UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
____________________
Form 10-Q
(Mark One)

[X] |  | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
|  | OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2019
|  | Or
[ ] |  | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
|  | OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to
Commission File No. 001-12079
______________________
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
Not Applicable
(Former Address)
Securities registered pursuant to Section 12(b) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [ ] No [X]
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes [X] No [ ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer | [ ] |  | Accelerated filer | [ ]
Non-accelerated filer | [X] |  | Smaller reporting company | [ ]
Emerging growth company | [ ] |  |  |

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: 105.2 shares of common stock, par value $0.001, were outstanding as of August 7, 2019, none of which were publicly traded.

CALPINE CORPORATION AND SUBSIDIARIES
REPORT ON FORM 10-Q
For the Quarter Ended June 30, 2019
INDEX

| Page
Definitions | ii
Forward-Looking Statements | vi
Where You Can Find Other Information | vii
PART I – FINANCIAL INFORMATION |
Item 1. Financial Statements (Unaudited) | 1
Consolidated Condensed Statements of Operations for the Three and Six Months Ended June 30, 2019 and 2018 | 1
Consolidated Condensed Statements of Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2019 and 2018 | 2
Consolidated Condensed Balance Sheets at June 30, 2019 and December 31, 2018 | 3
Consolidated Condensed Statement of Stockholder’s Equity for the Three and Six Months Ended June 30, 2019 and 2018 | 4
Consolidated Condensed Statements of Cash Flows for the Six Months Ended June 30, 2019 and 2018 | 5
Notes to Consolidated Condensed Financial Statements | 7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations | 36
Forward-Looking Information | 36
Introduction and Overview | 36
Results of Operations | 38
Commodity Margin by Segment | 42
Liquidity and Capital Resources | 45
Risk Management and Commodity Accounting | 49
New Accounting Standards and Disclosure Requirements | 52
Item 3. Quantitative and Qualitative Disclosures About Market Risk | 52
Item 4. Controls and Procedures | 52
PART II – OTHER INFORMATION |
Item 1. Legal Proceedings | 53
Item 1A. Risk Factors | 53
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds | 53
Item 3. Defaults Upon Senior Securities | 53
Item 4. Mine Safety Disclosures | 53
Item 5. Other Information | 53
Item 6. Exhibits | 54
Signatures | 55

i

DEFINITIONS
As used in this report for the quarter ended June 30, 2019 (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 filing this Report.

ABBREVIATION |  | DEFINITION
2018 Form 10-K |  | Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2018, filed with the SEC on March 28, 2019
2019 First Lien Term Loan |  | The $400 million first lien senior secured term loan, dated February 3, 2017, among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent and MUFG Union Bank, N.A., as collateral agent, repaid on April 5, 2019
2022 First Lien Notes |  | The $750 million aggregate principal amount of 6.0% senior secured notes due 2022, issued October 31, 2013
2023 First Lien Term Loans |  | The $550 million first lien senior secured term loan, dated December 15, 2015, among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent, repaid on April 5, 2019, and the $562 million first lien senior secured term loan, dated May 31, 2016, among Calpine Corporation, as borrower, the lenders party thereto, Citibank, N.A., as administrative agent and MUFG Union Bank, N.A., as collateral agent
2023 Senior Unsecured Notes |  | The $1.25 billion aggregate principal amount of 5.375% senior unsecured notes due 2023, issued July 22, 2014
2024 First Lien Notes |  | The $490 million aggregate principal amount of 5.875% senior secured notes due 2024, issued October 31, 2013
2024 First Lien Term Loan |  | The $1.6 billion first lien senior secured term loan, dated May 28, 2015 (as amended December 21, 2016), among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent
2024 Senior Unsecured Notes |  | The $650 million aggregate principal amount of 5.5% senior unsecured notes due 2024, issued February 3, 2015
2025 Senior Unsecured Notes |  | The $1.55 billion aggregate principal amount of 5.75% senior unsecured notes due 2025, issued July 22, 2014
2026 First Lien Notes |  | Collectively, the $625 million aggregate principal amount of 5.25% senior secured notes due 2026, issued May 31, 2016, and the $560 million aggregate principal amount of 5.25% senior secured notes due 2026, issued on December 15, 2017
2026 First Lien Term Loan |  | The $950 million first lien senior secured term loan, dated April 5, 2019, among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent and MUFG Union Bank, N.A., as collateral agent
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, both which allows for the revolving sale of up to $250 million in certain trade accounts receivables to third parties
AOCI |  | Accumulated Other Comprehensive Income
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
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 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 20 states, including presence in California, Texas, the Mid-Atlantic and the Northeast
CCFC |  | Calpine Construction Finance Company, L.P., an indirect, wholly owned subsidiary of Calpine
CCFC Term Loan |  | The $1.0 billion first lien senior secured term loan entered into on December 15, 2017 among CCFC as borrower, the lenders party thereto, and Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent
CDHI |  | Calpine Development Holdings, Inc., an indirect, wholly owned subsidiary of Calpine
Champion Energy |  | Champion Energy Marketing, LLC, which owns a retail electric provider that serves residential, governmental, commercial and industrial customers in deregulated electricity markets in 14 states and the District of Columbia, including presence in California, Texas, the Mid-Atlantic and Northeast
Cogeneration |  | Using a portion or all of the steam generated in the power generating process to supply a customer with 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 expenses, 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 Margin |  | Measure of profit reviewed by our chief operating decision maker that includes revenue 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 activities, fuel and purchased energy expenses, commodity transmission and transportation expenses, environmental compliance expenses and ancillary retail expense. Commodity Margin is a measure of segment profit or loss under FASB Accounting Standards Codification 280 used by our chief operating decision maker to make decisions about allocating resources to the relevant segments and assessing their performance
Commodity revenue |  | The sum of our revenues recognized on our wholesale and retail power sales activity, electric capacity sales, REC sales, steam sales and realized settlements from our marketing, hedging, optimization and trading activities
Company |  | Calpine Corporation, a Delaware corporation, and its subsidiaries
Corporate Revolving Facility |  | The approximately $2.02 billion aggregate amount revolving credit facility credit agreement, dated as of December 10, 2010, as amended on June 27, 2013, July 30, 2014, February 8, 2016, December 1, 2016, September 15, 2017, October 20, 2017, March 8, 2018, May 18, 2018 and April 5, 2019 among Calpine Corporation, the Bank of Tokyo-Mitsubishi UFJ, Ltd., as successor administrative agent, MUFG Union Bank, N.A., as successor collateral agent, the lenders party thereto and the other parties thereto
CPN Management |  | CPN Management, LP, which owns 100% of the common stock of Calpine Corporation
Exchange Act |  | U.S. Securities Exchange Act of 1934, as amended

iii

ABBREVIATION |  | DEFINITION
FASB |  | Financial Accounting Standards Board
FERC |  | U.S. Federal Energy Regulatory Commission
First Lien Notes |  | Collectively, the 2022 First Lien Notes, the 2024 First Lien Notes and the 2026 First Lien Notes
First Lien Term Loans |  | Collectively, the 2019 First Lien Term Loan, the 2023 First Lien Term Loans, the 2024 First Lien Term Loan and the 2026 First Lien Term Loan
Greenfield LP |  | Greenfield Energy Centre LP, a 50% partnership interest between certain of our subsidiaries and a third-party which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant in Ontario, Canada
Heat Rate(s) |  | A measure of the amount of fuel required to produce a unit of power
IRS |  | U.S. Internal Revenue Service
ISO(s) |  | Independent System Operator, which is an entity that coordinates, controls and monitors the operation of an electric power system
KWh |  | Kilowatt hour(s), a measure of power produced, purchased or sold
LIBOR |  | London Inter-Bank Offered Rate
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 pursuant to the terms of the Merger Agreement, which was consummated on March 8, 2018
Merger Agreement |  | Agreement and Plan of Merger, dated, August 17, 2017, by and among Calpine Corporation, Volt Parent, LP and Volt Merger Sub, Inc.
MMBtu |  | Million Btu
MW |  | Megawatt(s), a measure of plant capacity
MWh |  | Megawatt hour(s), a measure of power produced, purchased or sold
NOL(s) |  | Net operating loss(es)
OCI |  | Other Comprehensive Income
OMEC |  | Otay Mesa Energy Center, LLC, an indirect, wholly owned subsidiary that owns the Otay Mesa Energy Center, a 608 MW power plant located in San Diego County, California
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 other derivative or hedge transaction) 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
REC(s) |  | Renewable energy credit(s)

iv

ABBREVIATION |  | DEFINITION
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
RTO(s) |  | Regional Transmission Organization, 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
SDG&E |  | San Diego Gas & Electric Company
SEC |  | U.S. Securities and Exchange Commission
Securities Act |  | U.S. Securities Act of 1933, as amended
Senior Unsecured Notes |  | Collectively, the 2023 Senior Unsecured Notes, the 2024 Senior Unsecured Notes and the 2025 Senior Unsecured Notes
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
U.S. GAAP |  | Generally accepted accounting principles in the U.S.
VAR |  | Value-at-risk
VIE(s) |  | Variable interest entity(ies)
Whitby |  | Whitby Cogeneration Limited Partnership, a 50% partnership interest between certain of our subsidiaries and a third-party, which operates Whitby, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada

v

Forward-Looking Statements
This Report contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act, and Section 21E of the Exchange Act. 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 of 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 our liquidity needs, access the capital markets when necessary and comply with covenants under our Senior Unsecured Notes, First Lien Notes, First Lien Term Loans, Corporate Revolving Facility, CCFC Term Loan and other existing financing obligations;

• | Risks associated with the operation, construction and development of power plants, 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 from renewable sources of power, interference by states in competitive power markets through subsidies or similar support for new or existing power plants, 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 demand-side management tools (such as distributed generation, power storage 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, wildfires and floods, acts of terrorism or cyber attacks that may affect our power plants or the markets our power plants or retail operations serve and our corporate offices;

• | 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;

• | Our ability to attract, motivate and retain key employees;

• | Present and possible future claims, litigation and enforcement actions that may arise from noncompliance with market rules promulgated by the SEC, Commodity Futures Trading Commission, FERC and other regulatory bodies; and

• | Other risks identified in this Report, in our 2018 Form 10-K and in other reports filed by us with the SEC.

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.
vi

Where You Can Find Other Information
Our website is www.calpine.com. Information contained on our website is not part of this Report. Information that we furnish or file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to, or exhibits included in, these reports are available for download, free of charge, through our website. Our SEC filings, including exhibits filed therewith, are also available directly on the SEC’s website at www.sec.gov.
vii

PART I — FINANCIAL INFORMATION

Item 1. | Financial Statements

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
(Unaudited)

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2019 |  | 2018 |  | 2019 |  | 2018
| (in millions)
Operating revenues: |  |  |  |  |  |  |
Commodity revenue | $ | 2,128 |  |  | $ | 2,121 |  |  | $ | 4,666 |  |  | $ | 4,517 |
Mark-to-market gain (loss) | 467 |  |  | 131 |  |  | 523 |  |  | (260 | )
Other revenue | 4 |  |  | 7 |  |  | 9 |  |  | 11 |
Operating revenues | 2,599 |  |  | 2,259 |  |  | 5,198 |  |  | 4,268 |
Operating expenses: |  |  |  |  |  |  |
Fuel and purchased energy expense: |  |  |  |  |  |  |
Commodity expense | 1,367 |  |  | 1,426 |  |  | 3,125 |  |  | 3,216 |
Mark-to-market (gain) loss | 280 |  |  | (57 | ) |  | 290 |  |  | (77 | )
Fuel and purchased energy expense | 1,647 |  |  | 1,369 |  |  | 3,415 |  |  | 3,139 |
Operating and maintenance expense | 245 |  |  | 242 |  |  | 484 |  |  | 517 |
Depreciation and amortization expense | 175 |  |  | 186 |  |  | 349 |  |  | 387 |
General and other administrative expense | 34 |  |  | 31 |  |  | 66 |  |  | 91 |
Other operating expenses | 19 |  |  | 19 |  |  | 38 |  |  | 56 |
Total operating expenses | 2,120 |  |  | 1,847 |  |  | 4,352 |  |  | 4,190 |
Impairment losses | 40 |  |  | — |  |  | 55 |  |  | — |
(Income) from unconsolidated subsidiaries | (5 | ) |  | (5 | ) |  | (11 | ) |  | (11 | )
Income from operations | 444 |  |  | 417 |  |  | 802 |  |  | 89 |
Interest expense | 157 |  |  | 157 |  |  | 306 |  |  | 308 |
(Gain) loss on extinguishment of debt | 3 |  |  | — |  |  | (1 | ) |  | — |
Other (income) expense, net | 5 |  |  | 62 |  |  | 28 |  |  | 69 |
Income (loss) before income taxes | 279 |  |  | 198 |  |  | 469 |  |  | (288 | )
Income tax expense (benefit) | 9 |  |  | (158 | ) |  | 19 |  |  | (50 | )
Net income (loss) | 270 |  |  | 356 |  |  | 450 |  |  | (238 | )
Net income attributable to the noncontrolling interest | (4 | ) |  | (4 | ) |  | (9 | ) |  | (8 | )
Net income (loss) attributable to Calpine | $ | 266 |  |  | $ | 352 |  |  | $ | 441 |  |  | $ | (246 | )

The accompanying notes are an integral part of these Consolidated Condensed Financial Statements.
1

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited)

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2019 |  | 2018 |  | 2019 |  | 2018
| (in millions)
Net income (loss) | $ | 270 |  |  | $ | 356 |  |  | $ | 450 |  |  | $ | (238 | )
Cash flow hedging activities: |  |  |  |  |  |  |
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income (loss) | (29 | ) |  | 15 |  |  | (52 | ) |  | 63 |
Reclassification adjustment for (gain) loss on cash flow hedges realized in net income (loss) | (3 | ) |  | — |  |  | (5 | ) |  | 7 |
Foreign currency translation gain (loss) | 1 |  |  | (2 | ) |  | 3 |  |  | (8 | )
Income tax benefit (expense) | 1 |  |  | 7 |  |  | 1 |  |  | (4 | )
Other comprehensive income (loss) | (30 | ) |  | 20 |  |  | (53 | ) |  | 58 |
Comprehensive income (loss) | 240 |  |  | 376 |  |  | 397 |  |  | (180 | )
Comprehensive (income) attributable to the noncontrolling interest | (3 | ) |  | (4 | ) |  | (8 | ) |  | (10 | )
Comprehensive income (loss) attributable to Calpine | $ | 237 |  |  | $ | 372 |  |  | $ | 389 |  |  | $ | (190 | )

The accompanying notes are an integral part of these Consolidated Condensed Financial Statements.
2

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited)

|  | June 30, |  | December 31,
|  | 2019 |  | 2018
|  | (in millions, except share and per share amounts)
ASSETS |  |  |  |
Current assets: |  |  |  |
Cash and cash equivalents ($33 and $43 attributable to VIEs) |  | $ | 297 |  |  | $ | 205 |
Accounts receivable, net of allowance of $8 and $9 |  | 806 |  |  | 1,022 |
Inventories |  | 541 |  |  | 525 |
Margin deposits and other prepaid expense |  | 276 |  |  | 315 |
Restricted cash, current ($108 and $90 attributable to VIEs) |  | 182 |  |  | 167 |
Derivative assets, current |  | 202 |  |  | 142 |
Current assets held for sale |  | 335 |  |  | — |
Other current assets |  | 60 |  |  | 43 |
Total current assets |  | 2,699 |  |  | 2,419 |
Property, plant and equipment, net ($3,873 and $3,919 attributable to VIEs) |  | 12,051 |  |  | 12,442 |
Restricted cash, net of current portion ($48 and $33 attributable to VIEs) |  | 80 |  |  | 34 |
Investments in unconsolidated subsidiaries |  | 71 |  |  | 76 |
Long-term derivative assets |  | 213 |  |  | 160 |
Goodwill |  | 242 |  |  | 242 |
Intangible assets, net |  | 370 |  |  | 412 |
Other assets ($100 and $30 attributable to VIEs) |  | 483 |  |  | 277 |
Total assets |  | $ | 16,209 |  |  | $ | 16,062 |
LIABILITIES & STOCKHOLDER’S EQUITY |  |  |  |
Current liabilities: |  |  |  |
Accounts payable |  | $ | 695 |  |  | $ | 958 |
Accrued interest payable |  | 98 |  |  | 96 |
Debt, current portion ($213 and $201 attributable to VIEs) |  | 263 |  |  | 637 |
Derivative liabilities, current |  | 165 |  |  | 303 |
Current liabilitites held for sale |  | 22 |  |  | — |
Other current liabilities ($71 and $36 attributable to VIEs) |  | 470 |  |  | 489 |
Total current liabilities |  | 1,713 |  |  | 2,483 |
Debt, net of current portion ($1,889 and $1,978 attributable to VIEs) |  | 10,461 |  |  | 10,148 |
Long-term derivative liabilities |  | 119 |  |  | 140 |
Other long-term liabilities ($73 and $36 attributable to VIEs) |  | 463 |  |  | 235 |
Total liabilities |  | 12,756 |  |  | 13,006 |
Commitments and contingencies (see Note 11) |  |  |  |
Stockholder’s equity: |  |  |  |
Common stock, $0.001 par value per share; authorized 5,000 shares, 105.2 shares issued and outstanding |  | — |  |  | — |
Additional paid-in capital |  | 9,584 |  |  | 9,582 |
Accumulated deficit |  | (6,101 | ) |  | (6,542 | )
Accumulated other comprehensive loss |  | (129 | ) |  | (77 | )
Total Calpine stockholder’s equity |  | 3,354 |  |  | 2,963 |
Noncontrolling interest |  | 99 |  |  | 93 |
Total stockholder’s equity |  | 3,453 |  |  | 3,056 |
Total liabilities and stockholder’s equity |  | $ | 16,209 |  |  | $ | 16,062 |

The accompanying notes are an integral part of these Consolidated Condensed Financial Statements.
3

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF STOCKHOLDER’S EQUITY
For the Three and Six Months Ended June 30, 2019 and 2018
(Unaudited)
(in millions)

| Common Stock |  | Treasury Stock |  | Additional Paid-In Capital |  | Accumulated Deficit |  | Accumulated Other Comprehensive Loss |  | Noncontrolling Interest |  | Total Stockholder’s Equity
Balance, December 31, 2018 | $ | — |  |  | $ | — |  |  | $ | 9,582 |  |  | $ | (6,542 | ) |  | $ | (77 | ) |  | $ | 93 |  |  | $ | 3,056 |
Net income | — |  |  | — |  |  | — |  |  | 175 |  |  | — |  |  | 5 |  |  | 180 |
Other comprehensive loss | — |  |  | — |  |  | — |  |  | — |  |  | (23 | ) |  | — |  |  | (23 | )
Other | — |  |  | — |  |  | 2 |  |  | — |  |  | — |  |  | (2 | ) |  | — |
Balance, March 31, 2019 | $ | — |  |  | $ | — |  |  | $ | 9,584 |  |  | $ | (6,367 | ) |  | $ | (100 | ) |  | $ | 96 |  |  | $ | 3,213 |
Net income | — |  |  | — |  |  | — |  |  | 266 |  |  | — |  |  | 4 |  |  | 270 |
Other comprehensive loss | — |  |  | — |  |  | — |  |  | — |  |  | (29 | ) |  | (1 | ) |  | (30 | )
Balance, June 30, 2019 | $ | — |  |  | $ | — |  |  | $ | 9,584 |  |  | $ | (6,101 | ) |  | $ | (129 | ) |  | $ | 99 |  |  | $ | 3,453 |

| Common Stock |  | Treasury Stock |  | Additional Paid-In Capital |  | Accumulated Deficit |  | Accumulated Other Comprehensive Loss |  | Noncontrolling Interest |  | Total Stockholder’s Equity
Balance, December 31, 2017 | $ | — |  |  | $ | (15 | ) |  | $ | 9,661 |  |  | $ | (6,552 | ) |  | $ | (106 | ) |  | $ | 79 |  |  | $ | 3,067 |
Treasury stock transactions | — |  |  | (7 | ) |  | — |  |  | — |  |  | — |  |  | — |  |  | (7 | )
Stock-based compensation expense | — |  |  | — |  |  | 41 |  |  | — |  |  | — |  |  | — |  |  | 41 |
Effects of the Merger | — |  |  | 22 |  |  | (100 | ) |  | — |  |  | — |  |  | — |  |  | (78 | )
Dividends | — |  |  | — |  |  | (20 | ) |  | — |  |  | — |  |  | — |  |  | (20 | )
Contribution from the noncontrolling interest | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 2 |  |  | 2 |
Distribution to the noncontrolling interest | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (2 | ) |  | (2 | )
Net income (loss) | — |  |  | — |  |  | — |  |  | (598 | ) |  | — |  |  | 4 |  |  | (594 | )
Other comprehensive income | — |  |  | — |  |  | — |  |  | — |  |  | 36 |  |  | 2 |  |  | 38 |
Balance, March 31, 2018 | $ | — |  |  | $ | — |  |  | $ | 9,582 |  |  | $ | (7,150 | ) |  | $ | (70 | ) |  | $ | 85 |  |  | $ | 2,447 |
Distribution to the noncontrolling interest | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (1 | ) |  | (1 | )
Net income | — |  |  | — |  |  | — |  |  | 352 |  |  | — |  |  | 4 |  |  | 356 |
Other comprehensive income | — |  |  | — |  |  | — |  |  | — |  |  | 20 |  |  | — |  |  | 20 |
Balance, June 30, 2018 | $ | — |  |  | $ | — |  |  | $ | 9,582 |  |  | $ | (6,798 | ) |  | $ | (50 | ) |  | $ | 88 |  |  | $ | 2,822 |

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)

|  | Six Months Ended June 30,
|  | 2019 |  | 2018
|  | (in millions)
Cash flows from operating activities: |  |  |  |
Net income (loss) |  | $ | 450 |  |  | $ | (238 | )
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |  |  |  |
Depreciation and amortization(1) |  | 398 |  |  | 443 |
Deferred income taxes |  | 16 |  |  | 36 |
Impairment losses |  | 55 |  |  | — |
Mark-to-market activity, net |  | (231 | ) |  | 180 |
(Income) from unconsolidated subsidiaries |  | (11 | ) |  | (11 | )
Return on investments from unconsolidated subsidiaries |  | 11 |  |  | 5 |
Stock-based compensation expense |  | — |  |  | 57 |
Other |  | (3 | ) |  | 9 |
Change in operating assets and liabilities: |  |  |  |
Accounts receivable |  | 215 |  |  | (8 | )
Accounts payable |  | (269 | ) |  | (11 | )
Margin deposits and other prepaid expense |  | 40 |  |  | (90 | )
Other assets and liabilities, net |  | (61 | ) |  | (242 | )
Derivative instruments, net |  | (91 | ) |  | (74 | )
Net cash provided by operating activities |  | 519 |  |  | 56 |
Cash flows from investing activities: |  |  |  |
Purchases of property, plant and equipment |  | (304 | ) |  | (231 | )
Other |  | (11 | ) |  | (3 | )
Net cash used in investing activities |  | (315 | ) |  | (234 | )
Cash flows from financing activities: |  |  |  |
Borrowings under First Lien Term Loans |  | 941 |  |  | — |
Repayment of CCFC Term Loan and First Lien Term Loans |  | (942 | ) |  | (21 | )
Repurchases of Senior Unsecured Notes |  | (44 | ) |  | — |
Borrowings under Corporate Revolving Facility |  | 220 |  |  | 475 |
Repayments of Corporate Revolving Facility |  | (175 | ) |  | (200 | )
Borrowings from project financing, notes payable and other |  | 34 |  |  | — |
Repayments of project financing, notes payable and other |  | (77 | ) |  | (66 | )
Distribution to noncontrolling interest holder |  | — |  |  | (3 | )
Financing costs |  | (8 | ) |  | (12 | )
Stock repurchases |  | — |  |  | (79 | )
Shares repurchased for tax withholding on stock-based awards |  | — |  |  | (7 | )
Dividends paid(2) |  | — |  |  | (18 | )
Net cash (used in) provided by financing activities |  | (51 | ) |  | 69 |
Net increase (decrease) in cash, cash equivalents and restricted cash |  | 153 |  |  | (109 | )
Cash, cash equivalents and restricted cash, beginning of period |  | 406 |  |  | 443 |
Cash, cash equivalents and restricted cash, end of period(3) |  | $ | 559 |  |  | $ | 334 |

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)

|  | Six Months Ended June 30,
|  | 2019 |  | 2018
|  | (in millions)
Cash paid during the period for: |  |  |  |
Interest, net of amounts capitalized |  | $ | 283 |  |  | $ | 284 |
Income taxes |  | $ | 8 |  |  | $ | 10 |
Supplemental disclosure of non-cash investing and financing activities: |  |  |  |
Change in capital expenditures included in account payable |  | $ | 19 |  |  | $ | (14 | )
Plant tax settlement offset in prepaid assets |  | $ | (4 | ) |  | $ | — |
Asset retirement obligation adjustment offset in operating activities |  | $ | (10 | ) |  | $ | — |
Garrison Energy Center, RockGen Energy Center and other property, plant and equipment, net, classified as current assets held for sale |  | $ | (335 | ) |  | $ | — |
Garrison Energy Center finance lease liability classified as current liabilities held for sale |  | $ | 22 |  |  | $ | — |

____________

(1) | Includes amortization recorded in Commodity revenue and Commodity expense associated with intangible assets and amortization recorded in interest expense associated with debt issuance costs and discounts.

(2) | Subsequent to the consummation of the Merger on March 8, 2018, we paid certain Merger-related costs incurred by CPN Management, our direct parent.

(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.

The accompanying notes are an integral part of these Consolidated Condensed Financial Statements.
6

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
June 30, 2019
(Unaudited)

1. | Basis of Presentation and Summary of Significant Accounting Policies

We are a power generation company engaged in the ownership and operation of primarily natural gas-fired and geothermal power plants in North America. 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 U.S. We sell power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. We continue to focus on providing products and services that are beneficial to our wholesale and retail customers. We purchase primarily natural gas and some fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We also purchase power for sale to our customers and purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas, power, environmental product, fuel oil and other physical and financial commodity contracts to hedge certain business risks and optimize our portfolio of power plants.
Basis of Interim Presentation — The accompanying unaudited, interim Consolidated Condensed Financial Statements of Calpine Corporation, a Delaware corporation, and consolidated subsidiaries have been prepared pursuant to the rules and regulations of the SEC. 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 financial statements prepared in accordance with U.S. GAAP, have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, these financial statements should be read in conjunction with our audited Consolidated Financial Statements for the year ended December 31, 2018, included in our 2018 Form 10-K. 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 tax 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, liabilities, revenues, expenses and related disclosures included in our Consolidated Condensed Financial Statements. Actual results could differ from those estimates.
Reclassifications — We have reclassified certain prior period amounts for comparative purposes. These reclassifications did not have a material effect on our financial condition, results of operations or cash flows.
Cash and Cash Equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have cash and cash equivalents held in non-corporate accounts relating to certain project finance facilities and lease agreements that require us 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 in such accounts is limited, at least temporarily, to the operations of the respective projects.
Restricted Cash — Certain of our debt agreements, lease agreements or other operating 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 in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent and major maintenance or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. 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 on our Consolidated Condensed Balance Sheets.
7

The table below represents the components of our restricted cash as of June 30, 2019 and December 31, 2018 (in millions):

| June 30, 2019 |  | December 31, 2018
| Current |  | Non-Current |  | Total |  | Current |  | Non-Current |  | Total
Debt service | $ | 51 |  |  | $ | 8 |  |  | $ | 59 |  |  | $ | 13 |  |  | $ | 8 |  |  | $ | 21 |
Construction/major maintenance | 9 |  |  | 39 |  |  | 48 |  |  | 23 |  |  | 24 |  |  | 47 |
Security/project/insurance | 112 |  |  | 31 |  |  | 143 |  |  | 120 |  |  | — |  |  | 120 |
Other | 10 |  |  | 2 |  |  | 12 |  |  | 11 |  |  | 2 |  |  | 13 |
Total | $ | 182 |  |  | $ | 80 |  |  | $ | 262 |  |  | $ | 167 |  |  | $ | 34 |  |  | $ | 201 |

Business Interruption Proceeds — We record business interruption insurance proceeds in operating revenues when they are realizable. We recorded approximately $14 million of business interruption proceeds for each of the three and six months ended June 30, 2018. We have not recorded any business interruption insurance proceeds during the three and six months ended June 30, 2019.
Property, Plant and Equipment, Net — At June 30, 2019 and December 31, 2018, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):

| June 30, 2019 |  | December 31, 2018 |  | Depreciable Lives
Buildings, machinery and equipment | $ | 16,522 |  |  | $ | 16,400 |  |  | 1.5 | – | 50 | Years
Geothermal properties | 1,509 |  |  | 1,501 |  |  | 13 | – | 58 | Years
Other | 269 |  |  | 286 |  |  | 3 | – | 50 | Years
| 18,300 |  |  | 18,187 |  |  |  |  |  |
Less: Accumulated depreciation | 6,860 |  |  | 6,832 |  |  |  |  |  |
| 11,440 |  |  | 11,355 |  |  |  |  |  |
Land | 128 |  |  | 121 |  |  |  |  |  |
Construction in progress | 483 |  |  | 966 |  |  |  |  |  |
Property, plant and equipment, net | $ | 12,051 |  |  | $ | 12,442 |  |  |  |  |  |

Capitalized Interest — The total amount of interest capitalized was $1 million and $7 million during the three months ended June 30, 2019 and 2018, respectively, and $8 million and $14 million during the six months ended June 30, 2019 and 2018, respectively.
Goodwill — We have not recorded any impairment losses or changes in the carrying amount of our goodwill during the three and six months ended June 30, 2019 and 2018.
New Accounting Standards and Disclosure Requirements
Leases — On January 1, 2019, we adopted Accounting Standards Update 2016-02, “Leases” (“Topic 842”). The comprehensive new lease standard superseded all existing lease guidance. The standard requires that a lessee should recognize a right-of-use asset and a lease liability for substantially all operating leases based on the present value of the minimum rental payments. For lessors, the accounting for leases under Topic 842 remained substantially unchanged. The standard also requires expanded disclosures surrounding leases. We adopted the standards under Topic 842 using the modified retrospective method and elected a number of the practical expedients in our implementation of Topic 842. The key change that affected us relates to our accounting for operating leases for which we are the lessee that were historically off-balance sheet. The impact of adopting the standards resulted in the recognition of a right-of-use asset and lease obligation liability of $191 million on our Consolidated Condensed Balance Sheet on January 1, 2019, exclusive of previously recognized lease balances. The implementation of Topic 842 did not have a material effect on our Consolidated Condensed Statement of Operations or Consolidated Condensed Statement of Cash Flows for the six months ended June 30, 2019. See Note 3 for a discussion of the practical expedients we elected and additional disclosures required by Topic 842.
Derivatives and Hedging — In August 2017, the FASB issued Accounting Standards Update 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” The standard better aligns an entity’s hedging activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results in the financial statements. The standard will prospectively make hedge
8

accounting easier to apply to hedging activities and also enhances disclosure requirements for how hedge transactions are reflected in the financial statements when hedge accounting is elected. We adopted Accounting Standards Update 2017-12 in the first quarter of 2019 which did not have a material effect on our financial condition, results of operations or cash flows.
Fair Value Measurements — In August 2018, the FASB issued Accounting Standards Update 2018-13, “Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement.” The standard removes, modifies and adds disclosures about fair value measurements and is effective for fiscal years beginning after December 15, 2019. The changes required by this standard to remove or modify disclosures may be early adopted with adoption of the additional disclosures required by this standard delayed until their effective date. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.

2. | Revenue from Contracts with Customers

Disaggregation of Revenues with Customers
The following tables represent a disaggregation of our revenue for the three and six months ended June 30, 2019 and 2018 by reportable segment (in millions). See Note 13 for a description of our segments.

| Three Months Ended June 30, 2019
| Wholesale |  |  |  |  |  |
| West |  | Texas |  | East |  | Retail |  | Elimination |  | Total
Third-Party: |  |  |  |  |  |  |  |  |  |  |
Energy & other products | $ | 145 |  |  | $ | 318 |  |  | $ | 124 |  |  | $ | 413 |  |  | $ | — |  |  | $ | 1,000 |
Capacity | 36 |  |  | 33 |  |  | 154 |  |  | — |  |  | — |  |  | 223 |
Revenues relating to physical or executory contracts – third-party | $ | 181 |  |  | $ | 351 |  |  | $ | 278 |  |  | $ | 413 |  |  | $ | — |  |  | $ | 1,223 |
Affiliate(1): | $ | 6 |  |  | $ | 14 |  |  | $ | 30 |  |  | $ | 1 |  |  | $ | (51 | ) |  | $ | — |
Revenues relating to leases and derivative instruments(2) |  |  |  |  |  |  |  |  |  |  | $ | 1,376 |
Total operating revenues |  |  |  |  |  |  |  |  |  |  | $ | 2,599 |

| Three Months Ended June 30, 2018
| Wholesale |  |  |  |  |  |
| West |  | Texas |  | East |  | Retail |  | Elimination |  | Total
Third-Party: |  |  |  |  |  |  |  |  |  |  |
Energy & other products | $ | 176 |  |  | $ | 326 |  |  | $ | 120 |  |  | $ | 451 |  |  | $ | — |  |  | $ | 1,073 |
Capacity | 35 |  |  | 23 |  |  | 140 |  |  | — |  |  | — |  |  | 198 |
Revenues relating to physical or executory contracts – third-party | $ | 211 |  |  | $ | 349 |  |  | $ | 260 |  |  | $ | 451 |  |  | $ | — |  |  | $ | 1,271 |
Affiliate(1): | $ | 5 |  |  | $ | 9 |  |  | $ | 21 |  |  | $ | 1 |  |  | $ | (36 | ) |  | $ | — |
Revenues relating to leases and derivative instruments(2) |  |  |  |  |  |  |  |  |  |  | $ | 988 |
Total operating revenues |  |  |  |  |  |  |  |  |  |  | $ | 2,259 |

9

| Six Months Ended June 30, 2019
| Wholesale |  |  |  |  |  |
| West |  | Texas |  | East |  | Retail |  | Elimination |  | Total
Third-Party: |  |  |  |  |  |  |  |  |  |  |
Energy & other products | $ | 437 |  |  | $ | 620 |  |  | $ | 327 |  |  | $ | 825 |  |  | $ | — |  |  | $ | 2,209 |
Capacity | 71 |  |  | 65 |  |  | 331 |  |  | — |  |  | — |  |  | 467 |
Revenues relating to physical or executory contracts – third-party | $ | 508 |  |  | $ | 685 |  |  | $ | 658 |  |  | $ | 825 |  |  | $ | — |  |  | $ | 2,676 |
Affiliate(1): | $ | 17 |  |  | $ | 28 |  |  | $ | 57 |  |  | $ | 4 |  |  | $ | (106 | ) |  | $ | — |
Revenues relating to leases and derivative instruments(2) |  |  |  |  |  |  |  |  |  |  | $ | 2,522 |
Total operating revenues |  |  |  |  |  |  |  |  |  |  | $ | 5,198 |

| Six Months Ended June 30, 2018
| Wholesale |  |  |  |  |  |
| West |  | Texas |  | East |  | Retail |  | Elimination |  | Total
Third-Party: |  |  |  |  |  |  |  |  |  |  |
Energy & other products | $ | 375 |  |  | $ | 630 |  |  | $ | 252 |  |  | $ | 894 |  |  | $ | — |  |  | $ | 2,151 |
Capacity | 54 |  |  | 49 |  |  | 289 |  |  | — |  |  | — |  |  | 392 |
Revenues relating to physical or executory contracts – third-party | $ | 429 |  |  | $ | 679 |  |  | $ | 541 |  |  | $ | 894 |  |  | $ | — |  |  | $ | 2,543 |
Affiliate(1): | $ | 13 |  |  | $ | 13 |  |  | $ | 42 |  |  | $ | 2 |  |  | $ | (70 | ) |  | $ | — |
Revenues relating to leases and derivative instruments(2) |  |  |  |  |  |  |  |  |  |  | $ | 1,725 |
Total operating revenues |  |  |  |  |  |  |  |  |  |  | $ | 4,268 |

___________

(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 that we are required to account for as operating leases and physical and financial commodity derivative contracts, primarily relating to power, natural gas and environmental products. Revenue related to derivative instruments includes revenue recorded in Commodity revenue and mark-to-market gain (loss) within our operating revenues on our Consolidated Condensed Statements of Operations.

Performance Obligations and Contract Balances
At June 30, 2019 and December 31, 2018, deferred revenue balances relating to contracts with our customers were included in other current liabilities on our Consolidated Condensed Balance Sheets and primarily relate to sales of environmental products and capacity. We classify deferred revenue as current or long-term based on the timing of when we expect to recognize revenue. The balance outstanding at June 30, 2019 and December 31, 2018 was $22 million and $14 million, respectively. Revenue recognized during the three months ended June 30, 2019 and 2018, relating to the deferred revenue balance at the beginning of each period was $2 million and $3 million, respectively. Revenue recognized during the six months ended June 30, 2019 and 2018, relating to the deferred revenue balance at the beginning of each period was and $3 million and $9 million, respectively. Revenue recognized each period relating to deferred revenue balances resulted from our performance under the customer contracts. The change in the deferred revenue balance during the three and six months ended June 30, 2019 and 2018 was primarily due to the timing difference of when consideration was received and when the related good or service was transferred.
10

Performance Obligations not yet Satisfied
As of June 30, 2019, we have entered into certain contracts for fixed and determinable amounts with customers under which we have not yet completed our performance obligations which primarily includes agreements for which we are providing capacity from our generating facilities. We have revenues related to the sale of capacity through participation in various ISO capacity auctions estimated based upon cleared volumes and the sale of capacity to our customers of $258 million that will be recognized during the remainder of 2019, and $517 million, $468 million, $249 million and $50 million that will be recognized during the years ending December 31, 2020, 2021, 2022 and 2023, respectively, and $72 million thereafter. Revenues under these contracts will be recognized as we transfer control of the commodities to our customers.

3. | Leases

Accounting for Leases – Lessee
We evaluate contracts for lease accounting at contract inception and assess lease classification at the lease commencement date. For our leases, we recognize a right-of-use asset and corresponding lease obligation liability at the lease commencement date where the lease obligation liability is measured at the present value of the minimum lease payments. For our operating leases, the amortization of the right-of-use asset and the accretion of our lease obligation liability result in a single straight-line expense recognized over the lease term.
We determine the discount rate associated with our operating and finance leases using our incremental borrowing rate at lease commencement. For our operating leases, we use an interest rate commensurate with the interest rate to borrow on a collateralized basis over a similar term with an amount equal to the lease payments. Factors management considers in the calculation of the discount rate include the amount of the borrowing, the lease term including options that are reasonably certain of exercise, the current interest rate environment and the credit rating of the entity. For our finance leases, we use the interest rate commensurate with the interest rate for a project finance borrowing arrangement with a similar collateral package, repayment terms, restrictive covenants and guarantees.
Our operating leases are primarily related to office space for our corporate and regional offices as well as land and operating related leases for our power plants. Additionally, one of our power plants is accounted for as a long-term operating lease. Payments made by Calpine on this lease are recognized on a straight-line basis with capital improvements associated with our leased power plant deemed leasehold improvements that are amortized over the shorter of the term of the lease or the economic life of the capital improvement. Several of our leases contain renewal options held by us to extend the lease term. The inclusion of these renewal periods in the lease term and in the minimum lease payments included in our lease liabilities is dependent on specific facts and circumstances for each lease and whether it is determined to be reasonably certain that we will exercise our option to extend the term. Our office, land and other operating leases do not contain any material restrictive covenants or residual value guarantees.
We have entered into finance leases for certain power plants and related equipment with terms that range up to 30 years (including lease renewal options). The finance leases generally provide for the lessee to pay taxes, maintenance, insurance, and certain other operating costs of the leased property.
In connection with our adoption of Topic 842 on January 1, 2019, we elected certain practical expedients that were available under the new lease standards including:

• | we elected not to separate lease and nonlease components for our current classes of underlying leased assets as the lessee;

• | we did not evaluate existing and expired land easements that were not previously accounted for as leases prior to January 1, 2019; and

• | we did not reassess the classification of leases, the accounting for initial direct costs or whether contractual arrangements contained a lease for all contracts that expired or commenced prior to January 1, 2019.

Further, upon the adoption of Topic 842, we made an accounting policy election to not recognize lease assets and liabilities for leases with a term of 12 months or less. We do not have any material subleases associated with our operating and finance leases.
11

The components of our operating and finance lease expense are as follows for the three and six months ended June 30, 2019 (in millions):

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2019 |  | 2019
Operating Leases |  |  |
Operating lease expense | $ | 12 |  |  | $ | 23 |
Finance Leases |  |  |
Amortization of the right-of-use assets | $ | 1 |  |  | $ | 4 |
Interest expense | 2 |  |  | 4 |
Finance lease expense | $ | 3 |  |  | $ | 8 |
Variable lease expense | $ | 4 |  |  | $ | 5 |
Total lease expense | $ | 19 |  |  | $ | 36 |

The following is a schedule by year of future minimum lease payments associated with our operating and finance leases together with the present value of the net minimum lease payments as of June 30, 2019 (in millions):

| Operating Leases(1)(2) |  | Finance Leases(2)(3)
2019 | $ | 39 |  |  | $ | 8 |
2020 | 20 |  |  | 16 |
2021 | 21 |  |  | 16 |
2022 | 19 |  |  | 16 |
2023 | 18 |  |  | 19 |
Thereafter | 201 |  |  | 33 |
Total minimum lease payments | 318 |  |  | 108 |
Less: Amount representing interest | 108 |  |  | 30 |
Total lease obligation | 210 |  |  | 78 |
Less: current lease obligation | 39 |  |  | 10 |
Long-term lease obligation | $ | 171 |  |  | $ | 68 |

____________

(1) | The lease liabilities associated with our operating leases as of June 30, 2019 are included in other current liabilities and other long-term liabilities on our Consolidated Condensed Balance Sheet.

(2) | Excludes an operating lease obligation of $1 million and a finance lease obligation of $18 million related to Garrison Energy Center which are included in current liabilities held for sale on our Consolidated Condensed Balance Sheet. See Note 4 for further information related to the sale of the Garrison Energy Center.

(3) | The lease liabilities associated with our finance leases as of June 30, 2019 are included in debt, current portion and debt, net of current portion on our Consolidated Condensed Balance Sheet.

12

Supplemental balance sheet information related to our operating and finance leases is as follows as of June 30, 2019 (in millions, except lease term and discount rate):

|  | June 30, 2019(1)
Operating leases(2) |  |
Right-of-use assets associated with operating leases |  | $ | 184 |
Finance leases(3) |  |
Property, plant and equipment, gross |  | $ | 213 |
Accumulated amortization |  | (104 | )
Property, plant and equipment, net |  | $ | 109 |
Weighted average remaining lease term (in years) |  |
Operating leases |  | 15.8 |
Finance leases |  | 7.4 |
Weighted average discount rate |  |
Operating leases |  | 5.1 | %
Finance leases |  | 8.0 | %

____________

(1) | Excludes a right-of-use asset and property, plant and equipment, net of $1 million and $17 million, respectively, related to Garrison Energy Center which are included in current assets held for sale on our Consolidated Condensed Balance Sheet. See Note 4 for further information related to the sale of the Garrison Energy Center.

(2) | The right-of-use assets associated with our operating leases as of June 30, 2019 are included in other assets on our Consolidated Condensed Balance Sheet.

(3) | The right-of-use assets associated with our finance leases as of June 30, 2019 are included in property, plant and equipment, net on our Consolidated Condensed Balance Sheet.

Supplemental cash flow information related to our operating and finance leases is as follows for the period presented (in millions):

|  | Six Month Ended
|  | June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities |  |
Operating cash flows from operating leases |  | $ | 13 |
Operating cash flows from finance leases |  | $ | 4 |
Financing cash flows from finance leases |  | $ | 6 |
Right-of-use assets obtained in exchange for lease obligations: |  |
Operating leases |  | $ | 9 |
Finance leases |  | $ | — |

As of June 30, 2019, we have executed agreements that contain a lease with a future lease commencement date and future lease commitments of $1 million primarily related to an office lease which is scheduled to commence in September 2019.
Accounting for Leases – Lessor
We apply lease accounting to PPAs that meet the definition of a lease and determine lease classification treatment at commencement of the agreement. We currently do not have any contracts which are accounted for as sales-type leases or direct financing leases and all of our leases as the lessor are classified as operating leases. As part of the implementation of Topic 842, we elected the practical expedient to not reassess leases that have commenced prior to January 1, 2019.
13

Revenue from contracts accounted for as operating leases, such as certain tolling agreements, with minimum lease rentals (capacity payments) which vary over time must be levelized. Generally, we levelize these contract revenues on a straight-line basis over the term of the contract. Our operating leases that have commenced contain terms extending through December 2034. These contracts also generally contain variable payment components based on generation volumes or operating efficiency over a period of time. Revenues associated with the variable payments are recognized over time as the goods or services are provided to the lessee. Our operating leases generally do not contain renewal or purchase options or residual value guarantees. We have elected to not separate our lease and non-lease components as the lease components reflect the predominant characteristics of these agreements.
Revenue recognized related to fixed lease payments on our operating leases for the period presented is as follows (in millions):

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2019 |  | 2019
Operating Leases(1) |  |  |
Fixed lease payments | $ | 70 |  |  | $ | 139 |

____________

(1) | Revenues associated with our operating leases are included in Commodity revenue and other revenue on our Consolidated Condensed Statement of Operations.

The total contractual future minimum lease rentals for our contracts that have commenced and are accounted for as operating leases at June 30, 2019, are as follows (in millions):

2019 | $ | 204 |
2020 | 287 |
2021 | 261 |
2022 | 227 |
2023 | 144 |
Thereafter | 284 |
Total | $ | 1,407 |

We do not recognize lease receivables associated with our operating leases as the long-lived assets subject to the lease contracts are recorded on our Consolidated Condensed Balance Sheet and are being depreciated over their estimated useful lives. Amounts recorded on our Consolidated Condensed Balance Sheet associated with the long-lived assets subject to our operating leases as of June 30, 2019 are as follows (in millions):

| June 30, 2019
Assets subject to contracts accounted for as operating leases |
Property, plant and equipment, gross | $ | 3,076 |
Accumulated depreciation | (903 | )
Property, plant and equipment, net(1) | $ | 2,173 |

____________

(1) | Our assets subject to contracts that are accounted for as operating leases primarily consist of our power plants subject to tolling contracts.

We also record lease levelization assets and liabilities for any difference between the timing of the contractual payments made related to our operating lease contracts and revenue recognized on a straight-line basis. These balances are included in current and long-term assets and liabilities on our Consolidated Condensed Balance Sheet.
14

Disclosures for periods prior to the adoption of Topic 842
Lessee
The following is a schedule by year of future minimum lease payments under operating and capital leases as of December 31, 2018 (in millions):

| Operating Leases |  | Capital Leases(1)
2019 | $ | 50 |  |  | $ | 40 |
2020 | 19 |  |  | 40 |
2021 | 20 |  |  | 38 |
2022 | 18 |  |  | 33 |
2023 | 17 |  |  | 27 |
Thereafter | 192 |  |  | 92 |
Total minimum lease payments | $ | 316 |  |  | 270 |
Less: Amount representing interest |  |  | 89 |
Present value of net minimum lease payments |  |  | $ | 181 |

____________

(1) | Includes a failed sale-leaseback transaction related to our Pasadena Power Plant.

At December 31, 2018, the asset balance for our assets under capital leases totaled approximately $715 million with accumulated amortization of $353 million.
Lessor
The total contractual future minimum lease rentals for our contracts accounted for as operating leases at December 31, 2018, are as follows (in millions):

2019 | $ | 342 |
2020 | 261 |
2021 | 257 |
2022 | 224 |
2023 | 141 |
Thereafter | 239 |
Total | $ | 1,464 |

4. | Divestitures

Sale of Garrison Energy Center and RockGen Energy Center
On July 10, 2019, we, through our indirect, wholly owned subsidiaries Calpine Holdings, LLC and Calpine Northbrook Project Holdings, LLC, completed the sale of 100% of our ownership interests in Garrison Energy Center LLC (“Garrison”) and RockGen Energy LLC (“RockGen”) to Cobalt Power, L.L.C. for approximately $360 million, subject to certain working capital adjustments and the execution of financial commodity contracts. Garrison owns the Garrison Energy Center, a 309 MW natural gas-fired, combined-cycle power plant located in Dover, Delaware, and RockGen owns the RockGen Energy Center, a 503 MW natural gas-fired, simple-cycle power plant located in Christiana, Wisconsin. We used the sale proceeds, together with cash on hand, to fund a dividend of $400 million to our parent, CPN Management, LP.
At June 30, 2019, the assets and liabilities of Garrison and RockGen, which are part of our East segment, were classified as current assets and liabilities held for sale on our Consolidated Condensed Balance Sheet consisting primarily of property, plant and equipment, net, and finance leases, respectively. We recorded impairment losses of $40 million and $55 million during the three and six months ended June 30, 2019, respectively, associated with the sale to adjust the carrying value of the assets to reflect fair value less cost to sell.
15

5. | Variable Interest Entities and Unconsolidated Investments

We consolidate all of our VIEs where we have determined that we are the primary beneficiary. There were no changes to our determination of whether we are the primary beneficiary of our VIEs for the six months ended June 30, 2019. See Note 7 in our 2018 Form 10-K for further information regarding our VIEs.
VIE Disclosures
Our consolidated VIEs include natural gas-fired power plants with an aggregate capacity of 7,880 MW and 7,880 MW at June 30, 2019 and December 31, 2018, respectively. For these VIEs, we may provide other operational and administrative support through various affiliate contractual arrangements among the VIEs, Calpine Corporation and its other wholly owned subsidiaries whereby we support the VIE through the reimbursement of costs and/or the purchase and sale of energy. Other than amounts contractually required, we provided support to these VIEs in the form of cash and other contributions of nil during each of the three and six months ended June 30, 2019 and 2018.
OMEC — OMEC has a ten-year tolling agreement with SDG&E, which commenced on October 3, 2009. Under a ground lease agreement, OMEC held a put option to sell the Otay Mesa Energy Center for $280 million to SDG&E, pursuant to the terms and conditions of the agreement, which was exercisable until April 1, 2019 and SDG&E held a call option to purchase the Otay Mesa Energy Center for $377 million, which was exercisable through October 3, 2018. The call option held by SDG&E expired unexercised.
OMEC has executed a new 59-month Resource Adequacy (“RA”) contract with SDG&E, which would commence on October 3, 2019. The RA contract received initial regulatory approval by the California Public Utilities Commission (“CPUC”) on February 21, 2019. This approval was subject to a 30 day appeal period from the date of the issuance of the CPUC decision. On March 27, 2019, an appeal of the CPUC decision was filed with the CPUC, which appeal was denied on August 1, 2019. As a result, we continue to work to commence the RA contract. However, in the event that we are not successful and another alternative is not reached with SDG&E prior to October 3, 2019, OMEC expects to close on the put and transfer the Otay Mesa Energy Center to SDG&E for $280 million on or about October 3, 2019, which transaction could result in a write down of the carrying value of the asset.
On December 19, 2018, we refinanced the project debt associated with OMEC which lowered the aggregate debt balance to $220 million and extended the maturity to August 2024. In the event that the exercise of the OMEC put option is not rescinded, the OMEC project debt will become payable on November 3, 2019.
We have concluded that we are the primary beneficiary of OMEC as we believe the activity that has the most effect on the financial performance of OMEC is operations and maintenance which is controlled by us. As a result, we consolidate OMEC.
Unconsolidated VIEs and Investments in Unconsolidated Subsidiaries
We have a 50% partnership interest in Greenfield LP and in Whitby. Greenfield LP and Whitby are VIEs; however, we do not have the power to direct the most significant activities of these entities and therefore do not consolidate them. Greenfield LP is a limited partnership between certain subsidiaries of ours and of Mitsui & Co., Ltd., which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant located in Ontario, Canada. We and Mitsui & Co., Ltd. each hold a 50% interest in Greenfield LP. Whitby is a limited partnership between certain of our subsidiaries and Atlantic Packaging Ltd., which operates the Whitby facility, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada. We and Atlantic Packaging Ltd. each hold a 50% partnership interest in Whitby.
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. We have determined that we do 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, we have determined that we are not the primary beneficiary of Calpine Receivables because we do 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, we do not consolidate Calpine Receivables in our Consolidated Condensed Financial Statements and use the equity method of accounting to record our net interest in Calpine Receivables.
We account for these entities under the equity method of accounting and include our net equity interest in investments in unconsolidated subsidiaries on our Consolidated Condensed Balance Sheets. At June 30, 2019 and December 31, 2018, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):
16

| Ownership Interest as of June 30, 2019 |  | June 30, 2019 |  | December 31, 2018
Greenfield LP(1) | 50% |  | $ | 56 |  |  | $ | 55 |
Whitby | 50% |  | 10 |  |  | 15 |
Calpine Receivables | 100% |  | 5 |  |  | 6 |
Total investments in unconsolidated subsidiaries |  |  | $ | 71 |  |  | $ | 76 |

____________

(1) | Includes our share of accumulated other comprehensive income/loss related to interest rate hedging instruments associated with our unconsolidated subsidiary Greenfield LP’s debt.

Our risk of loss related to our investments in Greenfield LP and Whitby is limited to our investment balance. Our risk of loss related to our investment in Calpine Receivables is $67 million which consists of our notes receivable from Calpine Receivables at June 30, 2019 and our initial investment associated with Calpine Receivables. See Note 12 for further information associated with our related party activity with Calpine Receivables.
Holders of the debt of our unconsolidated investments do not have recourse to Calpine Corporation and its other subsidiaries; therefore, the debt of our unconsolidated investments is not reflected on our Consolidated Condensed Balance Sheets. At June 30, 2019 and December 31, 2018, Greenfield LP’s debt was approximately $304 million and $301 million, respectively, and based on our pro rata share of our investment in Greenfield LP, our share of such debt would be approximately $152 million and $151 million at June 30, 2019 and December 31, 2018, respectively.
Our equity interest in the net income from our investments in unconsolidated subsidiaries for the three and six months ended June 30, 2019 and 2018, is recorded in (income) from unconsolidated subsidiaries. The following table sets forth details of our (income) from unconsolidated subsidiaries for the periods indicated (in millions):

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2019 |  | 2018 |  | 2019 |  | 2018
Greenfield LP | $ | (4 | ) |  | $ | (2 | ) |  | $ | (6 | ) |  | $ | (4 | )
Whitby | (2 | ) |  | (4 | ) |  | (6 | ) |  | (8 | )
Calpine Receivables | 1 |  |  | 1 |  |  | 1 |  |  | 1 |
Total | $ | (5 | ) |  | $ | (5 | ) |  | $ | (11 | ) |  | $ | (11 | )

Distributions from Greenfield LP were nil during each of the three and six months ended June 30, 2019 and 2018. Distributions from Whitby were nil and $11 million during the three and six months ended June 30, 2019, respectively, and $2 million and $5 million during the three and six months ended June 30, 2018, respectively. We did not have material distributions from our investment in Calpine Receivables for the three and six months ended June 30, 2019 and 2018.
Inland Empire Energy Center Put and Call Options — We held a call option to purchase the Inland Empire Energy Center (a 775 MW natural gas-fired power plant located in California) at predetermined prices from GE that could be exercised between years 2017 and 2024. GE held a put option whereby they could require us to purchase the power plant, if certain plant performance criteria were met by 2025. On February 1, 2019, we entered into an agreement with GE, which among other things, terminated our call option and GE’s put option related to the Inland Empire Energy Center. As per this agreement, we will take ownership of the facility site and certain remaining site infrastructure and equipment after closure and decommissioning of the facility at a future date, until such time GE continues to own, operate and maintain the power plant, including directing any closure activities. As GE continues to direct all such significant activities of the power plant, we have determined that we no longer hold any variable interests in the Inland Empire Energy Center and it is not a VIE to Calpine.
17

6. | Debt

Our debt at June 30, 2019 and December 31, 2018, was as follows (in millions):

| June 30, 2019 |  | December 31, 2018
Senior Unsecured Notes | $ | 2,990 |  |  | $ | 3,036 |
First Lien Term Loans | 2,979 |  |  | 2,976 |
First Lien Notes | 2,402 |  |  | 2,400 |
Project financing, notes payable and other | 1,229 |  |  | 1,264 |
CCFC Term Loan | 971 |  |  | 974 |
Finance lease obligations | 78 |  |  | 105 |
Corporate Revolving Facility | 75 |  |  | 30 |
Subtotal | 10,724 |  |  | 10,785 |
Less: Current maturities | 263 |  |  | 637 |
Total long-term debt | $ | 10,461 |  |  | $ | 10,148 |

Our effective interest rate on our consolidated debt, excluding the effects of capitalized interest and mark-to-market gains (losses) on interest rate hedging instruments, increased to 5.9% for the six months ended June 30, 2019, from 5.7% for the same period in 2018. Since the fourth quarter of 2018, we have cumulatively repurchased $438 million in aggregate principal of our Senior Unsecured Notes for $399 million.
Senior Unsecured Notes
The amounts outstanding under our Senior Unsecured Notes are summarized in the table below (in millions):

| June 30, 2019 |  | December 31, 2018
2023 Senior Unsecured Notes | $ | 1,228 |  |  | $ | 1,227 |
2024 Senior Unsecured Notes | 589 |  |  | 599 |
2025 Senior Unsecured Notes | 1,173 |  |  | 1,210 |
Total Senior Unsecured Notes | $ | 2,990 |  |  | $ | 3,036 |

During the six months ended June 30, 2019, we repurchased $48 million in aggregate principal of our Senior Unsecured Notes for $44 million. In connection with the repurchases, we recorded approximately $4 million in gain on extinguishment of debt.
First Lien Term Loans
The amounts outstanding under our senior secured First Lien Term Loans are summarized in the table below (in millions):

| June 30, 2019 |  | December 31, 2018
2019 First Lien Term Loan | $ | — |  |  | $ | 389 |
2023 First Lien Term Loans | 535 |  |  | 1,059 |
2024 First Lien Term Loan | 1,522 |  |  | 1,528 |
2026 First Lien Term Loan | 922 |  |  | — |
Total First Lien Term Loans | $ | 2,979 |  |  | $ | 2,976 |

On April 5, 2019, we entered into a $950 million first lien senior secured term loan which bears interest, at our option, at either (i) the Base Rate, equal to the highest of (a) the Federal Funds Effective Rate plus 0.50% per annum, (b) the Prime Rate or (c) the Eurodollar Rate for a one month interest period plus 1.0% (in each case, as such terms are defined in the credit agreement), plus an applicable margin of 1.75%, or (ii) LIBOR plus 2.75% per annum (with a 0% LIBOR floor) and matures on April 5, 2026. An aggregate amount equal to 0.25% of the aggregate principal amount of the 2026 First Lien Term Loan is payable at the end of each quarter with the remaining balance payable on the maturity date. We paid an upfront fee of an amount equal to 1.0% of the aggregate principal amount of the 2026 First Lien Term Loan, which is structured as original issue discount and recorded approximately $7 million in debt issuance costs during the second quarter of 2019 related to the issuance of our 2026 First Lien
18

Term Loan. The 2026 First Lien Term Loan contains substantially similar covenants, qualifications, exceptions and limitations as our First Lien Term Loans and First Lien Notes. We used the proceeds from our 2026 First Lien Term Loan to repay our 2019 First Lien Term Loan and a portion of our 2023 First Lien Term Loans with a maturity date in January 2023 and recorded approximately $3 million in loss on extinguishment of debt during the second quarter of 2019 associated with the repayment.
First Lien Notes
The amounts outstanding under our senior secured First Lien Notes are summarized in the table below (in millions):

| June 30, 2019 |  | December 31, 2018
2022 First Lien Notes | $ | 744 |  |  | $ | 743 |
2024 First Lien Notes | 487 |  |  | 486 |
2026 First Lien Notes | 1,171 |  |  | 1,171 |
Total First Lien Notes | $ | 2,402 |  |  | $ | 2,400 |

Project Financing, Notes Payable and Other
On January 29, 2019, Pacific Gas and Electric Company (“PG&E”) and PG&E Corporation each filed voluntary petitions for relief under Chapter 11. Our power plants that sell energy and energy-related products to PG&E through PPAs, include Russell City Energy Center and Los Esteros Critical Energy Facility. Since the bankruptcy filing, we have received all material payments under the PPAs, either directly or through the application of collateral. As a result of PG&E’s bankruptcy, we are currently unable to make distributions from our Russell City and Los Esteros projects in accordance with the terms of the project debt agreements associated with each related project. In July 2019, we executed forbearance agreements associated with the Russell City and Los Esteros project debt agreements, under which the lenders have agreed to forbear enforcement of their rights and remedies, including the ability to accelerate the repayment of borrowings outstanding, otherwise arising because PG&E did not assume our PPAs during the first 180 days of PG&E’s bankruptcy proceeding. The forbearance agreements are effective for rolling 90-day periods, so long as we continue to meet certain conditions, including that the PPAs have not been rejected and there are no other defaults under the project debt agreements or the forbearance agreements. We may be required to reclassify $362 million of Russell City and Los Esteros long-term project debt outstanding at June 30, 2019 to a current liability in a future period. We continue to monitor the bankruptcy proceedings and are assessing our options.
In the event that the exercise of the OMEC put option is not rescinded, the OMEC project debt will become payable on November 3, 2019. See Note 5 for further information related to the OMEC put option.
Corporate Revolving Facility and Other Letter of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at June 30, 2019 and December 31, 2018 (in millions):

| June 30, 2019 |  | December 31, 2018
Corporate Revolving Facility(1) | $ | 585 |  |  | $ | 693 |
CDHI(2) | 30 |  |  | 251 |
Various project financing facilities | 227 |  |  | 228 |
Other corporate facilities(3) | 293 |  |  | 193 |
Total | $ | 1,135 |  |  | $ | 1,365 |

____________

(1) | The Corporate Revolving Facility represents our primary revolving facility. On April 5, 2019, we amended our Corporate Revolving Facility to increase the capacity by approximately $330 million from $1.69 billion to approximately $2.02 billion.

(2) | Pursuant to the terms and conditions of the CDHI credit agreement, the capacity under the CDHI letter of credit facility was reduced to $125 million on June 28, 2019. The decrease in capacity did not have a material effect on our liquidity as alternative sources of liquidity are available.

(3) | We have three unsecured letter of credit facilities with two third-party financial institutions totaling approximately $300 million at June 30, 2019.

19

Fair Value of Debt
We record our 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 our debt instruments at June 30, 2019 and December 31, 2018 (in millions):

| June 30, 2019 |  | December 31, 2018
| Fair Value |  | Carrying Value |  | Fair Value |  | Carrying Value
Senior Unsecured Notes | $ | 3,011 |  |  | $ | 2,990 |  |  | $ | 2,803 |  |  | $ | 3,036 |
First Lien Term Loans | 3,013 |  |  | 2,979 |  |  | 2,877 |  |  | 2,976 |
First Lien Notes | 2,462 |  |  | 2,402 |  |  | 2,299 |  |  | 2,400 |
Project financing, notes payable and other(1) | 1,136 |  |  | 1,153 |  |  | 1,209 |  |  | 1,188 |
CCFC Term Loan | 980 |  |  | 971 |  |  | 938 |  |  | 974 |
Corporate Revolving Facility | 75 |  |  | 75 |  |  | 30 |  |  | 30 |
Total | $ | 10,677 |  |  | $ | 10,570 |  |  | $ | 10,156 |  |  | $ | 10,604 |

____________

(1) | Excludes an agreement that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.

Our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes, CCFC Term Loan and Corporate Revolving Facility are categorized as level 2 within the fair value hierarchy. Our project financing, notes payable and other debt instruments are categorized as level 3 within the fair value hierarchy. We do not have any debt instruments with fair value measurements categorized as level 1 within the fair value hierarchy.

7. | Assets and Liabilities with Recurring Fair Value Measurements

Cash Equivalents — Highly liquid investments which meet the definition of cash equivalents, primarily investments in money market accounts and other interest-bearing accounts, are included in both our cash and cash equivalents and our restricted cash on our Consolidated Condensed Balance Sheets. Certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. We do 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 of our cash equivalents are classified within level 1 of the fair value hierarchy.
Derivatives — 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; our credit standing and that of our counterparties and customers for energy commodity derivatives; and prevailing interest rates for our interest rate hedging 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 our financial statements in the future.
We utilize market data, such as pricing services and broker quotes, and assumptions that we believe market participants would use in pricing our assets or liabilities including assumptions about the risks inherent to the inputs in the valuation technique. These inputs can be either 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 our assessment of fair value. We use other qualitative assessments to determine the level of activity in any given market. We primarily apply the market approach and income approach for recurring fair value measurements and utilize what we believe to be the best available information. We utilize valuation techniques that seek to maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the observability of those inputs.
The fair value of our derivatives includes consideration of our credit standing, the credit standing of our counterparties and customers and the effect of credit enhancements, if any. We have also recorded credit reserves in the determination of fair value based on our expectation of how market participants would determine fair value. Such valuation adjustments are generally based on market evidence, if available, or our best estimate.
Our level 1 fair value derivative instruments primarily consist of power and natural gas swaps, futures and options traded on the NYMEX or Intercontinental Exchange.
Our level 2 fair value derivative instruments primarily consist of interest rate hedging instruments and OTC power and natural gas forwards for which market-based pricing inputs in the principal or most advantageous market are representative of
20

executable prices for market participants. These inputs are observable at commonly quoted intervals for substantially the full term of the instruments. In certain instances, our level 2 derivative instruments may utilize models to measure fair value. These models are industry-standard models, including the Black-Scholes option-pricing model, that incorporate various assumptions, including quoted interest rates, correlation, volatility, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Our 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. Our valuation models may incorporate historical correlation information and extrapolate available broker and other information to future periods.
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. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect our estimate of the fair value of our assets and liabilities and their placement within the fair value hierarchy levels. The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2019 and December 31, 2018, by level within the fair value hierarchy:

| Assets and Liabilities with Recurring Fair Value Measures as of June 30, 2019
| Level 1 |  | Level 2 |  | Level 3 |  | Total
| (in millions)
Assets: |  |  |  |  |  |  |
Cash equivalents(1) | $ | 165 |  |  | $ | — |  |  | $ | — |  |  | $ | 165 |
Commodity instruments: |  |  |  |  |  |  |
Commodity exchange traded derivatives contracts | 1,089 |  |  | — |  |  | — |  |  | 1,089 |
Commodity forward contracts(2) | — |  |  | 350 |  |  | 322 |  |  | 672 |
Interest rate hedging instruments | — |  |  | 6 |  |  | — |  |  | 6 |
Effect of netting and allocation of collateral(3)(4) | (1,089 | ) |  | (243 | ) |  | (20 | ) |  | (1,352 | )
Total assets | $ | 165 |  |  | $ | 113 |  |  | $ | 302 |  |  | $ | 580 |
Liabilities: |  |  |  |  |  |  |
Commodity instruments: |  |  |  |  |  |  |
Commodity exchange traded derivatives contracts | $ | 1,179 |  |  | $ | — |  |  | $ | — |  |  | $ | 1,179 |
Commodity forward contracts(2) | — |  |  | 474 |  |  | 96 |  |  | 570 |
Interest rate hedging instruments | — |  |  | 33 |  |  | — |  |  | 33 |
Effect of netting and allocation of collateral(3)(4) | (1,179 | ) |  | (298 | ) |  | (21 | ) |  | (1,498 | )
Total liabilities | $ | — |  |  | $ | 209 |  |  | $ | 75 |  |  | $ | 284 |

21

| Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2018
| Level 1 |  | Level 2 |  | Level 3 |  | Total
| (in millions)
Assets: |  |  |  |  |  |  |
Cash equivalents(1) | $ | 168 |  |  | $ | — |  |  | $ | — |  |  | $ | 168 |
Commodity instruments: |  |  |  |  |  |  |
Commodity exchange traded derivatives contracts | 933 |  |  | — |  |  | — |  |  | 933 |
Commodity forward contracts(2) | — |  |  | 338 |  |  | 212 |  |  | 550 |
Interest rate hedging instruments | — |  |  | 40 |  |  | — |  |  | 40 |
Effect of netting and allocation of collateral(3)(4) | (933 | ) |  | (262 | ) |  | (26 | ) |  | (1,221 | )
Total assets | $ | 168 |  |  | $ | 116 |  |  | $ | 186 |  |  | $ | 470 |
Liabilities: |  |  |  |  |  |  |
Commodity instruments: |  |  |  |  |  |  |
Commodity exchange traded derivatives contracts | $ | 932 |  |  | $ | — |  |  | $ | — |  |  | $ | 932 |
Commodity forward contracts(2) | — |  |  | 549 |  |  | 220 |  |  | 769 |
Interest rate hedging instruments | — |  |  | 10 |  |  | — |  |  | 10 |
Effect of netting and allocation of collateral(3)(4) | (932 | ) |  | (310 | ) |  | (26 | ) |  | (1,268 | )
Total liabilities | $ | — |  |  | $ | 249 |  |  | $ | 194 |  |  | $ | 443 |

___________

(1) | At June 30, 2019 and December 31, 2018, we had cash equivalents of $16 million and $23 million included in cash and cash equivalents and $149 million and $145 million included in restricted cash, respectively.

(2) | Includes OTC swaps and options.

(3) | We offset 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 8 for further discussion of our 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 $90 million, $55 million and $1 million, respectively, at June 30, 2019. Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $(1) million, $48 million and nil, respectively, at December 31, 2018.

22

At June 30, 2019 and December 31, 2018, the derivative instruments classified as level 3 primarily included commodity contracts, which are classified as level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net derivative position classified as level 3 is predominantly driven by market commodity prices. The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at June 30, 2019 and December 31, 2018:

|  | Quantitative Information about Level 3 Fair Value Measurements |
|  | June 30, 2019 |
|  | Fair Value, Net Asset |  |  |  | Significant Unobservable |  |  |  |  |
|  | (Liability) |  | Valuation Technique |  | Input |  | Range
|  | (in millions) |  |  |  |  |  |  |  |  |
Power Contracts(1) |  | $ | 190 |  |  | Discounted cash flow |  | Market price (per MWh) |  | $ | 7.09 |  | — | $123.34 | /MWh
Power Congestion Products |  | $ | 18 |  |  | Discounted cash flow |  | Market price (per MWh) |  | $ | (8.63 | ) | — | $11.48 | /MWh
Natural Gas Contracts |  | $ | 6 |  |  | Discounted cash flow |  | Market price (per MMBtu) |  | $ | 0.61 |  | — | $9.75 | /MMBtu
|  | December 31, 2018 |
|  | Fair Value, Net Asset |  |  |  | Significant Unobservable |  |  |  |  |
|  | (Liability) |  | Valuation Technique |  | Input |  | Range
|  | (in millions) |  |  |  |  |  |  |  |  |
Power Contracts(1) |  | $ | 36 |  |  | Discounted cash flow |  | Market price (per MWh) |  | $ | 2.12 |  | — | $227.98 | /MWh
Power Congestion Products |  | $ | 26 |  |  | Discounted cash flow |  | Market price (per MWh) |  | $ | (11.71 | ) | — | $11.88 | /MWh
Natural Gas Contracts |  | $ | (73 | ) |  | Discounted cash flow |  | Market price (per MMBtu) |  | $ | 0.75 |  | — | $8.87 | /MMBtu

___________

(1) | Power contracts include power and heat rate instruments classified as level 3 in the fair value hierarchy.

The following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the periods indicated (in millions):

|  | Three Months Ended June 30, |  | Six Months Ended June 30,
|  | 2019 |  | 2018 |  | 2019 |  | 2018
Balance, beginning of period |  | $ | 105 |  |  | $ | 129 |  |  | $ | (8 | ) |  | $ | 197 |
Realized and mark-to-market gains (losses): |  |  |  |  |  |  |  |
Included in net income (loss): |  |  |  |  |  |  |  |
Included in operating revenues(1) |  | 152 |  |  | 31 |  |  | 197 |  |  | (28 | )
Included in fuel and purchased energy expense(2) |  | 1 |  |  | 18 |  |  | 2 |  |  | 15 |
Change in collateral |  | (1 | ) |  | 1 |  |  | 1 |  |  | (1 | )
Purchases, Issuances and settlements: |  |  |  |  |  |  |  |
Purchases |  | 1 |  |  | 5 |  |  | 3 |  |  | 9 |
Issuances |  | (1 | ) |  | — |  |  | (1 | ) |  | — |
Settlements |  | (35 | ) |  | (42 | ) |  | 28 |  |  | (53 | )
Transfers in and/or out of level 3(3): |  |  |  |  |  |  |  |
Transfers into level 3(4) |  | 6 |  |  | (1 | ) |  | 7 |  |  | (1 | )
Transfers out of level 3(5) |  | (1 | ) |  | (10 | ) |  | (2 | ) |  | (7 | )
Balance, end of period |  | $ | 227 |  |  | $ | 131 |  |  | $ | 227 |  |  | $ | 131 |
Change in unrealized gains (losses) relating to instruments still held at end of period |  | $ | 153 |  |  | $ | 49 |  |  | $ | 199 |  |  | $ | (13 | )

___________

(1) | For power contracts and other power-related products, included on our Consolidated Condensed Statements of Operations.

23

(2) | For natural gas and power contracts, swaps and options, included on our Consolidated Condensed Statements of Operations.

(3) | We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no transfers into or out of level 1 for each of the three and six months ended June 30, 2019 and 2018.

(4) | We had $6 million in gains and $(1) million in losses transferred out of level 2 into level 3 for the three months ended June 30, 2019 and 2018, respectively, and $7 million in gains and $(1) million in losses transferred out of level 2 into level 3 for the six months ended June 30, 2019 and 2018, respectively, due to changes in market liquidity in various power markets.

(5) | We had $1 million and $10 million in gains transferred out of level 3 into level 2 for the three months ended June 30, 2019 and 2018, respectively, and $2 million and $7 million in gains transferred out of level 3 into level 2 for the six months ended June 30, 2019 and 2018, respectively, due to changes in market liquidity in various power markets.

8. | Derivative Instruments

Types of Derivative Instruments and Volumetric Information
Commodity Instruments — We are exposed to changes in prices for the purchase and sale of power, natural gas, fuel oil, environmental products and other energy commodities. We use derivatives, which include physical commodity contracts and financial commodity instruments such as OTC and exchange traded swaps, futures, options, forward agreements and instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) or instruments that settle on power or natural gas price relationships between delivery points for the purchase and sale of power and natural gas to attempt to maximize the risk-adjusted returns by economically hedging a portion of the commodity price risk associated with our assets. By entering into these transactions, we are able to economically hedge a portion of our Spark Spread at estimated generation and prevailing price levels.
We also engage in limited trading activities related to our commodity derivative portfolio as authorized by our Board of Directors and monitored by our 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. Our trading results were not material for each of the three and six months ended June 30, 2019 and 2018.
Interest Rate Hedging Instruments — A portion of our debt is indexed to base rates, primarily LIBOR. We have historically used interest rate hedging instruments to adjust the mix between fixed and variable rate debt to hedge our interest rate risk for potential adverse changes in interest rates. As of June 30, 2019, the maximum length of time over which we were hedging using interest rate hedging instruments designated as cash flow hedges was 6 years.
As of June 30, 2019 and December 31, 2018, the net forward notional buy (sell) position of our outstanding commodity derivative instruments that did not qualify or were not designated under the normal purchase normal sale exemption and our interest rate hedging instruments were as follows:

Derivative Instruments |  | Notional Amounts |  |
| June 30, 2019 |  | December 31, 2018 |  | Unit of Measure
Power |  | (181 | ) |  | (161 | ) |  | Million MWh
Natural gas |  | 1,048 |  |  | 1,045 |  |  | Million MMBtu
Environmental credits |  | 13 |  |  | 13 |  |  | Million Tonnes
Interest rate hedging instruments |  | $ | 4.3 |  |  | $ | 4.5 |  |  | Billion U.S. dollars

Certain of our derivative instruments contain credit risk-related contingent provisions that require us to maintain collateral balances consistent with our credit ratings. If our credit rating were to be downgraded, it could require us to post additional collateral or could potentially allow our counterparty to request immediate, full settlement on certain derivative instruments in liability positions. The aggregate fair value of our derivative liabilities with credit risk-related contingent provisions as of June 30, 2019, was $230 million for which we have posted collateral of $171 million by posting margin deposits, letters of credit or granting additional first priority liens on the assets currently subject to first priority liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. However, if our credit rating were downgraded by one notch from its current level, we estimate that additional collateral of $5 million related to our derivative liabilities would be required and that no counterparty could request immediate, full settlement.
24

Accounting for Derivative Instruments
We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Condensed Statements of Operations until the period of delivery. Revenues and expenses derived from instruments that 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 us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We present the cash flows from our derivatives in the same category as the item being hedged (or economically hedged) within operating activities on our 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 — We currently apply hedge accounting to our interest rate hedging instruments. We report the mark-to-market gain or loss on our interest rate hedging instruments designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Prior to January 1, 2019, gains and losses due to ineffectiveness on interest rate hedging instruments were recognized in earnings as a component of interest expense. Upon the adoption of Accounting Standards Update 2017-12 on January 1, 2019, hedge ineffectiveness is no longer separately measured and recorded in earnings. If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value will be recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedge 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 — We enter into power, natural gas, interest rate, environmental product and fuel oil transactions that primarily act as economic hedges to our asset and interest rate portfolio, but either do not qualify as hedges under the hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected. Changes in fair value of commodity derivatives not designated as hedging instruments are recognized currently in earnings and are separately stated on our 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 fair value of interest rate derivatives not designated as hedging instruments are recognized currently in earnings as interest expense.
Derivatives Included on Our Consolidated Condensed Balance Sheets
We offset fair value amounts associated with our derivative instruments and related cash collateral and margin deposits on our Consolidated Condensed Balance Sheets that are executed with the same counterparty under master netting arrangements. Our netting arrangements include a right to set off or net together purchases and sales of similar products in the margining or settlement process. In some instances, we have also negotiated cross commodity netting rights which allow for the net presentation of activity with a given counterparty regardless of product purchased or sold. We also post and/or receive cash collateral in support of our derivative instruments which may also be subject to a master netting arrangement with the same counterparty.
25

The following tables present the fair values of our derivative instruments and our net exposure after offsetting amounts subject to a master netting arrangement with the same counterparty to our derivative instruments recorded on our Consolidated Condensed Balance Sheets by location and hedge type at June 30, 2019 and December 31, 2018 (in millions):

|  | June 30, 2019
|  | 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 |  | $ | 861 |  |  | $ | (861 | ) |  | $ | — |
Commodity forward contracts |  | 388 |  |  | (188 | ) |  | 200 |
Interest rate hedging instruments |  | 5 |  |  | (3 | ) |  | 2 |
Total current derivative assets(2) |  | $ | 1,254 |  |  | $ | (1,052 | ) |  | $ | 202 |
Commodity exchange traded derivatives contracts |  | 228 |  |  | (228 | ) |  | — |
Commodity forward contracts |  | 284 |  |  | (71 | ) |  | 213 |
Interest rate hedging instruments |  | 1 |  |  | (1 | ) |  | — |
Total long-term derivative assets(2) |  | $ | 513 |  |  | $ | (300 | ) |  | $ | 213 |
Total derivative assets |  | $ | 1,767 |  |  | $ | (1,352 | ) |  | $ | 415 |
Derivative (liabilities): |  |  |  |  |  |
Commodity exchange traded derivatives contracts |  | $ | (861 | ) |  | $ | 861 |  |  | $ | — |
Commodity forward contracts |  | (393 | ) |  | 234 |  |  | (159 | )
Interest rate hedging instruments |  | (9 | ) |  | 3 |  |  | (6 | )
Total current derivative (liabilities)(2) |  | $ | (1,263 | ) |  | $ | 1,098 |  |  | $ | (165 | )
Commodity exchange traded derivatives contracts |  | (318 | ) |  | 318 |  |  | — |
Commodity forward contracts |  | (177 | ) |  | 81 |  |  | (96 | )
Interest rate hedging instruments |  | (24 | ) |  | 1 |  |  | (23 | )
Total long-term derivative (liabilities)(2) |  | $ | (519 | ) |  | $ | 400 |  |  | $ | (119 | )
Total derivative liabilities |  | $ | (1,782 | ) |  | $ | 1,498 |  |  | $ | (284 | )
Net derivative assets (liabilities) |  | $ | (15 | ) |  | $ | 146 |  |  | $ | 131 |

26

|  | December 31, 2018
|  | 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 |  | $ | 820 |  |  | $ | (820 | ) |  | $ | — |
Commodity forward contracts |  | 341 |  |  | (229 | ) |  | 112 |
Interest rate hedging instruments |  | 30 |  |  | — |  |  | 30 |
Total current derivative assets(3) |  | $ | 1,191 |  |  | $ | (1,049 | ) |  | $ | 142 |
Commodity exchange traded derivatives contracts |  | 113 |  |  | (113 | ) |  | — |
Commodity forward contracts |  | 209 |  |  | (59 | ) |  | 150 |
Interest rate hedging instruments |  | 10 |  |  | — |  |  | 10 |
Total long-term derivative assets(3) |  | $ | 332 |  |  | $ | (172 | ) |  | $ | 160 |
Total derivative assets |  | $ | 1,523 |  |  | $ | (1,221 | ) |  | $ | 302 |
Derivative (liabilities): |  |  |  |  |  |
Commodity exchange traded derivatives contracts |  | $ | (764 | ) |  | $ | 764 |  |  | $ | — |
Commodity forward contracts |  | (576 | ) |  | 277 |  |  | (299 | )
Interest rate hedging instruments |  | (4 | ) |  | — |  |  | (4 | )
Total current derivative (liabilities)(3) |  | $ | (1,344 | ) |  | $ | 1,041 |  |  | $ | (303 | )
Commodity exchange traded derivatives contracts |  | (168 | ) |  | 168 |  |  | — |
Commodity forward contracts |  | (193 | ) |  | 59 |  |  | (134 | )
Interest rate hedging instruments |  | (6 | ) |  | — |  |  | (6 | )
Total long-term derivative (liabilities)(3) |  | $ | (367 | ) |  | $ | 227 |  |  | $ | (140 | )
Total derivative liabilities |  | $ | (1,711 | ) |  | $ | 1,268 |  |  | $ | (443 | )
Net derivative assets (liabilities) |  | $ | (188 | ) |  | $ | 47 |  |  | $ | (141 | )

____________

(1) | At June 30, 2019 and December 31, 2018, we had $142 million and $244 million, respectively, of collateral under master netting arrangements that were not offset against our derivative instruments on the Consolidated Condensed Balance Sheets primarily related to initial margin requirements.

(2) | At June 30, 2019, current and long-term derivative assets are shown net of collateral of $(27) million and $(3) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $72 million and $104 million, respectively.

(3) | At December 31, 2018, current and long-term derivative assets are shown net of collateral of $(58) million and $(8) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $49 million and $64 million, respectively.

27

| June 30, 2019 |  | December 31, 2018
| Fair Value of Derivative Assets |  | Fair Value of Derivative Liabilities |  | Fair Value of Derivative Assets |  | Fair Value of Derivative Liabilities
Derivatives designated as cash flow hedging instruments: |  |  |  |  |  |  |
Interest rate hedging instruments | $ | 2 |  |  | $ | 27 |  |  | $ | 40 |  |  | $ | 10 |
Total derivatives designated as cash flow hedging instruments | $ | 2 |  |  | $ | 27 |  |  | $ | 40 |  |  | $ | 10 |
Derivatives not designated as hedging instruments: |  |  |  |  |  |  |
Commodity instruments | $ | 413 |  |  | $ | 255 |  |  | $ | 262 |  |  | $ | 433 |
Interest rate hedging instruments | — |  |  | 2 |  |  | — |  |  | — |
Total derivatives not designated as hedging instruments | $ | 413 |  |  | $ | 257 |  |  | $ | 262 |  |  | $ | 433 |
Total derivatives | $ | 415 |  |  | $ | 284 |  |  | $ | 302 |  |  | $ | 443 |

Derivatives Included on Our Consolidated Condensed Statements of Operations
Changes in the fair values of our derivative instruments are reflected either in cash for option premiums paid or collected, in OCI, net of tax, for derivative instruments which qualify for and we have elected cash flow hedge accounting treatment, or on our 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 gain (loss) recognized from our derivative instruments in earnings and where these components were recorded on our Consolidated Condensed Statements of Operations for the periods indicated (in millions):

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2019 |  | 2018 |  | 2019 |  | 2018
Realized gain (loss)(1)(2) |  |  |  |  |  |  |
Commodity derivative instruments | $ | 58 |  |  | $ | 69 |  |  | $ | 169 |  |  | $ | 66 |
Total realized gain (loss) | $ | 58 |  |  | $ | 69 |  |  | $ | 169 |  |  | $ | 66 |
Mark-to-market gain (loss)(3) |  |  |  |  |  |  |
Commodity derivative instruments | $ | 187 |  |  | $ | 188 |  |  | $ | 233 |  |  | $ | (183 | )
Interest rate hedging instruments | (1 | ) |  | 1 |  |  | (2 | ) |  | 3 |
Total mark-to-market gain (loss) | $ | 186 |  |  | $ | 189 |  |  | $ | 231 |  |  | $ | (180 | )
Total activity, net | $ | 244 |  |  | $ | 258 |  |  | $ | 400 |  |  | $ | (114 | )

___________

(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 Champion Energy and Calpine Solutions.

(3) | In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes adjustments to reflect changes in credit default risk exposure.

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2019 |  | 2018 |  | 2019 |  | 2018
Realized and mark-to-market gain (loss)(1) |  |  |  |  |  |  |
Derivatives contracts included in operating revenues(2)(3) | $ | 541 |  |  | $ | 183 |  |  | $ | 578 |  |  | $ | (176 | )
Derivatives contracts included in fuel and purchased energy expense(2)(3) | (296 | ) |  | 74 |  |  | (176 | ) |  | 59 |
Interest rate hedging instruments included in interest expense | (1 | ) |  | 1 |  |  | (2 | ) |  | 3 |
Total activity, net | $ | 244 |  |  | $ | 258 |  |  | $ | 400 |  |  | $ | (114 | )

___________
28

(1) | In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes 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 Champion Energy and Calpine Solutions.

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):

| Three Months Ended June 30, |  | Three Months Ended June 30,
| Gain (Loss) Recognized in OCI |  | Gain (Loss) Reclassified from AOCI into Income(3)(4)
| 2019 |  | 2018 |  | 2019 |  | 2018 |  | Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate hedging instruments(1)(2) | $ | (32 | ) |  | $ | 15 |  |  | $ | 3 |  |  | $ | — |  |  | Interest expense
Total | $ | (32 | ) |  | $ | 15 |  |  | $ | 3 |  |  | $ | — |  |  |

| Six Months Ended June 30, |  | Six Months Ended June 30,
| Gain (Loss) Recognized in OCI |  | Gain (Loss) Reclassified from AOCI into Income(3)(4)
| 2019 |  | 2018 |  | 2019 |  | 2018 |  | Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate hedging instruments(1)(2) | $ | (57 | ) |  | $ | 69 |  |  | $ | 5 |  |  | $ | (6 | ) |  | Interest expense
Interest rate hedging instruments(1)(2) | — |  |  | 1 |  |  | — |  |  | (1 | ) |  | Depreciation and amortization expense
Total | $ | (57 | ) |  | $ | 70 |  |  | $ | 5 |  |  | $ | (7 | ) |  |

____________

(1) | We recorded $1 million in gains on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during each of the three and six months ended June 30, 2018. Upon the adoption of Accounting Standards Update 2017-12 on January 1, 2019, hedge ineffectiveness is no longer separately measured and recorded in earnings.

(2) | We recorded an income tax benefit of $1 million and $7 million for the three months ended June 30, 2019 and 2018, respectively, and income tax benefit of $1 million and income tax expense of $4 million for the six months ended June 30, 2019 and 2018, respectively, in AOCI related to our cash flow hedging activities.

(3) | Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $89 million and $34 million at June 30, 2019 and December 31, 2018, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $4 million and $3 million at June 30, 2019 and December 31, 2018, respectively.

(4) | Includes losses (gains) of nil that were reclassified from AOCI to interest expense for the three months ended June 30, 2019 and 2018, and losses of $1 million and nil that were reclassified from AOCI to interest expense for the six months ended June 30, 2019 and 2018, respectively, where the hedged transactions became probable of not occurring.

We estimate that pre-tax net losses of $20 million would be reclassified from AOCI into interest 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. Therefore, we are unable to predict what the actual reclassification from AOCI into earnings (positive or negative) will be for the next 12 months.

9. | Use of Collateral

We use margin deposits, prepayments and letters of credit as credit support with and from our counterparties for commodity procurement and risk management activities. In addition, we have 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 hedging instruments in order to reduce the cash collateral and letters of credit that we would otherwise
29

be required to provide 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 our 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 as of June 30, 2019 and December 31, 2018 (in millions):

| June 30, 2019 |  | December 31, 2018
Margin deposits(1) | $ | 373 |  |  | $ | 343 |
Natural gas and power prepayments | 34 |  |  | 31 |
Total margin deposits and natural gas and power prepayments with our counterparties(2) | $ | 407 |  |  | $ | 374 |
Letters of credit issued | $ | 900 |  |  | $ | 1,166 |
First priority liens under power and natural gas agreements | 42 |  |  | 92 |
First priority liens under interest rate hedging instruments | 29 |  |  | 10 |
Total letters of credit and first priority liens with our counterparties | $ | 971 |  |  | $ | 1,268 |
Margin deposits posted with us by our counterparties(1)(3) | $ | 85 |  |  | $ | 52 |
Letters of credit posted with us by our counterparties | 31 |  |  | 27 |
Total margin deposits and letters of credit posted with us by our counterparties | $ | 116 |  |  | $ | 79 |

___________

(1) | We offset 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 8 for further discussion of our derivative instruments subject to master netting arrangements.

(2) | At June 30, 2019 and December 31, 2018, $162 million and $79 million, respectively, were included in current and long-term derivative assets and liabilities, $237 million and $286 million, respectively, were included in margin deposits and other prepaid expense and $8 million and $9 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.

(3) | At June 30, 2019 and December 31, 2018, $16 million and $32 million, respectively, were included in current and long-term derivative assets and liabilities, $28 million and $20 million, respectively, were included in other current liabilities and $41 million and nil, respectively, were included in other long-term liabilities on our 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 our involvement in hedging and optimization contracts, movements in commodity prices, and also based on our credit ratings and general perception of creditworthiness in our market.

10. | Income Taxes

Income Tax Expense (Benefit)
The table below shows our consolidated income tax expense (benefit) and our effective tax rates for the periods indicated (in millions):

| Three Months Ended June 30, |  | Six Months Ended June 30,
| 2019 |  | 2018 |  | 2019 |  | 2018
Income tax expense (benefit) | $ | 9 |  |  | $ | (158 | ) |  | $ | 19 |  |  | $ | (50 | )
Effective tax rate | 3 | % |  | (81 | )% |  | 4 | % |  | 17 | %

Our income tax rates do not bear a customary relationship to statutory income tax rates primarily as a result of the effect of our NOLs, changes in unrecognized tax benefits and valuation allowances. For the three and six months ended June 30, 2019
30

and 2018, our income tax expense (benefit) is largely comprised of discrete tax items and estimated state and foreign income taxes in jurisdictions where we do not have NOLs or valuation allowances.
Income Tax Audits — We remain subject to periodic audits and reviews by taxing authorities; however, we do not expect these audits will have a material effect on our tax provision. Any NOLs we claim 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 we have NOLs. We are currently under various state income tax audits for various periods. Our Canadian subsidiaries are currently under examination by the Canada Revenue Agency for the years ended December 31, 2013 through 2016.
Valuation Allowance — U.S. GAAP requires that we consider all available evidence, both positive and negative, and tax planning strategies to determine whether, based on the weight of that evidence, a valuation allowance is needed to reduce the value of deferred tax assets. 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. Due to our history of losses, we were unable to assume future profits; however, we are able to consider available tax planning strategies.
Limitation on Deduction of Net Business Interest Expense — On November 26, 2018, the U.S. Treasury Department released proposed regulations which would limit the current deductibility of net business interest expense. The proposed regulations would be applicable for taxable years ending after the date on which the regulations become final. Companies have the discretion to apply the proposed regulations, but must apply all such provisions of the proposed regulations on a consistent basis. As of June 30, 2019, we have not elected to apply the proposed regulations for the 2018 or 2019 tax years and we do not expect the application of the final regulations will have a material effect on our Consolidated Condensed Financial Statements.
Unrecognized Tax Benefits — At June 30, 2019, we had unrecognized tax benefits of $29 million. If recognized, $17 million of our unrecognized tax benefits could affect the annual effective tax rate and $12 million, related to deferred tax assets, could be offset against the recorded valuation allowance resulting in no effect on our effective tax rate. We had accrued interest and penalties of $3 million for income tax matters at June 30, 2019. We recognize interest and penalties related to unrecognized tax benefits in income tax expense (benefit) on our Consolidated Condensed Statements of Operations. We believe that it is reasonably possible that a decrease within the range of nil and $8 million in unrecognized tax benefits could occur within the next twelve months primarily related to state tax issues.

11. | Commitments and Contingencies

Litigation
We are party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business. At the present time, we do not expect that the outcome of any of these proceedings, individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.
On a quarterly basis, we review our litigation activities and determine if an unfavorable outcome to us is considered “remote,” “reasonably possible” or “probable” as defined by U.S. GAAP. Where we determine an unfavorable outcome is probable and is reasonably estimable, we accrue for potential litigation losses. The liability we 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, we do not expect that the reasonably possible outcome of these litigation matters would, individually or in the aggregate, have a material adverse effect on our financial condition, results of operations or cash flows. Where we determine an unfavorable outcome is not probable or reasonably estimable, we do 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, we give no assurance that such litigation matters would, individually or in the aggregate, not have a material adverse effect on our financial condition, results of operations or cash flows.
Environmental Matters
We are subject to complex and stringent environmental laws and regulations related to the operation of our power plants. On occasion, we may incur environmental fees, penalties and fines associated with the operation of our power plants. At the present time, we do not have environmental violations or other matters that would have a material effect on our financial condition, results of operations or cash flows or that would significantly change our operations.
31

Guarantees and Indemnifications
Our 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. Our total maximum exposure under our guarantee and indemnification obligations is not estimable due to uncertainty as to whether claims will be made or how any potential claim will be resolved. As of June 30, 2019, there are no material outstanding claims related to our guarantee and indemnification obligations and we do not anticipate that we will be required to make any material payments under our guarantee and indemnification obligations. There have been no material changes to our guarantees and indemnifications from those disclosed in Note 16 of our 2018 Form 10-K.

12. | Related Party Transactions

We have entered into various agreements with related parties associated with the operation of our business. A description of these related party transactions is provided below:
Calpine Receivables — Under the Accounts Receivable Sales Program, at June 30, 2019 and December 31, 2018, we had $244 million and $238 million, respectively, in trade accounts receivable outstanding that were sold to Calpine Receivables and $57 million and $34 million, respectively, in notes receivable from Calpine Receivables which were recorded on our Consolidated Condensed Balance Sheets. During the six months ended June 30, 2019 and 2018, we sold an aggregate of $1.1 billion and $1.1 billion, respectively, in trade accounts receivable and recorded $1.1 billion and $1.1 billion, respectively, in proceeds. For a further discussion of the Accounts Receivable Sales Program and Calpine Receivables, see Notes 7 and 17 in our 2018 Form 10-K.
Lyondell — We have a ground lease agreement with Houston Refining LP (“Houston Refining”), a subsidiary of Lyondell, for our Channel Energy Center site from which we sell power, capacity and steam to Houston Refining under a PPA. We purchase refinery gas and raw water from Houston Refining under a facilities services agreement. One of the entities which obtained an ownership interest in Calpine through the Merger also has an ownership interest in Lyondell whereby they may significantly influence the management and operating policies of Lyondell. The terms of the PPA with Lyondell were negotiated prior to the Merger closing. We recorded $17 million and $19 million in Commodity revenue during the three months ended June 30, 2019 and 2018, respectively, and $37 million and $38 million in Commodity revenue during the six months ended June 30, 2019 and 2018, associated with this contract with Lyondell. We recorded $4 million and $4 million in Commodity expense during the three months ended June 30, 2019 and 2018, respectively, and $7 million and $6 million in Commodity expense during the six months ended June 30, 2019 and 2018, associated with this contract with Lyondell. At June 30, 2019 and December 31, 2018, the related party receivable and payable associated with this contract with Lyondell were immaterial.
Other — Following the Merger, we have identified other related party contracts for the sale of power, capacity and RECs which are entered into in the ordinary course of our business. Most of these contracts relate to the sale of commodities and capacity for varying tenors. The terms of most of these contracts were negotiated prior to the Merger. As of June 30, 2019 and December 31, 2018, the related party receivables and payables associated with these transactions were immaterial.

13. | Segment Information

We assess our business on a regional basis due to the effect on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors affecting supply and demand. At June 30, 2019, our geographic reportable segments for our wholesale business are West (including geothermal), Texas and East (including Canada) and we have a separate reportable segment for our retail business. We continue to evaluate the optimal manner in which we assess our performance including our segments and future changes may result in changes to the composition of our geographic segments.
Commodity Margin is a key operational measure of profit reviewed by our chief operating decision maker to assess the performance of our segments. The tables below show financial data for our segments (including a reconciliation of our Commodity Margin to income (loss) from operations by segment) for the periods indicated (in millions):
32

| Three Months Ended June 30, 2019
| Wholesale |  |  |  | Consolidation |  |
| West |  | Texas |  | East |  | Retail |  | Elimination |  | Total
Total operating revenues(1) | $ | 649 |  |  | $ | 899 |  |  | $ | 646 |  |  | $ | 1,082 |  |  | $ | (677 | ) |  | $ | 2,599 |
Commodity Margin | $ | 251 |  |  | $ | 173 |  |  | $ | 235 |  |  | $ | 93 |  |  | $ | — |  |  | $ | 752 |
Add: Mark-to-market commodity activity, net and other(2) | 58 |  |  | 240 |  |  | 94 |  |  | (182 | ) |  | (10 | ) |  | 200 |
Less: |  |  |  |  |  |  |  |  |  |  |  |
Operating and maintenance expense | 84 |  |  | 66 |  |  | 72 |  |  | 33 |  |  | (10 | ) |  | 245 |
Depreciation and amortization expense | 60 |  |  | 54 |  |  | 48 |  |  | 13 |  |  | — |  |  | 175 |
General and other administrative expense | 5 |  |  | 15 |  |  | 10 |  |  | 4 |  |  | — |  |  | 34 |
Other operating expenses | 7 |  |  | 1 |  |  | 11 |  |  | — |  |  | — |  |  | 19 |
Impairment losses | — |  |  | — |  |  | 40 |  |  | — |  |  | — |  |  | 40 |
(Income) from unconsolidated subsidiaries | — |  |  | — |  |  | (6 | ) |  | 1 |  |  | — |  |  | (5 | )
Income (loss) from operations | 153 |  |  | 277 |  |  | 154 |  |  | (140 | ) |  | — |  |  | 444 |
Interest expense |  |  |  |  |  |  |  |  |  |  | 157 |
Gain on extinguishment of debt and other (income) expense, net |  |  |  |  |  |  |  |  |  |  | 8 |
Income before income taxes |  |  |  |  |  |  |  |  |  |  | $ | 279 |

| Three Months Ended June 30, 2018
| Wholesale |  |  |  | Consolidation |  |
| West |  | Texas |  | East |  | Retail |  | Elimination |  | Total
Total operating revenues(1) | $ | 355 |  |  | $ | 993 |  |  | $ | 341 |  |  | $ | 935 |  |  | $ | (365 | ) |  | $ | 2,259 |
Commodity Margin | $ | 241 |  |  | $ | 151 |  |  | $ | 225 |  |  | $ | 77 |  |  | $ | — |  |  | $ | 694 |
Add: Mark-to-market commodity activity, net and other(2) | (23 | ) |  | 301 |  |  | (7 | ) |  | (67 | ) |  | (8 | ) |  | 196 |
Less: |  |  |  |  |  |  |  |  |  |  |
Operating and maintenance expense | 80 |  |  | 65 |  |  | 65 |  |  | 41 |  |  | (9 | ) |  | 242 |
Depreciation and amortization expense | 67 |  |  | 57 |  |  | 49 |  |  | 13 |  |  | — |  |  | 186 |
General and other administrative expense | 5 |  |  | 13 |  |  | 8 |  |  | 5 |  |  | — |  |  | 31 |
Other operating expenses | 8 |  |  | 3 |  |  | 8 |  |  | — |  |  | — |  |  | 19 |
(Income) from unconsolidated subsidiaries | — |  |  | — |  |  | (6 | ) |  | 1 |  |  | — |  |  | (5 | )
Income (loss) from operations | 58 |  |  | 314 |  |  | 94 |  |  | (50 | ) |  | 1 |  |  | 417 |
Interest expense |  |  |  |  |  |  |  |  |  |  | 157 |
Other (income) expense, net |  |  |  |  |  |  |  |  |  |  | 62 |
Income before income taxes |  |  |  |  |  |  |  |  |  |  | $ | 198 |

33

| Six Months Ended June 30, 2019
| Wholesale |  |  |  | Consolidation |  |
| West |  | Texas |  | East |  | Retail |  | Elimination |  | Total
Total operating revenues(3) | $ | 1,331 |  |  | $ | 1,642 |  |  | $ | 1,335 |  |  | $ | 2,080 |  |  | $ | (1,190 | ) |  | $ | 5,198 |
Commodity Margin | $ | 515 |  |  | $ | 335 |  |  | $ | 500 |  |  | $ | 181 |  |  | $ | — |  |  | $ | 1,531 |
Add: Mark-to-market commodity activity, net and other(4) | 114 |  |  | 284 |  |  | 107 |  |  | (235 | ) |  | (18 | ) |  | 252 |
Less: |  |  |  |  |  |  |  |  |  |  |
Operating and maintenance expense | 165 |  |  | 131 |  |  | 139 |  |  | 67 |  |  | (18 | ) |  | 484 |
Depreciation and amortization expense | 133 |  |  | 99 |  |  | 91 |  |  | 26 |  |  | — |  |  | 349 |
General and other administrative expense | 12 |  |  | 27 |  |  | 19 |  |  | 8 |  |  | — |  |  | 66 |
Other operating expenses | 16 |  |  | 3 |  |  | 19 |  |  | — |  |  | — |  |  | 38 |
Impairment losses | — |  |  | — |  |  | 55 |  |  | — |  |  | — |  |  | 55 |
(Income) from unconsolidated subsidiaries | — |  |  | — |  |  | (12 | ) |  | 1 |  |  | — |  |  | (11 | )
Income (loss) from operations | 303 |  |  | 359 |  |  | 296 |  |  | (156 | ) |  | — |  |  | 802 |
Interest expense |  |  |  |  |  |  |  |  |  |  | 306 |
Gain on extinguishment of debt and other (income) expense, net |  |  |  |  |  |  |  |  |  |  | 27 |
Income before income taxes |  |  |  |  |  |  |  |  |  |  | $ | 469 |

| Six Months Ended June 30, 2018
| Wholesale |  |  |  | Consolidation |  |
| West |  | Texas |  | East |  | Retail |  | Elimination |  | Total
Total operating revenues(3) | $ | 835 |  |  | $ | 1,133 |  |  | $ | 955 |  |  | $ | 1,873 |  |  | $ | (528 | ) |  | $ | 4,268 |
Commodity Margin | $ | 426 |  |  | $ | 317 |  |  | $ | 409 |  |  | $ | 154 |  |  | $ | — |  |  | $ | 1,306 |
Add: Mark-to-market commodity activity, net and other(4) | (10 | ) |  | (246 | ) |  | 33 |  |  | 61 |  |  | (15 | ) |  | (177 | )
Less: |  |  |  |  |  |  |  |  |  |  |
Operating and maintenance expense | 170 |  |  | 145 |  |  | 136 |  |  | 81 |  |  | (15 | ) |  | 517 |
Depreciation and amortization expense | 134 |  |  | 133 |  |  | 94 |  |  | 26 |  |  | — |  |  | 387 |
General and other administrative expense | 21 |  |  | 38 |  |  | 23 |  |  | 9 |  |  | — |  |  | 91 |
Other operating expenses | 22 |  |  | 19 |  |  | 15 |  |  | — |  |  | — |  |  | 56 |
(Income) from unconsolidated subsidiaries | — |  |  | — |  |  | (12 | ) |  | 1 |  |  | — |  |  | (11 | )
Income (loss) from operations | 69 |  |  | (264 | ) |  | 186 |  |  | 98 |  |  | — |  |  | 89 |
Interest expense |  |  |  |  |  |  |  |  |  |  | 308 |
Other (income) expense, net |  |  |  |  |  |  |  |  |  |  | 69 |
Loss before income taxes |  |  |  |  |  |  |  |  |  |  | $ | (288 | )

_________

(1) | Includes intersegment revenues of $100 million and $70 million in the West, $348 million and $276 million in Texas, $228 million and $18 million in the East and $1 million and $1 million in Retail for the three months ended June 30, 2019 and 2018, respectively.

(2) | Includes $(19) million and $(19) million of lease levelization and $18 million and $25 million of amortization expense for the three months ended June 30, 2019 and 2018, respectively.

34

(3) | Includes intersegment revenues of $262 million and $184 million in the West, $559 million and $209 million in Texas, $365 million and $133 million in the East and $4 million and $2 million in Retail for the six months ended June 30, 2019 and 2018, respectively.

(4) | Includes $(35) million and $(35) million of lease levelization and $39 million and $53 million of amortization expense for the six months ended June 30, 2019 and 2018, respectively.

35

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 our accompanying Consolidated Condensed Financial Statements and related Notes. 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
We are a power generation company engaged in the ownership and operation of primarily natural gas-fired and geothermal power plants in North America. 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 U.S. We sell power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. We continue to focus on providing products and services that are beneficial to our wholesale and retail customers. We purchase primarily natural gas and some fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We also purchase power for sale to our customers and purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas, power, environmental product, fuel oil and other physical and financial commodity contracts to hedge certain business risks and optimize our portfolio of power plants.
We assess our wholesale business on a regional basis due to the effect on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors affecting supply and demand. Our geographic reportable segments for our wholesale business are West (including geothermal), Texas and East (including Canada) and we have a separate reportable segment for our retail business.
Subsequent to the completion of the sale of the Garrison and RockGen Energy Centers on July 10, 2019, our wholesale power plant portfolio, including partnership interests, consists of 78 power plants, including one under construction, with an aggregate current generation capacity of 25,885 MW and 361 MW under construction. In March 2019, our York 2 Energy Center commenced commercial operations, bringing online approximately 828 MW of combined-cycle, natural gas-fired capacity with dual-fuel capability. Our fleet consists of 63 natural gas-fired combustion turbine-based plants, one natural gas and fuel oil-fired steam-based plant, 13 geothermal steam turbine-based plants and one photovoltaic solar plant. Our wholesale geographic segments have an aggregate generation capacity of 7,435 MW in the West, 9,095 MW in Texas and 9,355 MW with an additional 361 MW under construction in the East. Inclusive of our power generation portfolio and our retail sales platforms, we serve customers in 23 states in the U.S. and in Canada and Mexico.
Governmental and Regulatory Matters
We are subject to complex and stringent energy, environmental and other laws and regulations at the federal, state and local levels as well as rules within the ISO and RTO markets in which we participate. Federal and state legislative and regulatory actions, including those by ISO/RTOs, continue to change how our business is regulated. We are actively participating in these debates at the federal, regional, state and ISO/RTO levels. Significant updates are discussed below. For a further discussion of the environmental and other governmental regulations that affect us, see “— Governmental and Regulatory Matters” in Part I, Item 1 of our 2018 Form 10-K.
PJM
On June 29, 2018, the FERC issued a decision finding PJM’s current tariff to be unjust and unreasonable due to the price-suppressive effects of out-of-market compensation provided to certain generation resources by states within the PJM market. The FERC rejected both replacement proposals submitted by PJM to address the issue and instead opted for an expedited paper hearing to identify a reasonable replacement mechanism. In its decision, the FERC outlined a Fixed Resource Requirement Alternative (“FRR Alternative”) in which power resources receiving out-of-market subsidies could choose to be removed from the PJM market along with a commensurate amount of load. PJM made a compliance filing on October 2, 2018 to implement the FERC’s proposed FRR Alternative, which we do not support. In the same compliance filing, however, PJM also included additional market rule changes we do support that would partially mitigate the impact of out-of-market subsidies on wholesale capacity market prices. PJM’s filing has been pending for many months. On April 10, 2019, PJM submitted a filing to the FERC requesting authorization to run the auction in August 2019 under the current tariff, notwithstanding the FERC’s June 2018 ruling that the tariff is unjust and unreasonable. On July 25, 2019, the FERC issued an order rejecting PJM’s request and ordered PJM not to run the auction as
36

scheduled. As this issue is unresolved, we cannot predict the ultimate effect on our financial condition, results of operations or cash flows.
The Independent Market Monitor (“IMM”) for PJM filed a complaint with the FERC on February 21, 2019 regarding a component of PJM’s Reliability Pricing Model (“RPM”) that allows sellers of the Capacity Performance product (“CP”) to offer CP at prices above the competitive level, thereby potentially allowing them to exercise market power. The IMM argues that this provision of the tariff is unjust and unreasonable because the tariff does not provide a mechanism for the IMM to review these offers. Additionally, the IMM argues that the tariff should be revised to lower the Market Seller Offer Cap. This change would require nearly all competitive suppliers to submit their offers to the IMM for review prior to bidding in the RPM. In response to the IMM’s complaint, Calpine joined with many other competitive suppliers to urge the FERC to reject the IMM’s proposed resolution as inconsistent with CP and, alternatively, to enhance the penalty provisions of CP. This course of action would address the IMM’s concerns and would also be more consistent with the CP design. FERC action on the IMM’s complaint is pending.
37

RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED JUNE 30, 2019 AND 2018
Below are our results of operations for the three months ended June 30, 2019 as compared to the same period in 2018 (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.

| 2019 |  | 2018 |  | Change |  | % Change
Operating revenues: |  |  |  |  |  |  |
Commodity revenue | $ | 2,128 |  |  | $ | 2,121 |  |  | $ | 7 |  |  | — |
Mark-to-market gain | 467 |  |  | 131 |  |  | 336 |  |  | # |
Other revenue | 4 |  |  | 7 |  |  | (3 | ) |  | (43 | )
Operating revenues | 2,599 |  |  | 2,259 |  |  | 340 |  |  | 15 |
Operating expenses: |  |  |  |  |  |  |
Fuel and purchased energy expense: |  |  |  |  |  |  |
Commodity expense | 1,367 |  |  | 1,426 |  |  | 59 |  |  | 4 |
Mark-to-market (gain) loss | 280 |  |  | (57 | ) |  | (337 | ) |  | # |
Fuel and purchased energy expense | 1,647 |  |  | 1,369 |  |  | (278 | ) |  | (20 | )
Operating and maintenance expense | 245 |  |  | 242 |  |  | (3 | ) |  | (1 | )
Depreciation and amortization expense | 175 |  |  | 186 |  |  | 11 |  |  | 6 |
General and other administrative expense | 34 |  |  | 31 |  |  | (3 | ) |  | (10 | )
Other operating expenses | 19 |  |  | 19 |  |  | — |  |  | — |
Total operating expenses | 2,120 |  |  | 1,847 |  |  | (273 | ) |  | (15 | )
Impairment losses | 40 |  |  | — |  |  | (40 | ) |  | # |
(Income) from unconsolidated subsidiaries | (5 | ) |  | (5 | ) |  | — |  |  | — |
Income from operations | 444 |  |  | 417 |  |  | 27 |  |  | 6 |
Interest expense | 157 |  |  | 157 |  |  | — |  |  | — |
Loss on extinguishment of debt | 3 |  |  | — |  |  | (3 | ) |  | # |
Other (income) expense, net | 5 |  |  | 62 |  |  | 57 |  |  | 92 |
Income before income taxes | 279 |  |  | 198 |  |  | 81 |  |  | 41 |
Income tax expense (benefit) | 9 |  |  | (158 | ) |  | (167 | ) |  | # |
Net income | 270 |  |  | 356 |  |  | (86 | ) |  | (24 | )
Net income attributable to the noncontrolling interest | (4 | ) |  | (4 | ) |  | — |  |  | — |
Net income attributable to Calpine | $ | 266 |  |  | $ | 352 |  |  | $ | (86 | ) |  | (24 | )

| 2019 |  | 2018 |  | Change |  | % Change
Operating Performance Metrics: |  |  |  |  |  |  |
MWh generated (in thousands)(1)(2) | 21,156 |  |  | 21,451 |  |  | (295 | ) |  | (1 | )
Average availability(2) | 81.5 | % |  | 80.8 | % |  | 0.7 | % |  | 1 |
Average total MW in operation(1) | 25,908 |  |  | 25,153 |  |  | 755 |  |  | 3 |
Average capacity factor, excluding peakers | 41.6 | % |  | 43.9 | % |  | (2.3 | )% |  | (5 | )
Steam Adjusted Heat Rate(2) | 7,338 |  |  | 7,387 |  |  | 49 |  |  | 1 |

__________

# | Variance of 100% or greater

(1) | Represents generation and capacity from power plants that we both consolidate and operate and excludes Greenfield LP, Whitby, Freeport Energy Center, 21.5% of Hidalgo Energy Center and 25% each of Freestone Energy Center and Russell City Energy Center.

(2) | Generation, average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive.

38

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 $66 million for the three months ended June 30, 2019, compared to the same period in 2018, primarily due to (favorable variances are shown without brackets while unfavorable variances are shown with brackets):

(in millions) |  |
$ | 49 |  |  | Higher energy margins primarily associated with higher contribution from hedging activities in both our wholesale and retail business segments and commencement of commercial operations at our 828 MW York 2 Energy Center in March 2019
9 |  |  | Higher PJM and ISO-NE regulatory capacity revenue in our East segment
8 |  |  | Period-over-period change in contract amortization, lease levelization relating to tolling contracts and other(1)
$ | 66 |  |  |

__________

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

Our normal, recurring operating and maintenance expense, after excluding the effect of restarting our Sutter and South Point Energy Centers in 2018 and York 2 Energy Center achieving commercial operations in March 2019, decreased by $8 million for the three months ended June 30, 2019 compared to the same period in 2018. The decrease was offset by an $11 million increase in operating and maintenance expense primarily associated with higher major maintenance expense resulting from our plant outage schedule and an increase in equipment failure costs.
During the three months ended June 30, 2019, we recorded impairment losses of approximately $40 million related to the sale of our Garrison and RockGen Energy Centers. See Note 4 of the Notes to Consolidated Condensed Financial Statements for further information related to the sale.
Other (income) expense, net decreased by $57 million for the three months ended June 30, 2019 compared to the same period in 2018 primarily due to shareholder settlement costs associated with the Merger, which were recorded during the second quarter of 2018.
During the three months ended June 30, 2019, we recorded income tax expense of $9 million compared to an income tax benefit of $158 million for the three months ended June 30, 2018. The unfavorable period-over-period change primarily resulted from changes in the effect of applying the intraperiod tax allocation rules to our results of operations and related tax expense.
39

RESULTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2019 AND 2018
Below are our results of operations for the six months ended June 30, 2019 as compared to the same period in 2018 (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.

| 2019 |  | 2018 |  | Change |  | % Change
Operating revenues: |  |  |  |  |  |  |
Commodity revenue | $ | 4,666 |  |  | $ | 4,517 |  |  | $ | 149 |  |  | 3 |
Mark-to-market gain (loss) | 523 |  |  | (260 | ) |  | 783 |  |  | # |
Other revenue | 9 |  |  | 11 |  |  | (2 | ) |  | (18 | )
Operating revenues | 5,198 |  |  | 4,268 |  |  | 930 |  |  | 22 |
Operating expenses: |  |  |  |  |  |  |
Fuel and purchased energy expense: |  |  |  |  |  |  |
Commodity expense | 3,125 |  |  | 3,216 |  |  | 91 |  |  | 3 |
Mark-to-market (gain) loss | 290 |  |  | (77 | ) |  | (367 | ) |  | # |
Fuel and purchased energy expense | 3,415 |  |  | 3,139 |  |  | (276 | ) |  | (9 | )
Operating and maintenance expense | 484 |  |  | 517 |  |  | 33 |  |  | 6 |
Depreciation and amortization expense | 349 |  |  | 387 |  |  | 38 |  |  | 10 |
General and other administrative expense | 66 |  |  | 91 |  |  | 25 |  |  | 27 |
Other operating expenses | 38 |  |  | 56 |  |  | 18 |  |  | 32 |
Total operating expenses | 4,352 |  |  | 4,190 |  |  | (162 | ) |  | (4 | )
Impairment losses | 55 |  |  | — |  |  | (55 | ) |  | # |
(Income) from unconsolidated subsidiaries | (11 | ) |  | (11 | ) |  | — |  |  | — |
Income from operations | 802 |  |  | 89 |  |  | 713 |  |  | # |
Interest expense | 306 |  |  | 308 |  |  | 2 |  |  | 1 |
Gain on extinguishment of debt | (1 | ) |  | — |  |  | 1 |  |  | # |
Other (income) expense, net | 28 |  |  | 69 |  |  | 41 |  |  | 59 |
Income (loss) before income taxes | 469 |  |  | (288 | ) |  | 757 |  |  | # |
Income tax expense (benefit) | 19 |  |  | (50 | ) |  | (69 | ) |  | # |
Net income (loss) | 450 |  |  | (238 | ) |  | 688 |  |  | # |
Net income attributable to the noncontrolling interest | (9 | ) |  | (8 | ) |  | (1 | ) |  | (13 | )
Net income (loss) attributable to Calpine | $ | 441 |  |  | $ | (246 | ) |  | $ | 687 |  |  | # |

| 2019 |  | 2018 |  | Change |  | % Change
Operating Performance Metrics: |  |  |  |  |  |  |
MWh generated (in thousands)(1)(2) | 43,257 |  |  | 42,251 |  |  | 1,006 |  |  | 2 |
Average availability(2) | 84.2 | % |  | 84.2 | % |  | — | % |  | — |
Average total MW in operation(1) | 25,558 |  |  | 25,170 |  |  | 388 |  |  | 2 |
Average capacity factor, excluding peakers | 43.9 | % |  | 43.4 | % |  | 0.5 | % |  | 1 |
Steam Adjusted Heat Rate(2) | 7,305 |  |  | 7,356 |  |  | 51 |  |  | 1 |

__________

# | Variance of 100% or greater

(1) | Represents generation and capacity from power plants that we both consolidate and operate and excludes Greenfield LP, Whitby, Freeport Energy Center, 21.5% of Hidalgo Energy Center and 25% each of Freestone Energy Center and Russell City Energy Center.

(2) | Generation, average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive.

40

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 $240 million for the six months ended June 30, 2019, compared to the same period in 2018, primarily due to (favorable variances are shown without brackets while unfavorable variances are shown with brackets):

(in millions) |  |
$ | 202 |  |  | Higher energy margins primarily associated with higher market Spark Spreads in the West during the first quarter of 2019 compared to the same period in 2018, higher contribution from both wholesale and retail hedging activities and the commencement of commercial operations at our 828 MW York 2 Energy Center in March 2019. The increase was partially offset by a gain associated with the cancellation of a PPA recorded in the first quarter of 2018 with no similar activity in 2019
54 |  |  | Higher PJM and ISO-NE regulatory capacity revenue in our East segment
(31 | ) |  | The sale of environmental credits in our Texas segment during the first quarter of 2018 with no similar activity in 2019
15 |  |  | Period-over-period change in contract amortization, lease levelization relating to tolling contracts and other(1)
$ | 240 |  |  |

__________

(1) | Commodity Margin excludes amortization expense related to contracts recorded at fair value, non-cash GAAP-related adjustments to levelize revenues from tolling agreements, Commodity revenue and Commodity expense attributable to the noncontrolling interest 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 a favorable variance of $416 million primarily driven by lower forward power and natural gas prices during the six months ended June 30, 2019.
Our normal, recurring operating and maintenance expense, after excluding the effect of restarting our Sutter and South Point Energy Centers in 2018 and York 2 Energy Center achieving commercial operations in March 2019, decreased by $6 million for the six months ended June 30, 2019 compared to the same period in 2018. The remaining decrease in operating and maintenance expense for the six months ended June 30, 2019 compared to the same period in 2018 primarily resulted from the acceleration of stock-based compensation expense during the first quarter of 2018 in connection with the consummation of the Merger. We no longer incur stock-based compensation expense subsequent to the consummation of the Merger.
Depreciation and amortization expense decreased by $38 million for the six months ended June 30, 2019 compared to the same period in 2018 primarily due to the change in estimated useful lives for our componentized balance of plant parts and rotable parts initiated in 2018 primarily offset by adjustments related to our asset retirement obligations during the first quarter of 2019.
General and other administrative expense decreased by $25 million for the six months ended June 30, 2019 compared to the same period in 2018 primarily resulting from the acceleration of stock-based compensation expense during the first quarter of 2018 in connection with the consummation of the Merger in March 2018.
Other operating expense decreased by $18 million for the six months ended June 30, 2019 compared to the same period in 2018 primarily due to Merger-related costs associated with legal, investment banking and other professional fees in March 2018 partially offset by the write-off of unamortized balances associated with the termination of a PPA during the first quarter of 2018.
During the six months ended June 30, 2019, we recorded impairment losses of approximately $55 million related to the sale of our Garrison and RockGen Energy Centers. See Note 4 of the Notes to Consolidated Condensed Financial Statements for further information related to the sale.
Other (income) expense, net decreased by $41 million for the six months ended June 30, 2019 compared to the same period in 2018 primarily due to shareholder settlement costs associated with the Merger recorded during the second quarter of 2018. The decrease was partially offset by the net effect of a settlement agreement with GE executed in February 2019 which,
41

among other things, terminated our call option and GE’s put option related to the Inland Empire Energy Center. See Note 5 of the Notes to Consolidated Condensed Financial Statements for further information related to the Inland Empire Energy Center.
During the six months ended June 30, 2019, we recorded income tax expense of $19 million compared to an income tax benefit of $50 million for the six months ended June 30, 2018. The unfavorable period-over-period change primarily resulted from changes in the effect of applying the intraperiod tax allocation rules to our results of operations and related tax expense.
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. See Note 13 of the Notes to Consolidated Condensed Financial Statements for a reconciliation of Commodity Margin to income (loss) from operations by segment.
Commodity Margin by Segment for the Three Months Ended June 30, 2019 and 2018
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 June 30, 2019 and 2018 (exclusive of the noncontrolling interest). 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.

West: | 2019 |  | 2018 |  | Change |  | % Change
Commodity Margin (in millions) | $ | 251 |  |  | $ | 241 |  |  | $ | 10 |  |  | 4 |
Commodity Margin per MWh generated | $ | 62.52 |  |  | $ | 61.29 |  |  | $ | 1.23 |  |  | 2 |
MWh generated (in thousands) | 4,015 |  |  | 3,932 |  |  | 83 |  |  | 2 |
Average availability | 79.7 | % |  | 78.3 | % |  | 1.4 | % |  | 2 |
Average total MW in operation | 7,430 |  |  | 7,425 |  |  | 5 |  |  | — |
Average capacity factor, excluding peakers | 26.6 | % |  | 25.6 | % |  | 1.0 | % |  | 4 |
Steam Adjusted Heat Rate | 7,526 |  |  | 7,533 |  |  | 7 |  |  | — |

West — Commodity Margin in our West segment increased by $10 million, or 4%, for the three months ended June 30, 2019 compared to the three months ended June 30, 2018, primarily resulting from higher contribution from hedging activities due to lower market Spark Spreads and higher resource adequacy revenues.

Texas: | 2019 |  | 2018 |  | Change |  | % Change
Commodity Margin (in millions) | $ | 173 |  |  | $ | 151 |  |  | $ | 22 |  |  | 15 |
Commodity Margin per MWh generated | $ | 16.48 |  |  | $ | 13.11 |  |  | $ | 3.37 |  |  | 26 |
MWh generated (in thousands) | 10,497 |  |  | 11,519 |  |  | (1,022 | ) |  | (9 | )
Average availability | 80.9 | % |  | 86.2 | % |  | (5.3 | )% |  | (6 | )
Average total MW in operation | 8,855 |  |  | 8,850 |  |  | 5 |  |  | — |
Average capacity factor, excluding peakers | 54.3 | % |  | 59.6 | % |  | (5.3 | )% |  | (9 | )
Steam Adjusted Heat Rate | 7,149 |  |  | 7,124 |  |  | (25 | ) |  | — |

Texas — Commodity Margin in our Texas segment increased by $22 million, or 15%, for the three months ended June 30, 2019 compared to the three months ended June 30, 2018, primarily due to higher contribution from hedging activities. The increase in Commodity Margin was partially offset by lower on-peak market Spark Spreads during the second quarter of 2019 compared to the same period in 2018, which was partially responsible for the 9% period-over-period decrease in generation.
42

East: | 2019 |  | 2018 |  | Change |  | % Change
Commodity Margin (in millions) | $ | 235 |  |  | $ | 225 |  |  | $ | 10 |  |  | 4 |
Commodity Margin per MWh generated | $ | 35.37 |  |  | $ | 37.50 |  |  | $ | (2.13 | ) |  | (6 | )
MWh generated (in thousands) | 6,644 |  |  | 6,000 |  |  | 644 |  |  | 11 |
Average availability | 83.5 | % |  | 77.1 | % |  | 6.4 | % |  | 8 |
Average total MW in operation | 9,623 |  |  | 8,878 |  |  | 745 |  |  | 8 |
Average capacity factor, excluding peakers | 41.8 | % |  | 42.1 | % |  | (0.3 | )% |  | (1 | )
Steam Adjusted Heat Rate | 7,571 |  |  | 7,832 |  |  | 261 |  |  | 3 |

East — Commodity Margin in our East segment increased by $10 million, or 4%, for the three months ended June 30, 2019 compared to the three months ended June 30, 2018, primarily due to higher regulatory capacity revenue in ISO-NE and PJM, higher contribution from hedging activities and the commencement of commercial operations at our 828 MW York 2 Energy Center in March 2019. The increase in Commodity Margin was partially offset by lower market Spark Spreads during the second quarter of 2019 compared to the same period in 2018. Generation increased 11% primarily driven by our York 2 Energy Center.

Retail: | 2019 |  | 2018 |  | Change |  | % Change
Commodity Margin (in millions) | $ | 93 |  |  | $ | 77 |  |  | $ | 16 |  |  | 21 |

Retail — Commodity Margin in our retail segment increased by $16 million, or 21%, for the three months ended June 30, 2019 compared to the three months ended June 30, 2018, primarily due to increased contribution from power and gas supply hedging activity.
Commodity Margin by Segment for the Six Months Ended June 30, 2019 and 2018
The following tables show our Commodity Margin by segment and related operating performance metrics by regional segment for our wholesale business for the six months ended June 30, 2019 and 2018 (exclusive of the noncontrolling interest). 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.

West: | 2019 |  | 2018 |  | Change |  | % Change
Commodity Margin (in millions) | $ | 515 |  |  | $ | 426 |  |  | $ | 89 |  |  | 21 |
Commodity Margin per MWh generated | $ | 47.76 |  |  | $ | 47.12 |  |  | $ | 0.64 |  |  | 1 |
MWh generated (in thousands) | 10,784 |  |  | 9,041 |  |  | 1,743 |  |  | 19 |
Average availability | 83.3 | % |  | 82.6 | % |  | 0.7 | % |  | 1 |
Average total MW in operation | 7,428 |  |  | 7,425 |  |  | 3 |  |  | — |
Average capacity factor, excluding peakers | 35.9 | % |  | 29.5 | % |  | 6.4 | % |  | 22 |
Steam Adjusted Heat Rate | 7,391 |  |  | 7,345 |  |  | (46 | ) |  | (1 | )

West — Commodity Margin in our West segment increased by $89 million, or 21%, for the six months ended June 30, 2019 compared to the six months ended June 30, 2018, primarily resulting from higher market Spark Spreads in the first quarter of 2019 and higher resource adequacy revenues. Additionally, generation increased 19% due to higher market Spark Spreads in the first quarter of 2019 along with the positive effect of a new contract associated with our Sutter Energy Center which became effective during the second quarter of 2018.
43

Texas: | 2019 |  | 2018 |  | Change |  | % Change
Commodity Margin (in millions) | $ | 335 |  |  | $ | 317 |  |  | $ | 18 |  |  | 6 |
Commodity Margin per MWh generated | $ | 16.17 |  |  | $ | 14.98 |  |  | $ | 1.19 |  |  | 8 |
MWh generated (in thousands) | 20,713 |  |  | 21,166 |  |  | (453 | ) |  | (2 | )
Average availability | 81.8 | % |  | 85.7 | % |  | (3.9 | )% |  | (5 | )
Average total MW in operation | 8,852 |  |  | 8,850 |  |  | 2 |  |  | — |
Average capacity factor, excluding peakers | 53.9 | % |  | 55.1 | % |  | (1.2 | )% |  | (2 | )
Steam Adjusted Heat Rate | 7,110 |  |  | 7,121 |  |  | 11 |  |  | — |

Texas — Commodity Margin in our Texas segment increased by $18 million, or 6%, for the six months ended June 30, 2019 compared to the six months ended June 30, 2018, primarily due to higher contribution from hedging activities in the second quarter of 2019. The increase in Commodity Margin was partially offset by lower on-peak market Spark Spreads during the first half of 2019 compared to the same period in 2018 and higher revenue in the first quarter of 2018 associated with the sale of environmental credits with no similar activity in the same period in 2019.

East: | 2019 |  | 2018 |  | Change |  | % Change
Commodity Margin (in millions) | $ | 500 |  |  | $ | 409 |  |  | $ | 91 |  |  | 22 |
Commodity Margin per MWh generated | $ | 42.52 |  |  | $ | 33.96 |  |  | $ | 8.56 |  |  | 25 |
MWh generated (in thousands) | 11,760 |  |  | 12,044 |  |  | (284 | ) |  | (2 | )
Average availability | 87.3 | % |  | 83.9 | % |  | 3.4 | % |  | 4 |
Average total MW in operation | 9,278 |  |  | 8,895 |  |  | 383 |  |  | 4 |
Average capacity factor, excluding peakers | 39.1 | % |  | 42.4 | % |  | (3.3 | )% |  | (8 | )
Steam Adjusted Heat Rate | 7,596 |  |  | 7,780 |  |  | 184 |  |  | 2 |

East — Commodity Margin in our East segment increased by $91 million, or 22%, for the six months ended June 30, 2019 compared to the six months ended June 30, 2018, primarily due to higher regulatory capacity revenue in ISO-NE and PJM, higher contribution from hedging activities and the commencement of commercial operations at our 828 MW York 2 Energy Center in March 2019. The increase in Commodity Margin was partially offset by a gain associated with the cancellation of a PPA recorded during first quarter 2018 with no similar activity during the first quarter of 2019.

Retail: | 2019 |  | 2018 |  | Change |  | % Change
Commodity Margin (in millions) | $ | 181 |  |  | $ | 154 |  |  | $ | 27 |  |  | 18 |

Retail — Commodity Margin in our retail segment increased by $27 million, or 18%, for the six months ended June 30, 2019 compared to the six months ended June 30, 2018, primarily due to increased contribution from power and gas supply hedging activity.
44

LIQUIDITY AND CAPITAL RESOURCES
We maintain a strong focus on liquidity. We manage our liquidity to help provide access to sufficient funding to meet our business needs and financial obligations throughout business cycles.
Our business is capital intensive. Our ability to successfully implement our strategy is dependent on the continued availability of capital on attractive terms. In addition, our ability to successfully operate our business is dependent on maintaining sufficient liquidity. We believe that we have adequate resources from a combination of cash and cash equivalents on hand and cash expected to be generated from future operations to continue to meet our obligations as they become due.
Liquidity
The following table provides a summary of our liquidity position at June 30, 2019 and December 31, 2018 (in millions):

| June 30, 2019 |  | December 31, 2018
Cash and cash equivalents, corporate(1) | $ | 242 |  |  | $ | 141 |
Cash and cash equivalents, non-corporate(2) | 55 |  |  | 64 |
Total cash and cash equivalents | 297 |  |  | 205 |
Restricted cash(2) | 262 |  |  | 201 |
Corporate Revolving Facility availability(3) | 1,356 |  |  | 966 |
CDHI letter of credit facility availability(4) | 61 |  |  | 49 |
Other facilities availability(5) | 4 |  |  | 7 |
Total current liquidity availability(6) | $ | 1,980 |  |  | $ | 1,428 |

____________

(1) | Our ability to use corporate cash and cash equivalents is unrestricted.

(2) | See Note 1 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 availability under our Corporate Revolving Facility is unrestricted. On April 5, 2019, we amended our Corporate Revolving Facility to increase the capacity by approximately $330 million from $1.69 billion to approximately $2.02 billion. See “Letter of Credit Facilities” below for amounts issued under letters of credit at June 30, 2019 associated with our Corporate Revolving Facility.

(4) | Our CDHI letter of credit facility is restricted to support certain obligations under PPAs and power transmission and natural gas transportation agreements as well as fund the construction of our Washington Parish Energy Center. Pursuant to the terms and conditions of the CDHI credit agreement, the capacity under the CDHI letter of credit facility was reduced to $125 million on June 28, 2019. The decrease in capacity did not have a material effect on our liquidity as alternative sources of liquidity are available.

(5) | We have three unsecured letter of credit facilities with two third-party financial institutions totaling approximately $300 million at June 30, 2019.

(6) | Includes $85 million and $52 million of margin deposits posted with us by our counterparties at June 30, 2019 and December 31, 2018, respectively. See Note 9 of the Notes to Consolidated Condensed Financial Statements for further information related to our collateral.

Our principal source for future liquidity is cash flows generated from our operations. We believe that cash on hand and expected future cash flows from operations will be sufficient to meet our liquidity needs for our operations, both in the near and longer term. See “Cash Flow Activities” below for a further discussion of our change in cash and cash equivalents.
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 and opportunistically repaying debt to manage our balance sheet.
Cash Management — 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 lease 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.
45

On July 18, 2019, our board of directors approved a special cash dividend of $400 million to be paid to our parent, CPN Management, LP, which was funded with the proceeds from the sale of the Garrison and RockGen Energy Centers and cash on hand and paid on July 18, 2019. See Note 4 of the Notes to Consolidated Condensed Financial Statements for further information related to the sale of the Garrison and RockGen Energy Centers.
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 as we use margin deposits, cash prepayments and letters of credit as credit support (collateral) with and from our counterparties for commodity procurement and risk management activities. We estimate that as of June 30, 2019, a three standard deviation shift in collateral exposure based on commodity market price changes for the previous 12 months applied to our current portfolio of margined transactions would result in an increase in collateral posted of approximately $255 million. This amount is not necessarily indicative of the actual amounts that could be required, which may be higher or lower than the amounts estimated above, and also exclude any correlation between the changes in natural gas prices and Market Heat Rates that may occur concurrently. These sensitivities will change as new contracts or hedging activities are executed.
In order to effectively manage our future Commodity Margin, we have economically hedged a portion of our expected generation and natural gas portfolio as well as retail load supply obligations, where appropriate, mostly through power and natural gas forward physical and financial transactions including retail power sales; however, we currently remain susceptible to significant price movements for 2019 and beyond. In addition to the price of natural gas, our Commodity Margin is highly dependent on other factors such as:

• | the level of Market Heat Rates;

• | our continued ability to successfully hedge our Commodity Margin;

• | 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.

Additionally, scheduled outages related to the life cycle of our power plant fleet in addition to unscheduled outages may result in maintenance expenditures that are disproportionate in differing periods. In order to manage such liquidity requirements, we maintain additional liquidity availability in the form of our Corporate Revolving Facility (noted in the table above), letters of credit and the ability to issue first priority liens for collateral support. It is difficult to predict future developments and the amount of credit support that we may need to provide should such conditions occur, we experience another economic recession or energy commodity prices increase significantly.
Letter of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at June 30, 2019 and December 31, 2018 (in millions):

| June 30, 2019 |  | December 31, 2018
Corporate Revolving Facility(1) | $ | 585 |  |  | $ | 693 |
CDHI(2) | 30 |  |  | 251 |
Various project financing facilities | 227 |  |  | 228 |
Other corporate facilities(3) | 293 |  |  | 193 |
Total | $ | 1,135 |  |  | $ | 1,365 |

____________

(1) | The Corporate Revolving Facility represents our primary revolving facility. On April 5, 2019, we amended our Corporate Revolving Facility to increase the capacity by approximately $330 million from $1.69 billion to approximately $2.02 billion.

46

(2) | Pursuant to the terms and conditions of the CDHI credit agreement, the capacity under the CDHI letter of credit facility was reduced to $125 million on June 28, 2019. The decrease in capacity did not have a material effect on our liquidity as alternative sources of liquidity are available.

(3) | We have three unsecured letter of credit facilities with two third-party financial institutions totaling approximately $300 million at June 30, 2019.

NOLs
We have significant NOLs that will provide future tax deductions when we generate sufficient taxable income during the applicable carryover periods. At December 31, 2018, our consolidated federal NOLs totaled approximately $6.4 billion.
Cash Flow Activities
The following table summarizes our cash flow activities for the six months ended June 30, 2019 and 2018 (in millions):

| 2019 |  | 2018
Beginning cash, cash equivalents and restricted cash | $ | 406 |  |  | $ | 443 |
Net cash provided by (used in): |  |  |
Operating activities | 519 |  |  | 56 |
Investing activities | (315 | ) |  | (234 | )
Financing activities | (51 | ) |  | 69 |
Net increase (decrease) in cash, cash equivalents and restricted cash | 153 |  |  | (109 | )
Ending cash, cash equivalents and restricted cash | $ | 559 |  |  | $ | 334 |

Net Cash Provided By Operating Activities
Cash provided by operating activities for the six months ended June 30, 2019, was $519 million compared to $56 million for the six months ended June 30, 2018. The increase was primarily due to:

• | Income from operations — Income from operations, adjusted for non-cash items, increased by $301 million for the six months ended June 30, 2019, compared to the same period in 2018. Non-cash items consist primarily of depreciation and amortization, income from unconsolidated subsidiaries, gain on sale of assets and mark-to-market activity. The increase in income from operations was primarily driven by a $240 million increase in Commodity revenue, net of Commodity expense, excluding non-cash amortization, a $33 million decrease in operating and maintenance expense and a $25 million decrease in general and other administrative expenses. See “Results of Operations for the Six Months Ended June 30, 2019 and 2018” above for further discussion of these changes.

• | Working capital employed — Working capital employed decreased by $179 million for the six months ended June 30, 2019 compared to the same period in 2018 after adjusting for changes in debt extinguishment costs and certain mark-to-market related balances that do not impact cash provided by operating activities. This change was primarily due to a net decrease in margin posting activity on our commodity hedging activities as well as a decrease in the purchase of environmental products inventory.

Net Cash Used In Investing Activities
Cash used in investing activities for the six months ended June 30, 2019, was $315 million compared to $234 million for the six months ended June 30, 2018. The increase was primarily due to:

• | Capital expenditures — We incurred higher capital expenditures on construction and growth projects during the six months ended June 30, 2019 as compared to the six months ended June 30, 2018.

Net Cash (Used In) Provided By Financing Activities
Cash used in financing activities for the six months ended June 30, 2019, was $51 million compared to cash provided by financing activities of $69 million for the six months ended June 30, 2018. The decrease was primarily due to:

• | First Lien Term Loans — During the six months ended June 30, 2019, we received net proceeds of $941 million from the issuance of the 2026 First Lien Term Loan, which was used to repay our 2019 First Lien Term Loan and a portion of our 2023 First Lien Term Loans. There was no similar activity during the six months ended June 30, 2018.

47

• | Corporate Revolving Facility — During the six months ended June 30, 2019, we borrowed a net $45 million under our Corporate Revolving Facility, compared to $275 million net borrowings under our Corporate Revolving Facility during the six months ended June 30, 2018. The 2018 borrowing was made in part to fund non-recurring costs associated with the consummation of the Merger, including the repurchase of our equity-classified share based awards on the effective date of the merger.

• | Project Financing, Notes Payable and Other — During the six months ended June 30, 2019, we borrowed $34 million to fund the construction of our Washington Parish Energy Center. There was no similar activity during the six months ended June 30, 2018.

• | Repurchases of Senior Unsecured Notes — During the six months ended June 30, 2019, we repurchased $48 million in aggregate principal of our Senior Unsecured Notes for $44 million. There was no similar activity during the six months ended June 30, 2018.

• | Stock Repurchases — During the six months ended June 30, 2018, we repurchased $79 million of our equity classified share-based awards on the effective date of the Merger. There was no similar activity during the six months ended June 30, 2019.

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 our 2018 Form 10-K.
Special Purpose Subsidiaries
Pursuant to applicable transaction agreements, we have established certain of our 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 Notes 7 and 17 of the Notes to Consolidated Financial Statements in our 2018 Form 10-K for further information related to Calpine Receivables). As of the date of filing of this Report, these entities included: Russell City Energy Company, LLC, OMEC and Calpine Receivables.
OMEC — OMEC has a ten-year tolling agreement with SDG&E, which commenced on October 3, 2009. Under a ground lease agreement, OMEC held a put option to sell the Otay Mesa Energy Center for $280 million to SDG&E, pursuant to the terms and conditions of the agreement, which was exercisable until April 1, 2019 and SDG&E held a call option to purchase the Otay Mesa Energy Center for $377 million, which was exercisable through October 3, 2018. The call option held by SDG&E expired unexercised.
OMEC has executed a new 59-month Resource Adequacy (“RA”) contract with SDG&E, which would commence on October 3, 2019. The RA contract received initial regulatory approval by the California Public Utilities Commission (“CPUC”) on February 21, 2019. This approval was subject to a 30 day appeal period from the date of the issuance of the CPUC decision. On March 27, 2019, an appeal of the CPUC decision was filed with the CPUC, which appeal was denied on August 1, 2019. As a result, we continue to work to commence the RA contract. However, in the event that we are not successful and another alternative is not reached with SDG&E prior to October 3, 2019, OMEC expects to close on the put and transfer the Otay Mesa Energy Center to SDG&E for $280 million on or about October 3, 2019, which transaction could result in a write down of the carrying value of the asset.
48

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. We actively manage our risk exposures with a variety of physical and financial instruments with varying time horizons. These instruments include PPAs, tolling arrangements, Heat Rate swaps and options, retail power sales including through our retail subsidiaries, steam sales, buying and selling standard physical power and natural gas products, buying and selling exchange traded instruments, buying and selling environmental and capacity products, natural gas transportation and storage arrangements, electric transmission service and other contracts for the sale and purchase of power products. We utilize these instruments to maximize the risk-adjusted returns for our Commodity Margin. Our retail portfolio has been established to provide an additional source of liquidity for our generation fleet as we hedge retail load from our wholesale generation assets as appropriate.
We conduct our hedging and optimization activities within a structured risk management framework based on controls, policies and procedures. We monitor these activities through active and ongoing management and oversight, defined roles and responsibilities, and daily risk estimates and reporting. Additionally, we seek to manage the associated risks through diversification, by controlling position sizes, by using portfolio position limits, and by actively managing hedge positions to lock in margin. We are exposed to commodity price movements (both profits and losses) in connection with these transactions. These positions are included in and subject to our consolidated risk management portfolio position limits and controls structure. Changes in fair value of commodity positions that do not qualify for or for which we do not elect either hedge accounting or the normal purchase normal sale exemption are recognized currently in earnings and are separately stated on our 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). Our future hedged status and marketing and optimization activities are subject to change as determined by our commercial operations group, Chief Risk Officer, senior management and Board of Directors.
At any point in time, the relative quantity of our products hedged or sold under longer-term contracts is determined by the availability of forward product sales opportunities and our view of the attractiveness of the pricing available for forward sales. We have economically hedged a portion of our expected generation and natural gas portfolio as well as retail load supply obligations, where appropriate, mostly through power and natural gas forward physical and financial transactions including retail power sales; however, we currently remain susceptible to significant price movements for 2019 and beyond. When we elect to enter into these transactions, we are able to economically hedge a portion of our Spark Spread at pre-determined generation and price levels.
We have historically used interest rate hedging instruments to adjust the mix between our fixed and variable rate debt. To the extent eligible, our interest rate hedging instruments have been designated as cash flow hedges, and changes in fair value are recorded in OCI with gains and losses reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. See Note 8 of the Notes to Consolidated Condensed Financial Statements for further discussion of our derivative instruments.
The primary factors affecting our market risk and the fair value of our derivatives 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; our credit standing and that of our counterparties for energy commodity derivatives; and prevailing interest rates for our interest rate hedging instruments. 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 increased to approximately $415 million at June 30, 2019, compared to approximately $302 million at December 31, 2018, and our derivative liabilities have decreased to approximately $284 million at June 30, 2019, compared to approximately $443 million at December 31, 2018. The fair value of our level 3 derivative assets and liabilities at June 30, 2019 represents approximately 52% and 26% of our total assets and liabilities measured at fair value, respectively. See Note 7 of the Notes to Consolidated Condensed Financial Statements for further information related to our level 3 derivative assets and liabilities.
49

The change in fair value of our outstanding commodity and interest rate hedging instruments from January 1, 2019, through June 30, 2019, is summarized in the table below (in millions):

| Commodity Instruments |  | Interest Rate Hedging Instruments |  | Total
Fair value of contracts outstanding at January 1, 2019 | $ | (171 | ) |  | $ | 30 |  |  | $ | (141 | )
Items recognized or otherwise settled during the period(1)(2) | (153 | ) |  | (12 | ) |  | (165 | )
Fair value attributable to new contracts(3) | 125 |  |  | — |  |  | 125 |
Changes in fair value attributable to price movements | 357 |  |  | (45 | ) |  | 312 |
Fair value of contracts outstanding at June 30, 2019(4) | $ | 158 |  |  | $ | (27 | ) |  | $ | 131 |

__________

(1) | Commodity contract settlements consist of the realization of previously recognized gains on contracts not designated as hedging instruments of $151 million (represents a portion of Commodity revenue and Commodity expense as reported on our Consolidated Condensed Statements of Operations) and $(2) million related to current period losses from other changes in derivative assets and liabilities not reflected in OCI or earnings.

(2) | Interest rate settlements consist of $12 million related to realized gains from settlements of designated cash flow hedges and nil related to roll-off from settlements of undesignated interest rate hedging instruments (represents a portion of interest expense as reported on our Consolidated Condensed Statements of Operations).

(3) | Fair value attributable to new contracts includes $(1) million and nil of fair value related to commodity contracts and interest rate hedging instruments, respectively, which are not reflected in OCI or earnings.

(4) | We netted all amounts allowed under the derivative accounting guidance on our Consolidated Condensed Balance Sheet, which includes derivative transactions under enforceable master netting arrangements and related cash collateral. Net commodity and interest rate derivative assets and liabilities reported in Notes 7 and 8 of the Notes to Consolidated Condensed Financial Statements are shown net of collateral paid to and received from counterparties under legally enforceable master netting arrangements.

Commodity Price Risk — Commodity price risks result from exposure to changes in spot prices, forward prices, price volatilities and correlations between the price of power, steam and natural gas. We manage the commodity price risk and the variability in future cash flows from forecasted sales of power and purchases of natural gas of our entire portfolio of generating assets and contractual positions by entering into various derivative and non-derivative instruments.
The net fair value of outstanding derivative commodity instruments, net of allocated collateral, at June 30, 2019, based on price source and the period during which the instruments will mature, are summarized in the table below (in millions):

Fair Value Source |  | 2019 |  | 2020-2021 |  | 2022-2023 |  | After 2023 |  | Total
Prices actively quoted |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Prices provided by other external sources |  | (53 | ) |  | (20 | ) |  | 4 |  |  | — |  |  | (69 | )
Prices based on models and other valuation methods |  | 42 |  |  | 93 |  |  | 40 |  |  | 52 |  |  | 227 |
Total fair value |  | $ | (11 | ) |  | $ | 73 |  |  | $ | 44 |  |  | $ | 52 |  |  | $ | 158 |

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 upon historical experience resulting from potential market movements. Our VAR is calculated for our entire portfolio comprising energy commodity derivatives, expected generation and 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.
50

The table below presents the high, low and average of our daily VAR for the three and six months ended June 30, 2019 and 2018 (in millions):

| 2019 |  | 2018
Three months ended June 30: |  |  |
High | $ | 39 |  |  | $ | 45 |
Low | $ | 22 |  |  | $ | 24 |
Average | $ | 28 |  |  | $ | 33 |
Six months ended June 30: |  |  |
High | $ | 50 |  |  | $ | 45 |
Low | $ | 22 |  |  | $ | 19 |
Average | $ | 32 |  |  | $ | 30 |
As of June 30 | $ | 37 |  |  | $ | 34 |

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. In order 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, including stress testing, 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. If the number of counterparties in these markets were to decrease, 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 9 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 customer’s 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.

We have concentrations of credit risk with a few of our wholesale counterparties 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 recent wildfires in California and, accordingly, incur substantial costs associated with the wildfires.
On January 29, 2019, PG&E and PG&E Corporation each filed voluntary petitions for relief under Chapter 11. We currently have several power plants that provide energy and energy-related products to PG&E under PPAs, many of which have PG&E collateral posting requirements. Since the bankruptcy filing, we have received all material payments under the PPAs, either directly or through the application of collateral. We also currently have numerous other agreements with PG&E related to the operation of our power plants in Northern California, under which PG&E has continued to provide service since its bankruptcy
51

filing. We cannot predict the ultimate outcome of this matter and continue to monitor the bankruptcy proceedings. See Note 6 of the Notes to Consolidated Condensed Financial Statements for further information related to the event of default associated with our Russell City and Los Esteros project debt agreements in connection with the PG&E bankruptcy.
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 on 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 June 30, 2019, and the period during which the instruments will mature are summarized in the table below (in millions):

Credit Quality (Based on Credit Ratings as of June 30, 2019) |  | 2019 |  | 2020-2021 |  | 2022-2023 |  | After 2023 |  | Total
Investment grade |  | $ | (56 | ) |  | $ | (3 | ) |  | $ | 16 |  |  | $ | 24 |  |  | $ | (19 | )
Non-investment grade |  | 4 |  |  | (4 | ) |  | (2 | ) |  | — |  |  | (2 | )
No external ratings(1) |  | 41 |  |  | 80 |  |  | 30 |  |  | 28 |  |  | 179 |
Total fair value |  | $ | (11 | ) |  | $ | 73 |  |  | $ | 44 |  |  | $ | 52 |  |  | $ | 158 |

__________

(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 LIBOR. 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 $(10) million at June 30, 2019.
New Accounting Standards and Disclosure Requirements
See Note 1 of the Notes to Consolidated Condensed Financial Statements for a discussion of new accounting standards and disclosure requirements.

Item 3. | Quantitative and Qualitative Disclosures About Market Risk

The information required to be disclosed under this Item 3 is set forth under Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Risk Management and Commodity Accounting.” This information should be read in conjunction with the information disclosed in our 2018 Form 10-K.

Item 4. | Controls and Procedures

Disclosure Controls and Procedures
As of the end of the period covered by this Report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rule 13a-15(e) and Rule 15d-15(e) of the Exchange Act. Based upon, and as of the date of, this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective such that the information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Changes in Internal Control Over Financial Reporting
During the second quarter of 2019, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
52

PART II — OTHER INFORMATION

Item 1. | Legal Proceedings

See Note 11 of the Notes to Consolidated Condensed Financial Statements for a description of our legal proceedings.

Item 1A. | Risk Factors

There were no material changes to the description of the risk factors associated with our business previously disclosed in Part I, Item 1A “Risk Factors” of our 2018 Form 10-K.

Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. | Defaults Upon Senior Securities

None.

Item 4. | Mine Safety Disclosures

Not applicable.

Item 5. | Other Information

None.
53

Item 6. | Exhibits

EXHIBIT INDEX

Exhibit Number |  | Description
10.1 |  | Amendment No. 9 to the Credit Agreement, dated as of April 5, 2019, among Calpine Corporation, as borrower, the guarantors party thereto, MUFG Bank, Ltd, as administrative agent, MUFG Union Bank, N.A., as collateral agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on April 5, 2019).
10.2 |  | Credit Agreement, dated April 5, 2019 among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent, and MUFG Union Bank, N.A., as collateral agent (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on April 5, 2019).
10.3 |  | Amendment to Award Agreement of Class B Interest in CPN Management, LP to Charles M. Gates dated April 26, 2019.†
10.4 |  | Second Amendment to Award Agreement of Class B Interest in CPN Management, LP to Charles M. Gates dated July 23, 2019.†
10.5 |  | Award Agreement of Class B Interest in CPN Management, LP to Charles M. Gates dated June 28, 2019.†
10.6 |  | Letter Agreement, dated August 7, 2019, between the Company and Charles M. Gates.†
31.1 |  | Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 |  | Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 |  | Certification of the Chief Executive Officer and the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. *
101.INS |  | XBRL Instance Document.
101.SCH |  | XBRL Taxonomy Extension Schema.
101.CAL |  | XBRL Taxonomy Extension Calculation Linkbase.
101.DEF |  | XBRL Taxonomy Extension Definition Linkbase.
101.LAB |  | XBRL Taxonomy Extension Label Linkbase.
101.PRE |  | XBRL Taxonomy Extension Presentation Linkbase.

_______________

* | Furnished herewith.

† | Management contract or compensatory plan, contract or arrangement.

54

SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.

CALPINE CORPORATION
(Registrant)
By: |  | /s/ ZAMIR RAUF
|  | Zamir Rauf Executive Vice President and Chief Financial Officer (Principal Financial Officer)

Date: August 7, 2019
55