capitalized interest costs following the achievement of commercial operation of Phases I through V at Nova battery storage facilities.

Loss on extinguishment of debt decreased $8 million for the three months ended September 30, 2025, compared to the three months ended September 30, 2024, primarily due to refinancing and the upsize of the CCFC Term Loans in September 2024 with no comparable activity in the current period.

Other expense, net increased $16 million for the three months ended September 30, 2025, compared to the three months ended September 30, 2024, primarily due to higher letter of credit fees and increased costs associated with receivable securitization activities.

During the three months ended September 30, 2025, we recorded an income tax expense of $162 million compared to an income tax expense of $260 million during the three months ended September 30, 2024. This change is primarily due to lower income from operations in the three months ended September 30, 2025 compared to the three months ended September 30, 2024.

RESULTS OF OPERATIONS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2025 AND 2024

Below are our results of operations for the nine months ended September 30, 2025, as compared to the same period in 2024 (in millions, except for percentages and operating performance metrics). In the comparative tables below, increases in revenue/income or decreases in expense (favorable variances) are shown without brackets while decreases in revenue/income or increases in expense (unfavorable variances) are shown with brackets.

	2025			2024		Change			% Change
Operating revenues:
Commodity revenue	$	10,128		$	9,340	$	788			8
Mark-to-market (loss) gain		(310	)		167		(477	)		#
Other revenue		55			63		(8	)		(13	)
Operating revenues		9,873			9,570		303			3
Operating expenses:
Fuel and purchased energy expense:
Commodity expense		6,118			5,347		(771	)		(14	)
Mark-to-market loss		109			30		(79	)		#
Fuel and purchased energy expense		6,227			5,377		(850	)		(16	)
Operating and maintenance expense		1,063			1,047		(16	)		(2	)
Depreciation and amortization expense		611			568		(43	)		(8	)
General and other administrative expense		121			121		—			—
Other operating expenses		186			63		(123	)		#
Total operating expenses		8,208			7,176		(1,032	)		(14	)
(Gain) loss on sale of assets, net		(127	)		13		140			#
(Income) loss from unconsolidated subsidiaries		(10	)		6		16			#
Income from operations		1,802			2,375		(573	)		(24	)
Interest expense		474			426		(48	)		(11	)
Loss on extinguishment of debt		—			38		38			#
Other expense, net		55			23		(32	)		#
Income before income taxes		1,273			1,888		(615	)		(33	)
Income tax expense		325			439		114			26
Net income	$	948		$	1,449	$	(501	)		(35	)

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	2025			2024			Change			% Change
Operating Performance Metrics:
MWh generated (in thousands)(1)(2)		91,099			92,764			(1,665	)		(2	)
Average availability(1)(2)		86.6	%		87.5	%		(0.9	)		(1	)
Average total MW in operation(1)		27,882			26,783			1,099			4
Average capacity factor, excluding peakers(1)		53.6	%		56.9	%		(3.3	)		(6	)
Steam Adjusted Heat Rate(1)(2)(3)		7,475			7,427			(48	)		(1	)

#	Variance of 100% or greater
(1)	Represents generation and capacity from power plants that we both consolidate and operate. See “— Description of Our Operations – Table of Operating Power Plants and Projects Under Construction” in our 2024 Annual Report for our total equity generation and capacities.
(2)	Generation, average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive.
(3)	Steam Adjusted Heat Rate excludes our Geysers and battery storage facilities.

We evaluate our Commodity revenue and Commodity expense on a collective basis because the price of power and natural gas tend to move together as the price for power is generally determined by the variable operating cost of the next marginal generator to be dispatched to meet demand. The spread between our Commodity revenue and Commodity expense represents a significant portion of our Commodity Margin. Our financial performance is correlated to how we maximize our Commodity Margin through management of our portfolio of power plants, as well as our hedging and optimization activities. See additional segment discussion in “Commodity Margin by Segment.”

Commodity revenue, net of Commodity expense, increased $17 million for the nine months ended September 30, 2025, compared to the same period in 2024, primarily due to (favorable variances are shown without brackets while unfavorable variances are shown with brackets):

(in millions)
$	(55	)	Lower contribution from energy and capacity, driven partly from our West region as a result of lower market capacity revenues and less favorable hedge pricing. These impacts were partly related to the shaping of hedges from newly executed hedge contracts with tenors that span across multiple years. In our East region, less favorable hedge pricing compared to the previous year also contributed to the lower results. These decreases were partially offset by higher contribution from our Retail segment, increased hedge contributions from our Texas region and incremental margin contribution from portfolio changes including the acquisition of the Quail Run Energy Center and commencement of commercial operation at our Nova battery facility and our Bear Canyon and West Ford Flat battery facilities.
	70		Higher regulatory capacity revenues in our East segment
	2		Period-over-period change in contract amortization, lease levelization relating to tolling contracts and other(1)
$	17

(1) Commodity Margin excludes amortization expense related to contracts recorded at fair value, non-cash GAAP-related adjustments to levelize revenues from tolling agreements and other unusual items or non-recurring items.

Mark-to-market gain/loss, net from hedging our future generation, fuel supply requirements and retail activities had an unfavorable variance of $556 million primarily driven by the reversal of previously recognized gains on outstanding hedges at the beginning of the period as well as the negative effect of changes in forward market commodity prices on our existing commodity hedge portfolio.

Other revenue decreased $8 million for the nine months ended September 30, 2025, as compared to the nine months ended September 30, 2024, primarily due to lower revenue reimbursements associated with power plant maintenance services we provide to third parties, partially offset by increased revenue recognition associated with completion of the initial phases of the Bosque Data Center construction project during the three month period ending September 30, 2025.

Our normal, recurring operating and maintenance expense, after excluding the effect of scheduled maintenance costs, portfolio changes, performance-based employee compensation and stock-based compensation costs, increased $25 million for the nine months ended September 30, 2025, as compared to the nine months ended September 30, 2024. This increase was primarily related to higher salaries and wages related to annual compensation adjustments.

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Depreciation and amortization expense increased by $43 million for the nine months ended September 30, 2025, as compared to the same period in 2024, primarily resulting from the acquisition of the Quail Run Energy Center, achievement of commercial operation on Phases I through IV at our Nova battery storage facilities and at the Bear Canyon and West Ford Flat battery facilities, and newly installed parts associated with normally scheduled maintenance events and newly constructed development projects.

Our normal, recurring general and other administrative expense, after excluding non-recurring compensation costs, increased $2 million for the nine months ended September 30, 2025, compared to nine months ended September 30, 2024, primarily related to annual incentive compensation adjustments, partially offset by lower legal costs.

Other operating expense increased by $123 million for the nine months ended September 30, 2025, compared to the same period in 2024, primarily due to transaction and legal costs related to the Plan of Merger Agreement between Calpine Corporation and Constellation Energy Group announced in January, 2025.

Income from unconsolidated investments increased $16 million for the nine months ended September 30, 2025, compared to the nine months ended September 30, 2024, primarily due to lower administrative fees associated with our retail AR securitization facility.

Gain on sale of assets increased $140 million primarily driven by the approximately $117 million gain recognized on the sale of land at our Thad Hill Energy Center as a component of the newly executed data center deal.

Interest expense, excluding the effect of non-cash mark-to-market gains and losses, increased $31 million for the nine months ended September 30, 2025, compared to the same period in 2024, primarily driven by lower capitalized debt interest costs upon achievement of commercial operation of Phases I through V at Nova battery storage facilities. The unfavorable period-over-period change in non-cash mark-to-market activity of $17 million - associated with interest rate swaps that are economic hedges of our interest rate exposure but not designated in an accounting hedging relationship is also recognized within interest expense.

Loss on extinguishment of debt decreased $38 million for the nine months ended September 30, 2025, compared to the nine months ended September 30, 2024, primarily due to refinancing and the upsize of the CCFC Term Loans during 2024 with no comparable activity in the current period.

Other expense, net increased $32 million for the nine months ended September 30, 2025, compared to the same period in 2024, primarily due to higher letter of credit fees and increased costs associated with receivable securitization activities.

During the nine months ended September 30, 2025, we recorded an income tax expense of $325 million compared to an income tax expense of $439 million during the nine months ended September 30, 2024. This change is primarily due to lower income from operations in the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024.

Commodity Margin by Segment

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

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Commodity Margin by Segment for the Three Months Ended September 30, 2025 and 2024

The following tables show our Commodity Margin by segment and related operating performance metrics by regional segment for our wholesale business for the three months ended September 30, 2025 and 2024. In the comparative tables below, favorable variances are shown without brackets while unfavorable variances are shown with brackets. The MWh generated by regional segment below represent generation from power plants that we both consolidate and operate. Generation, Average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive. Steam Adjusted Heat Rate excludes our Geysers and battery storage facilities.

West:	2025			2024			Change			% Change
Commodity Margin (in millions)	$	594		$	728		$	(134	)		(18	)
Commodity Margin per MWh generated	$	61.28		$	72.80		$	(11.52	)		(16	)
MWh generated (in thousands)		9,694			10,000			(306	)		(3	)
Average availability		95.2	%		97.0	%		(1.8	)%		(2	)
Average total MW in operation		8,464			8,250			214			3
Average capacity factor, excluding peakers		55.0	%		57.4	%		(2.4	)%		(4	)
Steam Adjusted Heat Rate		7,276			7,345			69			1

West — Commodity Margin in our West segment decreased by $134 million, or 18%, for the three months ended September 30, 2025, compared to the three months ended September 30, 2024. The decrease in margin was primarily driven by less favorable realized pricing on market capacity sales and less favorable pricing on energy hedges. As discussed in prior quarters, the lower contribution from hedges was in part related to the shaping impact of long-term hedges covering multiple years executed at average prices over the transaction term. This was partially offset by the incremental commodity margin contribution associated with Phases I through IV of our Nova battery storage facility and our Bear Canyon and West Ford Flat battery facilities, which achieved commercial operations during September 2024 and October 2024, respectively.

Texas:	2025			2024			Change			% Change
Commodity Margin (in millions)	$	403		$	435		$	(32	)		(7	)
Commodity Margin per MWh generated	$	24.98		$	27.33		$	(2.35	)		(9	)
MWh generated (in thousands)		16,130			15,918			212			1
Average availability		94.2	%		94.3	%		(0.1	)%		—
Average total MW in operation		9,750			9,139			611			7
Average capacity factor, excluding peakers		74.9	%		78.2	%		(3.3	)%		(4	)
Steam Adjusted Heat Rate		7,401			7,301			(100	)		(1	)

Texas — Commodity Margin in our Texas segment decreased by $32 million, or 7%, for the three months ended September 30, 2025, compared to the three months ended September 30, 2024. The decrease in margin was primarily driven by less favorable realized hedge pricing compared to the previous year. This lower contribution was partially offset by incremental commodity margin contribution from our Quail Run Energy Center which was acquired during September 2024.

East:	2025			2024			Change			% Change
Commodity Margin (in millions)	$	349		$	340		$	9			3
Commodity Margin per MWh generated	$	29.65		$	29.67		$	(0.02	)		—
MWh generated (in thousands)		11,772			11,461			311			3
Average availability		92.9	%		93.4	%		(0.5	)%		(1	)
Average total MW in operation		9,763			9,713			50			1
Average capacity factor, excluding peakers		63.4	%		63.3	%		0.1	%		—
Steam Adjusted Heat Rate		7,645			7,658			13			—

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East — Commodity Margin in our East segment increased by $9 million, or 3%, for the three months ended September 30, 2025, compared to the three months ended September 30, 2024. The increase was driven by higher regulatory capacity revenue largely offset by lower total realized energy and hedge values.

Retail:	2025		2024		Change			% Change
Commodity Margin (in millions)	$	170	$	210	$	(40	)		(19	)

Retail — Commodity Margin in our retail segment decreased by $40 million, or 19%, for the three months ended September 30, 2025, compared to the three months ended September 30, 2024, driven by lower contribution from power and related energy products hedging activity when compared to the same period on the prior year.

Commodity Margin by Segment for the Nine Months Ended September 30, 2025 and 2024

The following tables show our Commodity Margin by segment and related operating performance metrics by regional segment for our wholesale business for the nine months ended September 30, 2025 and 2024. In the comparative tables below, favorable variances are shown without brackets while unfavorable variances are shown with brackets. The MWh generated by regional segment below represent generation from power plants that we both consolidate and operate. Generation, average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive. Steam Adjusted Heat Rate excludes our Geysers and battery storage facilities.

West:	2025			2024			Change			% Change
Commodity Margin (in millions)	$	1,430		$	1,567		$	(137	)		(9	)
Commodity Margin per MWh generated	$	68.05		$	66.51		$	1.54			2
MWh generated (in thousands)		21,014			23,562			(2,548	)		(11	)
Average availability		83.4	%		87.1	%		(3.7	)%		(4	)
Average total MW in operation		8,409			7,909			500			6
Average capacity factor, excluding peakers		40.5	%		47.8	%		(7.3	)%		(15	)
Steam Adjusted Heat Rate		7,340			7,385			(45	)		(1	)

West — Commodity Margin in our West segment decreased by $137 million, or 9%, for the nine months ended September 30, 2025, compared to the Nine months ended September 30, 2024. The decrease in margin was driven by less favorable realized pricing on market capacity sales and less favorable pricing on energy hedges. The lower contribution from hedges was in part related to the shaping impact of long-term hedges covering multiple years executed at average prices over the transaction term. These lower contributions were partially offset by incremental commodity margin contribution associated with Phases I through IV of our Nova battery storage facility and our Bear Canyon and West Ford Flat battery facilities, which achieved commercial operations during September 2024 and October 2024, respectively.

Texas:	2025			2024			Change			% Change
Commodity Margin (in millions)	$	1,123		$	948		$	175			18
Commodity Margin per MWh generated	$	27.72		$	23.84		$	3.88			16
MWh generated (in thousands)		40,511			39,759			752			2
Average availability		87.9	%		86.2	%		1.7	%		2
Average total MW in operation		9,721			9,083			638			7
Average capacity factor, excluding peakers		63.6	%		66.3	%		(2.7	)%		(4	)
Steam Adjusted Heat Rate		7,413			7,322			91			1

Texas — Commodity Margin in our Texas segment increased by $175 million, or 18%, for the nine months ended September 30, 2025, compared to the nine months ended September 30, 2024. The increase in margin was primarily driven by higher contribution from hedging activity on favorable hedged price levels for the period compared to the previous year and the incremental commodity margin contribution from our Quail Run Energy Center which was acquired during September 2024.

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East:	2025			2024			Change			% Change
Commodity Margin (in millions)	$	865		$	925		$	(60	)		(6	)
Commodity Margin per MWh generated	$	29.25		$	31.42		$	(2.17	)		(7	)
MWh generated (in thousands)		29,574			29,443			131			—
Average availability		88.2	%		89.2	%		(1.0	)%		(1	)
Average total MW in operation		9,751			9,791			(40	)		—
Average capacity factor, excluding peakers		54.3	%		54.7	%		(0.4	)%		(1	)
Steam Adjusted Heat Rate		7,643			7,602			41			1

East — Commodity Margin in our East segment decreased by $60 million, or 6%, for the nine months ended September 30, 2025, compared to the nine months ended September 30, 2024. The decrease in margin was primarily driven by less favorable hedge pricing compared to the previous year. The decrease was partially offset by increased regulatory capacity revenues primarily during the three-month period ended September 30, 2025.

Retail:	2025		2024		Change		% Change
Commodity Margin (in millions)	$	574	$	537	$	37		7

Retail — Commodity Margin in our retail segment increased by $37 million, or 7%, for the nine months ended September 30, 2025, compared to the nine months ended September 30, 2024, driven by higher contribution from power and related energy products hedging activity when compared to the same period on the prior year.

Liquidity and Capital Resources

We maintain a strong focus on our balance sheet, capital allocation and liquidity. We manage our liquidity to provide access to sufficient funding to meet our business needs and financial obligations.

Our business is capital-intensive, and successful implementation of our business strategy is dependent on the continued availability of capital at attractive terms. Continued commodity price volatility places a higher priority on access to liquidity and liquidity management. We believe that we have adequate liquidity that includes a combination of revolving credit facilities, letter of credit facilities, other liquidity and collateral-specific facilities, such as accounts receivable monetization facilities, cash and cash equivalents on hand and cash expected to be generated from future operations. This liquidity allows us to continue to meet our obligations as they become due. Further, we continue to opportunistically increase liquidity sources through the execution of new facilities and/or increasing capacity under existing facilities. We executed the following transactions in line with our balance sheet management strategy:

· 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.

See further discussion of our available liquidity provided below and of the above facilities within Note 5, Debt of the Notes to Consolidated Condensed Financial Statements included herein.

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Liquidity

Liquidity Position

The following table provides a summary of liquidity position (in millions):

	September 30, 2025		December 31, 2024
Cash and cash equivalents, corporate(1)	$	1,118	$	650
Cash and cash equivalents, non-corporate(2)		31		56
Total cash and cash equivalents		1,149		706
Restricted cash(2)		293		279
Corporate Revolving Facility availability(3)		1,818		2,227
CDHI Credit Agreement availability(4)		356		370
Commodity-linked Revolver availability(5)		1,646		1,786
Other facilities availability(6)		1		51
Total liquidity position(7)	$	5,263	$	5,419

(1)	The ability to use corporate cash and cash equivalents is unrestricted.
(2)	See Note 1, Basis of Presentation and Summary of Significant Accounting Policies - Restricted Cash of the Notes to Consolidated Condensed Financial Statements for a description of the restrictions on our use of non-corporate cash and cash equivalents and restricted cash.
(3)	Our ability to use $2.500 billion Corporate Revolving Facility is unrestricted. On January 31, 2024, we extended the term on $2.225 billion of the Corporate Revolving Facility from January 2027 to January 2029 with the remaining $275 million expiring in January 2027. On December 16, 2024, the Company amended the Corporate Revolving Facility commitments with $2.400 billion expiring in January 2029 and the remaining $100 million expiring in January 2027. As of September 30, 2025, approximately $2.500 billion in total capacity was comprised of $682 million in letters of credit outstanding with nil borrowings outstanding and roughly $1.818 billion in remaining available capacity. As of December 31, 2024, approximately $2.500 billion in total capacity was comprised of $273 million in letters of credit outstanding, nil in borrowings outstanding, and roughly $2.227 billion in remaining available capacity. See “Letter of Credit Facilities” below for amounts issued under letters of credit as of September 30, 2025 and December 31, 2024 associated with the Corporate Revolving Facility.
(4)	As of September 30, 2025 and December 31, 2024, CDHI Credit Agreement has an available capacity of $1.2 billion and the letter of credit facility limit of $400 million for construction loans that meet specified criteria. As of September 30, 2025 and December 31, 2024, the CDHI Credit Agreement has $524 million and $640 million in letters of credit outstanding, $278 million and $148 million in borrowings outstanding and $356 million and $370 million in remaining available capacity, respectively. See “Letter of Credit Facilities” below for amounts issued under letters of credit as of September 30, 2025 and December 31, 2024 associated with the CDHI credit agreement.
(5)	The Commodity-linked Revolver can be utilized to meet collateral posting requirements for eligible commodity hedge agreements, as defined in the agreement, and contains an aggregate borrowing base limit of $1.646 billion and $1.786 billion as of September 30, 2025 and December 31, 2024, respectively. On July 17, 2025, the agreement was extended through July 2026 and decreased the total borrowing base limit from $1.786 billion to $1.646 billion.
(6)	We have four secured bilateral letter of credit agreements, for up to $525 million and $525 million as of September 30, 2025 and December 31, 2024, respectively, of capacity with varying tenors, one of which was extended from 2025 to 2027 in January 2024. We also have unsecured letter of credit facilities totaling approximately $200 million and $325 million as of September 30, 2025 and December 31, 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. See “Letter of Credit Facilities” below for amounts issued under letters of credit as of September 30, 2025 and December 31, 2024 associated with Other Corporate Facilities.
(7)	Includes $101 million and $327 million of margin deposits posted with us by our counterparties as of September 30, 2025, and December 31, 2024, respectively. See Note 8, Use of Collateral of the Notes to Consolidated Condensed Financial Statements included herein for further information related to collateral.

Our principal sources for future liquidity are cash on hand and cash flows generated from our operations and our financing arrangements. We believe that cash on hand and expected future cash flows from operations will be sufficient to meet our debt service requirements, including principal and interest repayments, post collateral and finance for our ongoing operations, both in the near and long term. See “Cash Flow Activities” below for a further discussion of changes in our cash, cash equivalents and restricted cash.

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Our principal uses of liquidity and capital resources, outside of those required for our operations, include, but are not limited to, collateral requirements to support our commercial hedging and optimization activities, debt service obligations including principal and interest payments, capital expenditures for construction, project development and other growth initiatives, funding distributions to our shareholders and opportunistically repaying debt to manage our balance sheet.

We manage our cash in accordance with our cash management system subject to the requirements of our Corporate Revolving Facility and requirements under certain of our project debt and other agreements or by regulatory agencies. Our cash and cash equivalents, as well as our restricted cash balances, are invested in money market funds that are not FDIC insured. We place our cash, cash equivalents and restricted cash in what we believe to be creditworthy financial institutions.

Future cash dividends, if any, may be authorized at the discretion of our Board of Directors and will depend upon, among other things, our future operations and earnings, capital requirements, asset sales, general financial condition, contractual and financing restrictions and such other factors as our Board of Directors may deem relevant.

Liquidity Sensitivity

Significant changes in commodity prices and Market Heat Rates can affect our liquidity. These changes can affect margin deposits, cash prepayments and letters of credit as credit support made with and received from our counterparties associated with our commodity procurement and risk management activities. We estimate that as of September 30, 2025, the effect of a $1.00 change to natural gas prices at a market heat rate would result in collateral posted of approximately $688 million. We believe we have sufficient liquidity resources to mitigate normal collateral exposure from changes in commodity prices. These sensitivities represent an estimate as of a point in time and will change as new contracts or hedging activities are executed.

In order to manage the effect commodity price volatility on our future results of operations, we have economically hedged a portion of our expected power generation and natural gas fuel supply portfolio requirements as well as retail load supply obligations, mostly through power and natural gas forward physical and financial transactions including retail power sales. However, we currently remain susceptible to significant commodity price movements for 2025 and beyond.

In addition to commodity market prices, our results of operations are highly dependent on other factors such as:

· the level of Market Heat Rates;

· our continued ability to successfully hedge our Commodity Margin (for a discussion of our non-GAAP financial measures, including Commodity Margin, and a reconciliation to the most comparable GAAP measure, see the section titled “Non-GAAP Financial Measures” included herein);

· changes in U.S. macroeconomic conditions;

· maintaining acceptable availability levels for our fleet;

· the effect of current and pending environmental regulations in the markets in which we participate;

· improving the efficiency and profitability of our operations;

· increasing future contractual cash flows; and

· our significant counterparties performing under their contracts with us.

It is difficult to predict future developments and the amount of credit support that we may need to provide under such conditions or if we experience an economic recession or energy commodity prices increase significantly. To manage such liquidity requirements, we maintain additional liquidity availability in the form of our Corporate Revolving Facility, our CDHI Credit Agreement and our Commodity-linked Revolver (noted in the table above), letters of credit and the ability to issue first priority liens for collateral support.

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Capital Resources

Letter of Credit Facilities

The table below represents letters of credit issued under our letter of credit facilities as of September 30, 2025 and December 31, 2024 (in millions):

	September 30, 2025		December 31, 2024
Corporate Revolving Facility	$	682	$	273
CDHI Credit Agreement		524		640
Project financing facilities		315		290
Other corporate facilities		724		849
Total	$	2,245	$	2,052

Credit Compliance

We complied with our covenants under the Corporate Revolving Facility, the CDHI Credit Agreement, the Commodity-linked Revolver and the letter of credit facilities as of September 30, 2025 and December 31, 2024.

NOLs and Interest Expense Limitation

We have significant NOLs that may provide a future offset to taxable income during the applicable carryover periods. As of December 31, 2024, our consolidated gross federal NOLs totaled approximately $3.0 billion, and our gross post-apportioned state NOLs totaled approximately $1.6 billion, resulting in net tax-affected federal and post-apportioned state NOLs of $0.7 billion. Our valuation allowance is partially due to the uncertainty in our ability to use state NOLs before expiration, with the remaining valuation allowance mostly related to the 163(j)-interest expense limitation where it is not more likely than not we will be able to utilize the 163(j) carryforwards in future periods.

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Cash Flow Activities

The following table summarizes our cash flow activities for the nine months ended September 30, 2025 and 2024 (in millions):

	2025			2024
Beginning cash, cash equivalents and restricted cash	$	985		$	348
Net cash provided by (used in):
Operating activities		1,520			2,906
Investing activities		(922	)		(1,104	)
Financing activities		(141	)		491
Net increase in cash, cash equivalents and restricted cash		457			2,293
Ending cash, cash equivalents and restricted cash	$	1,442		$	2,641

Net Cash Provided By Operating Activities

Cash provided by operating activities for the nine months ended September 30, 2025, was $1,520 million compared to $2,906 million in the prior year period. The period-over-period decrease was driven by an increase in collateral margin postings in 2025 for our commodity hedges, along with a large one-time sale of investment tax credits for our Nova Battery Storage Facility during the third quarter of 2024.

Net Cash Used In Investing Activities

Cash used in investing activities for the nine months ended September 30, 2025, was $922 million compared to $1,104 million in the prior year period. The period-over-period decrease was primarily driven by the acquisition of our Quail Run Energy Center during September 2024 for a cash purchase price of $334 million. This was offset in part by continued investments in our development and growth projects, additional investments in unconsolidated subsidiaries, and strategic purchases of long lead time parts in the current year period.

Net Cash (Used In) Provided By Financing Activities

Cash used in financing activities for the nine months ended September 30, 2025 was $141 million, compared to cash provided by financing activities of $491 million in the prior year period. Cash used in financing activities during the nine months ended September 30, 2025, was primarily driven by the redemption of the 2026 First Lien Notes, utilizing proceeds from the upsizing and extension of our term loan facilities during the fourth quarter of 2024. Cash provided by financing activities during the nine months ended September 30, 2024, was primarily attributable to the upsize of our CCFC term loan facility, borrowings under our Nova Credit Agreement utilized to fund the ongoing construction of our Nova battery storage facility, as well as borrowings under our GPC Term Loan utilized to fund the construction of our West Ford Flat and Bear Canyon battery facilities. This was partially offset by repayments on our Commodity-linked Revolver during the period, along with normal, recurring debt amortization.

Off-Balance Sheet Arrangements

There have been no material changes to our off-balance sheet arrangements from those disclosed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2024 Annual Report.

Special Purpose Subsidiaries

Pursuant to applicable transaction agreements, we have established certain entities separate from Calpine Corporation and our other subsidiaries. In accordance with applicable accounting standards, we consolidate these entities with the exception of Calpine Receivables (see Note 7, Variable Interest Entities and Unconsolidated Investments, Note 16, Commitments and Contingencies and 17, Related Party Transactions of the Notes to Consolidated Financial Statements in our 2024 Annual Report for further information related to Calpine Receivables). As of the filing of this Report, these entities included: GPC, Calistoga Holdings, LLC, Wildhorse Geothermal LLC, Geysers Intermediate Holdings LLC, Geysers Company, LLC, Bethpage Energy Center 3, LLC, Nova Power, LLC and Calpine Receivables.

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Risk Management and Commodity Accounting

Our commercial hedging and optimization strategies are designed to maximize our risk-adjusted Commodity Margin by leveraging our knowledge, experience and fundamental views on natural gas and power. During 2024, as power prices increased in major markets, we were able to secure forward gains for 2025 at values higher than actual settled prices across all markets. Further, market volatility also created significant opportunities for both our Retail segment where we were able to capture value through hedging and optimization activities and also in our wholesale generation segments where opportunities for originated load and other transactions contributed additional margin.

Where available, we account for commodity derivatives under hedge accounting rules, recognizing the unrealized gain and/or loss associated with those hedges through other comprehensive income. All other derivative contracts are accounted for on a mark-to-market basis with the change in fair value recognized through mark-to-market earnings. Our hedging approach is also the key driver of changes in unrealized hedge gains and losses. Volumes sold forward against future generation create unrealized gains/losses on forward hedges as prices change. Since prices for power and natural gas and interest rates are volatile, there may be material changes in the fair value of our derivatives over time, driven both by price volatility and the changes in volume of open derivative transactions. Our derivative assets have decreased to approximately $961 million at September 30, 2025 compared to approximately $1,138 million at December 31, 2024, and derivative liabilities have increased to approximately $823 million at September 30, 2025 compared to approximately $704 million at December 31, 2024. The fair value of our Level 3 derivative assets and liabilities at September 30, 2025 and December 31, 2024 represents approximately 74% and 55% and 51% and 78% of our total assets and liabilities measured at fair value, respectively. See Note 7, Derivative Instruments of the Consolidated Condensed Financial Statements included herein, for further discussion on our derivative assets and liabilities.

The change in fair value of our outstanding commodity and interest rate hedging instruments from January 1, 2025 through September 30, 2025, is summarized in the table below (in millions):

	Commodity Instruments			Interest Rate Hedging Instruments			Total
Fair value of contracts outstanding at January 1, 2025(1)	$	187		$	247		$	434
Items recognized or otherwise settled during the period(2)(3)		(140	)		(81	)		(221	)
Fair value attributable to new contracts(4)		(78	)		—			(78	)
Changes in fair value attributable to price movements		(442	)		(55	)		(497	)
Changes in fair value attributable to nonperformance risk		4			1			5
Changes in fair value attributable to margin allocation		495			—			495
Fair value of contracts outstanding at September 30, 2025(1)	$	26		$	112		$	138

(1)	The Company nets all amounts allowed under the derivative accounting guidance in the Consolidated Condensed Balance Sheets, which includes derivative transactions under enforceable master netting arrangements and related cash collateral. Net commodity and interest rate derivative assets and liabilities reported in Note 6, Assets and Liabilities with Recurring Fair Value Measurements and Note 7, Derivative Instruments of the Notes to Consolidated Condensed Financial Statements included herein are shown net of collateral paid to and received from counterparties under legally enforceable master netting arrangements.
(2)	Commodity contract settlements consist of the realization of previously recognized gains on contracts not designated as hedging instruments of $224 million (represents a portion of Commodity revenue and Commodity expense as reported in our Consolidated Condensed Statements of Operations), $67 million related to realized losses from settlements of designated cash flow hedges and gains of $17 million related to current period / other changes in derivative assets and liabilities not reflected in OCI or earnings.
(3)	Interest rate settlements consist of $47 million related to realized gains from settlements of designated cash flow hedges and $34 million related to roll-off of gains from settlements of undesignated interest rate swaps (represents a portion of interest expense as reported in our Consolidated Condensed Statements of Operations).
(4)	Fair value attributable to new contracts includes $14 million and nil of fair value related to commodity contracts and interest rate hedging instruments, respectively, which are not reflected in OCI or earnings.

The price sourced fair value and maturities of outstanding derivative commodity instruments, net of allocated collateral, are summarized in the table below ($ in millions) at September 30, 2025. The categories below are consistent with the fair value hierarchy as Level 1 instruments use prices actively quoted, Level 2 instruments use prices provided by other external sources and Level 3 instruments use prices based on models and other valuation methods.

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	Maturity dates of unrealized commodity contract net assets / (liabilities) at September 30, 2025
Source of fair value	Less than 1 year		1-3 years			4-5 years			Excess of 5 years		Total
Prices actively quoted	$	—	$	—		$	—		$	—	$	—
Prices provided by other external sources		59		(221	)		(73	)		—		(235	)
Other valuation methods		51		61			26			123		261
Total	$	110	$	(160	)	$	(47	)	$	123	$	26

We measure the energy commodity price risk in our portfolio on a daily basis using a VAR model to estimate the potential one-day risk of loss based on historical experience resulting from potential market movements. Our VAR is calculated for our entire portfolio, which comprises energy commodity derivatives, expected generation, natural gas consumption from our power plants, PPAs and other physical and financial transactions. We measure VAR using a variance/covariance approach based on a confidence level of 95%, a one-day holding period, and actual observed historical correlation. While we believe that our VAR assumptions and approximations are reasonable, different assumptions and/or approximations could produce materially different estimates.

The table below presents the high, low and average of our daily VAR for the nine months ended 2025 and 2024 (in millions):

	2025		2024
High	$	32	$	48
Low	$	19	$	33
Average	$	25	$	40
As of the period end	$	19	$	35

Due to the inherent limitations of statistical measures such as VAR, the VAR calculation may not capture the full extent of our commodity price exposure. As a result, actual changes in the value of our energy commodity portfolio could be different from the calculated VAR and could have a material effect on our financial results. To evaluate the risks of our portfolio on a comprehensive basis and augment our VAR analysis, we also measure the risk of the energy commodity portfolio using several analytical methods including sensitivity analysis, non-statistical scenario analysis and daily position report analysis.

We utilize the forward commodity markets to hedge price risk associated with our power plant portfolio. Our ability to hedge relies in part on market liquidity and the number of counterparties with which to transact. While the number of counterparties in these markets has decreased, to date this occurrence has not had a material adverse effect on our results of operations or financial condition. However, should these conditions persist or increase, it could decrease our ability to hedge our forward commodity price risk and create incremental volatility in our earnings. The effects of declining liquidity in the forward commodity markets is also mitigated by our retail subsidiaries which provides us with an additional outlet to transact hedging activities related to our wholesale power plant portfolio.

Liquidity Risk — Liquidity risk arises from the general funding requirements needed to manage our activities and assets and liabilities. Fluctuating natural gas prices or Market Heat Rates can cause our collateral requirements for our wholesale and retail activities to increase or decrease. Our liquidity management framework is intended to maximize liquidity access and minimize funding costs during times of rising prices. See further discussion regarding our uses of collateral as they relate to our commodity procurement and risk management activities in Note 8, Use of Collateral of the Notes to Consolidated Condensed Financial Statements.

Credit Risk — Credit risk relates to the risk of loss resulting from nonperformance or non-payment by our counterparties or customers related to their contractual obligations with us. Risks surrounding counterparty and customer performance and credit could ultimately affect the amount and timing of expected cash flows. We also have credit risk if counterparties or customers are unable to provide collateral or post margin. We monitor and manage our credit risk through credit policies that include:

· credit approvals;

· routine monitoring of counterparties’ and customers’ credit limits and their overall credit ratings;

· limiting our marketing, hedging and optimization activities with high risk counterparties;

· margin, collateral or prepayment arrangements; and

· payment netting arrangements or master netting arrangements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty.

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We have concentrations of credit risk with a few of our wholesale counterparties, ISOs and retail customers relating to our sales of power and steam and our hedging, optimization and trading activities. For example, our wholesale business currently has contracts with investor-owned California utilities which could be affected should they be found liable for past wildfires in California and, accordingly, incur substantial costs associated with the wildfires.

We believe that our credit policies and portfolio of transactions adequately monitor and diversify our credit risk, and currently our counterparties and customers are performing and financially settling timely according to their respective agreements. We monitor and manage our total comprehensive credit risk associated with all of our contracts irrespective of whether they are accounted for as an executory contract, a normal purchase normal sale or whether they are marked-to-market and included in our derivative assets and liabilities in our Consolidated Condensed Balance Sheets. Our counterparty and customer credit quality associated with the net fair value of outstanding derivative commodity instruments is included in our derivative assets and (liabilities), net of allocated collateral, at September 30, 2025, and the period during which the respective instruments will mature are summarized in the table below (in millions):

Credit Quality (Based on Credit Ratings as of September 30, 2025)	2025		2026-2027			2028-2029			After 2029		Total
Investment grade	$	23	$	(265	)	$	(75	)	$	57	$	(260	)
Non-investment grade		48		(18	)		—			58		88
No external ratings(1)		39		123			28			8		198
Total fair value	$	110	$	(160	)	$	(47	)	$	123	$	26

(1) Primarily comprised of the fair value of derivative instruments held with customers that are not rated by third-party credit agencies due to the nature and size of the customers.

Interest Rate Risk — Our variable rate financings are indexed to base rates, generally SOFR. Interest rate risk represents the potential loss in earnings arising from adverse changes in market interest rates. The fair value of our interest rate hedging instruments are validated based upon external quotes. Our interest rate hedging instruments are with counterparties we believe are primarily high quality institutions, and we do not believe that our interest rate hedging instruments expose us to any significant credit risk. Holding all other factors constant, we estimate that a 10% decrease in interest rates would result in a change in the fair value of our interest rate hedging instruments hedging our variable rate debt of approximately $(37) million at September 30, 2025.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The information required to be disclosed under this Item 3 is set forth under Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Risk Management and Commodity Accounting” in the 2024 Annual Report. This information should be read in conjunction with the information disclosed in the 2024 Annual Report. Except as disclosed in this Report, there have been no material changes from the disclosures presented in the 2024 Annual Report regarding our exposures to certain market risks.

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings

See Note 10, Commitments and Contingencies of the Notes to Consolidated Condensed Financial Statements included herein for a description of our legal proceedings.

Item 1A. Risk Factors

There were no changes to the description of the risk factors previously disclosed in Part I, Item 1A “Risk Factors” of our 2024 Annual Report.

Item 5. Other Information

Not applicable

Item 6. Exhibits

EXHIBIT INDEX

Exhibit Number

Description

4.1

CREDIT AGREEMENT, dated as of October 13, 2025 (this “Agreement”), is entered into among PIN OAK CREEK ENERGY CENTER, LLC (f/k/a FPEC, LLC), a limited liability company duly organized and existing under the laws of Delaware (“Borrower”), U.S. BANK TRUST COMPANY, NATIONAL ASSOCIATION, as administrative agent for Lender (together with its successors and permitted assigns in such capacity, “Administrative Agent”) and the PUBLIC UTILITY COMMISSION OF TEXAS (“Lender” and together with Borrower and Administrative Agent, the “Parties”).*

* Filed herewith.

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SIGNATURES

Calpine has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.

CALPINE CORPORATION
By:	/s/ ZAMIR RAUF
	Zamir Rauf
	Executive Vice President and Chief Financial Officer

Date: November 3, 2025

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