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 September 30, 2017
|  | 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)
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 [X] No [ ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted 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 and post 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 | [X] |  | Accelerated filer | [ ]
Non-accelerated filer | [ ] | (Do not check if a smaller reporting company) | 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: 360,581,879 shares of common stock, par value $0.001, were outstanding as of October 30, 2017.

CALPINE CORPORATION AND SUBSIDIARIES
REPORT ON FORM 10-Q
For the Quarter Ended September 30, 2017
INDEX

| Page
Definitions | ii
Forward-Looking Statements | vii
Where You Can Find Other Information | viii
PART I – FINANCIAL INFORMATION |
Item 1. Financial Statements | 1
Consolidated Condensed Statements of Operations for the Three and Nine Months Ended September 30, 2017 and 2016 | 1
Consolidated Condensed Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2017 and 2016 | 2
Consolidated Condensed Balance Sheets at September 30, 2017 and December 31, 2016 | 3
Consolidated Condensed Statements of Cash Flows for the Nine Months Ended September 30, 2017 and 2016 | 4
Notes to Consolidated Condensed Financial Statements | 6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations | 32
Forward-Looking Information | 32
Introduction and Overview | 32
Results of Operations | 38
Commodity Margin and Adjusted Free Cash Flow | 43
Liquidity and Capital Resources | 48
Risk Management and Commodity Accounting | 52
New Accounting Standards and Disclosure Requirements | 55
Item 3. Quantitative and Qualitative Disclosures About Market Risk | 55
Item 4. Controls and Procedures | 55
PART II – OTHER INFORMATION |
Item 1. Legal Proceedings | 56
Item 1A. Risk Factors | 56
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds | 58
Item 3. Defaults Upon Senior Securities | 58
Item 4. Mine Safety Disclosures | 58
Item 5. Other Information | 58
Item 6. Exhibits | 59
Signatures | 60

i

DEFINITIONS
As used in this report for the quarter ended September 30, 2017 (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
2008 Director Plan |  | The Amended and Restated Calpine Corporation 2008 Director Incentive Plan
2008 Equity Plan |  | The Amended and Restated Calpine Corporation 2008 Equity Incentive Plan
2016 Form 10-K |  | Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2016, filed with the SEC on February 10, 2017
2017 Director Plan |  | The Calpine Corporation 2017 Equity Compensation Plan for Non-Employee Directors
2017 Equity Plan |  | The Calpine Corporation 2017 Equity Incentive Plan
2017 First Lien Term Loan |  | The $550 million first lien senior secured term loan, dated December 1, 2016, 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, partially repaid on March 16, 2017, August 31, 2017, September 29, 2017 and October 31, 2017
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
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 Notes |  | The $1.2 billion aggregate principal amount of 7.875% senior secured notes due 2023, issued January 14, 2011, repaid in series of transactions on November 7, 2012, December 2, 2013, December 4, 2014, February 3, 2015, December 7, 2015, December 19, 2016 and March 6, 2017
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 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

ii

ABBREVIATION |  | DEFINITION
2026 First Lien Notes |  | The $625 million aggregate principal amount of 5.25% senior unsecured notes due 2026, issued May 31, 2016
AB 32 |  | California Assembly Bill 32
Accounts Receivable Sales Program |  | Receivables purchase agreement between Calpine Solutions and Calpine Receivables and the purchase and sale agreement between Calpine Receivables and an unaffiliated financial institution, both which allows for the revolving sale of up to $250 million in certain trade accounts receivables to third parties
Adjusted EBITDA |  | EBITDA as adjusted for the effects of (a) impairment charges, (b) major maintenance expense, (c) operating lease expense, (d) gains or losses on commodity derivative mark-to-market activity, (e) adjustments to reflect only the Adjusted EBITDA from our unconsolidated investments, (f) adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, (g) stock-based compensation expense, (h) gains or losses on sales, dispositions or retirements of assets, (i) non-cash gains and losses from foreign currency translations, (j) gains or losses on the repurchase, modification or extinguishment of debt, (k) non-cash GAAP-related adjustments to levelize revenues from tolling agreements and (l) other unusual or non-recurring items
Adjusted Free Cash Flow |  | Cash flows from operating activities adjusted for the effects of changes in working capital, maintenance capital expenditures, adjustments to reflect the Adjusted Free Cash Flow from unconsolidated investments and to exclude the noncontrolling interest and other miscellaneous items
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
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
CAISO |  | California Independent System Operator which is an entity that manages the power grid and operates the competitive power market in California
Calpine Equity Incentive Plans |  | Collectively, the Director Plans and the Equity Plans, which provide for grants of equity awards to Calpine non-union employees and non-employee members of Calpine’s Board of Directors
Calpine Receivables |  | Calpine Receivables, LLC, formerly Noble Americas Treasury Solutions LLC, an indirect, wholly-owned subsidiary of Calpine, which was established as a bankruptcy remote, special purpose subsidiary and is responsible for administering the Accounts Receivable Sales Program
Calpine Solutions |  | Calpine Energy Solutions, LLC, formerly Noble Solutions, an indirect, wholly-owned subsidiary of Calpine, which is the third largest supplier of power to commercial and industrial retail customers in the United States with customers in 19 states, including presence in California, Texas, the Mid-Atlantic and the Northeast
Cap-and-Trade |  | A government imposed emissions reduction program that would place a cap on the amount of emissions that can be emitted from certain sources, such as power plants. In its simplest form, the cap amount is set as a reduction from the total emissions during a base year and for each year over a period of years the cap amount would be reduced to achieve the targeted overall reduction by the end of the period. Allowances or credits for emissions in an amount equal to the cap would be issued or auctioned to companies with facilities, permitting them to emit up to a certain amount of emissions during each applicable period. After allowances have been distributed or auctioned, they can be transferred or traded
CARB |  | California Air Resources Board

iii

ABBREVIATION |  | DEFINITION
CCFC |  | Calpine Construction Finance Company, L.P., an indirect, wholly-owned subsidiary of Calpine
CCFC Term Loans |  | Collectively, the $900 million first lien senior secured term loan and the $300 million first lien senior secured term loan entered into on May 3, 2013, and the $425 million first lien senior secured term loan entered into on February 26, 2014, between CCFC, as borrower, and Goldman Sachs Lending Partners, LLC, as administrative agent and as collateral agent, and the lenders party thereto
CDHI |  | Calpine Development Holdings, Inc., an indirect, wholly-owned subsidiary of Calpine
CFTC |  | Commodities Futures Trading Commission
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 Texas, Illinois, Pennsylvania, Ohio, New Jersey, Maryland, Massachusetts, New York, Delaware, Maine, Connecticut, California, New Hampshire and the District of Columbia
CO 2 |  | Carbon dioxide
COD |  | Commercial operations date
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 and realized settlements from our marketing, hedging and optimization activities including natural gas and fuel oil transactions hedging future power sales
Commodity Margin |  | Non-GAAP financial measure 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 activity, fuel and purchased energy expenses, commodity transmission and transportation expenses and environmental compliance expenses
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 $1.8 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 and October 20, 2017 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
Director Plans |  | Collectively, the 2008 Director Plan and the 2017 Director Plan
EBITDA |  | Net income (loss) attributable to Calpine before net (income) loss attributable to the noncontrolling interest, interest, taxes, depreciation and amortization
Equity Plans |  | Collectively, the 2008 Equity Plan and the 2017 Equity Plan
ERCOT |  | Electric Reliability Council of Texas which is an entity that manages the flow of electric power to Texas customers representing approximately 90 percent of the state’s electric load
Exchange Act |  | U.S. Securities Exchange Act of 1934, as amended
FASB |  | Financial Accounting Standards Board

iv

ABBREVIATION |  | DEFINITION
FDIC |  | U.S. Federal Deposit Insurance Corporation
FERC |  | U.S. Federal Energy Regulatory Commission
First Lien Notes |  | Collectively, the 2022 First Lien Notes, the 2023 First Lien Notes, the 2024 First Lien Notes and the 2026 First Lien Notes
First Lien Term Loans |  | Collectively, the 2017 First Lien Term Loan, the 2019 First Lien Term Loan, the 2023 First Lien Term Loans and the 2024 First Lien Term Loan
Geysers Assets |  | Our geothermal power plant assets, including our steam extraction and gathering assets, located in northern California consisting of 13 operating power plants
GHG(s) |  | Greenhouse gas(es), primarily carbon dioxide (CO 2), and including methane (CH 4), nitrous oxide (N 2 O), sulfur hexafluoride (SF 6), hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs)
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
IESO |  | Independent Electricity System Operator which is a RTO that coordinates the supply and demand for electricity in the Canadian province of Ontario
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
ISO-NE |  | ISO New England Inc., an independent, nonprofit RTO serving states in the New England area, including Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont
KWh |  | Kilowatt hour(s), a measure of power produced, purchased or sold
LIBOR |  | London Inter-Bank Offered Rate
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
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
Noble Solutions |  | Noble Americas Energy Solutions LLC, which was legally renamed Calpine Energy Solutions, LLC on December 1, 2016 following the completion of its acquisition by an indirect, wholly-owned subsidiary of Calpine Corporation
NOL(s) |  | Net operating loss(es)
North American Power |  | North American Power & Gas, LLC, an indirect, wholly-owned subsidiary of Calpine, which was acquired on January 17, 2017 and is a growing retail energy supplier for homes and small businesses primarily concentrated in the Northeast U.S.

v

ABBREVIATION |  | DEFINITION
NYISO |  | New York ISO which operates competitive wholesale markets to manage the flow of electricity across New York
NYMEX |  | New York Mercantile Exchange
OCI |  | Other Comprehensive Income
OTC |  | Over-the-Counter
PJM |  | PJM Interconnection is a RTO that coordinates the movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia
PPA(s) |  | Any term power purchase agreement or other contract for a physically settled sale (as distinguished from a financially settled future, option or 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
PUCT |  | Public Utility Commission of Texas
REC(s) |  | Renewable energy credit(s)
Risk Management Policy |  | Calpine’s policy applicable to all employees, contractors, representatives and agents, which defines the risk management framework and corporate governance structure for commodity risk, interest rate risk, currency risk and other risks
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
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

vi

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:

• | Risks and uncertainties associated with the Merger, including (i) any event that could give rise to termination of the Merger Agreement or otherwise cause failure of the Merger to close, (ii) failure to obtain requisite stockholder or regulatory approval for the Merger, (iii) the effect of the Merger on our relationships with customers and employees, (iv) the effect of the Merger on our financial results and business and (v) potential termination fees associated with the Merger Agreement and other Merger-related fees and expenses incurred.

• | 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 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 Loans 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;

• | Competition, including from renewable sources of power, interference by states in competitive power markets through subsidies or similar support for new or existing power plants, 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;

• | 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, CFTC, FERC and other regulatory bodies; and

• | Other risks identified in this Report, in our 2016 Form 10-K and in other reports filed by us with the SEC.

vii

Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of the date of this Report. Other than as required by law, we undertake no obligation to update or revise forward-looking statements, whether as a result of new information, future events, or otherwise.
Where You Can Find Other Information
Our website is www.calpine.com. 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, on our website as soon as reasonably practicable after such materials are filed with or furnished to the SEC. Our SEC filings, including exhibits filed therewith, are also available on the SEC’s website at www.sec.gov. You may obtain and copy any document we furnish or file with the SEC at the SEC’s public reference room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the SEC’s public reference facilities by calling the SEC at 1-800-SEC-0330. You may request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at its principal office at 100 F Street, NE, Room 1580, Washington, D.C. 20549.
viii

PART I — FINANCIAL INFORMATION

Item 1. | Financial Statements

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

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2017 |  | 2016 |  | 2017 |  | 2016
| (in millions, except share and per share amounts)
Operating revenues: |  |  |  |  |  |  |
Commodity revenue | $ | 2,506 |  |  | $ | 2,063 |  |  | $ | 6,714 |  |  | $ | 5,199 |
Mark-to-market gain (loss) | 76 |  |  | 287 |  |  | 224 |  |  | (79 | )
Other revenue | 4 |  |  | 5 |  |  | 13 |  |  | 14 |
Operating revenues | 2,586 |  |  | 2,355 |  |  | 6,951 |  |  | 5,134 |
Operating expenses: |  |  |  |  |  |  |
Fuel and purchased energy expense: |  |  |  |  |  |  |
Commodity expense | 1,711 |  |  | 1,294 |  |  | 4,757 |  |  | 3,197 |
Mark-to-market (gain) loss | 10 |  |  | 178 |  |  | 185 |  |  | (57 | )
Fuel and purchased energy expense | 1,721 |  |  | 1,472 |  |  | 4,942 |  |  | 3,140 |
Plant operating expense | 228 |  |  | 215 |  |  | 812 |  |  | 741 |
Depreciation and amortization expense | 179 |  |  | 161 |  |  | 542 |  |  | 490 |
Sales, general and other administrative expense | 37 |  |  | 33 |  |  | 117 |  |  | 106 |
Other operating expenses | 23 |  |  | 18 |  |  | 63 |  |  | 55 |
Total operating expenses | 2,188 |  |  | 1,899 |  |  | 6,476 |  |  | 4,532 |
Impairment losses | 12 |  |  | — |  |  | 41 |  |  | 13 |
(Gain) on sale of assets, net | — |  |  | — |  |  | (27 | ) |  | — |
(Income) from unconsolidated subsidiaries | (7 | ) |  | (6 | ) |  | (17 | ) |  | (16 | )
Income from operations | 393 |  |  | 462 |  |  | 478 |  |  | 605 |
Interest expense | 156 |  |  | 158 |  |  | 469 |  |  | 472 |
Debt extinguishment costs | 1 |  |  | — |  |  | 26 |  |  | 15 |
Other (income) expense, net | 7 |  |  | 7 |  |  | 16 |  |  | 18 |
Income (loss) before income taxes | 229 |  |  | 297 |  |  | (33 | ) |  | 100 |
Income tax expense (benefit) | (2 | ) |  | (4 | ) |  | — |  |  | 17 |
Net income (loss) | 231 |  |  | 301 |  |  | (33 | ) |  | 83 |
Net income attributable to the noncontrolling interest | (6 | ) |  | (6 | ) |  | (14 | ) |  | (15 | )
Net income (loss) attributable to Calpine | $ | 225 |  |  | $ | 295 |  |  | $ | (47 | ) |  | $ | 68 |
Basic earnings (loss) per common share attributable to Calpine: |  |  |  |  |  |  |
Weighted average shares of common stock outstanding (in thousands) | 355,442 |  |  | 354,215 |  |  | 355,164 |  |  | 353,929 |
Net income (loss) per common share attributable to Calpine — basic | $ | 0.63 |  |  | $ | 0.83 |  |  | $ | (0.13 | ) |  | $ | 0.19 |
Diluted earnings (loss) per common share attributable to Calpine: |  |  |  |  |  |  |
Weighted average shares of common stock outstanding (in thousands) | 358,844 |  |  | 356,352 |  |  | 355,164 |  |  | 355,980 |
Net income (loss) per common share attributable to Calpine — diluted | $ | 0.63 |  |  | $ | 0.83 |  |  | $ | (0.13 | ) |  | $ | 0.19 |

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 September 30, |  | Nine Months Ended September 30,
| 2017 |  | 2016 |  | 2017 |  | 2016
| (in millions)
Net income (loss) | $ | 231 |  |  | $ | 301 |  |  | $ | (33 | ) |  | $ | 83 |
Cash flow hedging activities: |  |  |  |  |  |  |
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income (loss) | (3 | ) |  | 7 |  |  | (44 | ) |  | (33 | )
Reclassification adjustment for loss on cash flow hedges realized in net income (loss) | 11 |  |  | 11 |  |  | 37 |  |  | 33 |
Foreign currency translation gain (loss) | 7 |  |  | (3 | ) |  | 13 |  |  | 9 |
Income tax expense | (1 | ) |  | — |  |  | (3 | ) |  | — |
Other comprehensive income | 14 |  |  | 15 |  |  | 3 |  |  | 9 |
Comprehensive income (loss) | 245 |  |  | 316 |  |  | (30 | ) |  | 92 |
Comprehensive (income) attributable to the noncontrolling interest | (7 | ) |  | (8 | ) |  | (15 | ) |  | (15 | )
Comprehensive income (loss) attributable to Calpine | $ | 238 |  |  | $ | 308 |  |  | $ | (45 | ) |  | $ | 77 |

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

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited)

|  | September 30, |  | December 31,
|  | 2017 |  | 2016
|  | (in millions, except share and per share amounts)
ASSETS |  |  |  |
Current assets: |  |  |  |
Cash and cash equivalents ($55 and $79 attributable to VIEs) |  | $ | 426 |  |  | $ | 418 |
Accounts receivable, net of allowance of $9 and $6 |  | 935 |  |  | 839 |
Inventories |  | 409 |  |  | 581 |
Margin deposits and other prepaid expense |  | 182 |  |  | 364 |
Restricted cash, current ($126 and $109 attributable to VIEs) |  | 196 |  |  | 173 |
Derivative assets, current |  | 206 |  |  | 221 |
Current assets held for sale (nil and $134 attributable to VIEs) |  | — |  |  | 210 |
Other current assets |  | 34 |  |  | 45 |
Total current assets |  | 2,388 |  |  | 2,851 |
Property, plant and equipment, net ($4,099 and $3,979 attributable to VIEs) |  | 12,833 |  |  | 13,013 |
Restricted cash, net of current portion ($25 and $14 attributable to VIEs) |  | 26 |  |  | 15 |
Investments in unconsolidated subsidiaries |  | 106 |  |  | 99 |
Long-term derivative assets |  | 284 |  |  | 300 |
Goodwill |  | 243 |  |  | 187 |
Intangible assets, net |  | 552 |  |  | 650 |
Other assets ($58 and $56 attributable to VIEs) |  | 360 |  |  | 378 |
Total assets |  | $ | 16,792 |  |  | $ | 17,493 |
LIABILITIES & STOCKHOLDERS’ EQUITY |  |  |  |
Current liabilities: |  |  |  |
Accounts payable |  | $ | 756 |  |  | $ | 671 |
Accrued interest payable |  | 129 |  |  | 125 |
Debt, current portion ($181 and $176 attributable to VIEs) |  | 369 |  |  | 748 |
Derivative liabilities, current |  | 113 |  |  | 138 |
Other current liabilities |  | 427 |  |  | 523 |
Total current liabilities |  | 1,794 |  |  | 2,205 |
Debt, net of current portion ($2,867 and $2,944 attributable to VIEs) |  | 11,281 |  |  | 11,431 |
Long-term derivative liabilities |  | 103 |  |  | 149 |
Other long-term liabilities |  | 291 |  |  | 369 |
Total liabilities |  | 13,469 |  |  | 14,154 |
Commitments and contingencies (see Note 11) |  |  |  |
Stockholders’ equity: |  |  |  |
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding |  | — |  |  | — |
Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 361,695,622 and 359,627,113 shares issued, respectively, and 360,613,587 and 359,061,764 shares outstanding, respectively |  | — |  |  | — |
Treasury stock, at cost, 1,082,035 and 565,349 shares, respectively |  | (13 | ) |  | (7 | )
Additional paid-in capital |  | 9,652 |  |  | 9,625 |
Accumulated deficit |  | (6,260 | ) |  | (6,213 | )
Accumulated other comprehensive loss |  | (135 | ) |  | (137 | )
Total Calpine stockholders’ equity |  | 3,244 |  |  | 3,268 |
Noncontrolling interest |  | 79 |  |  | 71 |
Total stockholders’ equity |  | 3,323 |  |  | 3,339 |
Total liabilities and stockholders’ equity |  | $ | 16,792 |  |  | $ | 17,493 |

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

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

|  | Nine Months Ended September 30,
|  | 2017 |  | 2016
|  | (in millions)
Cash flows from operating activities: |  |  |  |
Net income (loss) |  | $ | (33 | ) |  | $ | 83 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |  |  |  |
Depreciation and amortization(1) |  | 691 |  |  | 659 |
Debt extinguishment costs |  | 8 |  |  | 15 |
Income taxes |  | 12 |  |  | 15 |
Impairment losses |  | 41 |  |  | 13 |
Gain on sale of assets, net |  | (27 | ) |  | — |
Mark-to-market activity, net |  | (40 | ) |  | 21 |
(Income) from unconsolidated subsidiaries |  | (17 | ) |  | (16 | )
Return on investments from unconsolidated subsidiaries |  | 22 |  |  | 19 |
Stock-based compensation expense |  | 31 |  |  | 23 |
Other |  | (4 | ) |  | 1 |
Change in operating assets and liabilities, net of effects of acquisitions: |  |  |  |
Accounts receivable |  | (86 | ) |  | (168 | )
Derivative instruments, net |  | (10 | ) |  | (154 | )
Other assets |  | 60 |  |  | 1 |
Accounts payable and accrued expenses |  | 95 |  |  | 53 |
Other liabilities |  | 64 |  |  | 102 |
Net cash provided by operating activities |  | 807 |  |  | 667 |
Cash flows from investing activities: |  |  |  |
Purchases of property, plant and equipment |  | (248 | ) |  | (337 | )
Proceeds from sale of Osprey Energy Center |  | 162 |  |  | — |
Purchase of Granite Ridge Energy Center |  | — |  |  | (526 | )
Purchase of North American Power, net of cash acquired |  | (111 | ) |  | — |
(Increase) decrease in restricted cash |  | (33 | ) |  | 2 |
Other |  | 35 |  |  | 20 |
Net cash used in investing activities |  | (195 | ) |  | (841 | )
Cash flows from financing activities: |  |  |  |
Borrowings under First Lien Term Loans |  | 396 |  |  | 556 |
Repayment of CCFC Term Loans and First Lien Term Loans |  | (435 | ) |  | (1,220 | )
Repurchase of First Lien Notes |  | (453 | ) |  | — |
Borrowings under First Lien Notes |  | — |  |  | 625 |
Repayments of project financing, notes payable and other |  | (90 | ) |  | (98 | )
Distribution to noncontrolling interest holder |  | (8 | ) |  | — |
Financing costs |  | (9 | ) |  | (27 | )
Shares repurchased for tax withholding on stock-based awards |  | (6 | ) |  | (5 | )
Other |  | 1 |  |  | (2 | )
Net cash used in financing activities |  | (604 | ) |  | (171 | )
Net increase (decrease) in cash and cash equivalents |  | 8 |  |  | (345 | )
Cash and cash equivalents, beginning of period |  | 418 |  |  | 906 |
Cash and cash equivalents, end of period |  | $ | 426 |  |  | $ | 561 |

The accompanying notes are an integral part of these Consolidated Condensed Financial Statements.
4

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

|  | Nine Months Ended September 30,
|  | 2017 |  | 2016
|  | (in millions)
Cash paid during the period for: |  |  |  |
Interest, net of amounts capitalized |  | $ | 412 |  |  | $ | 421 |
Income taxes |  | $ | 10 |  |  | $ | 10 |
Supplemental disclosure of non-cash investing and financing activities: |  |  |  |
Change in capital expenditures included in accounts payable |  | $ | 14 |  |  | $ | (4 | )
Purchase of King City Cogeneration Plant lease(2) |  | $ | 15 |  |  | $ | — |

____________

(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) | On April 3, 2017, we completed the purchase of the King City Cogeneration Plant lease in exchange for a three-year promissory note with a discounted value of $57 million. We recorded a net increase to property, plant and equipment, net on our Consolidated Condensed Balance Sheet of $15 million due to the increased value of the promissory note as compared to the carrying value of the lease.

The accompanying notes are an integral part of these Consolidated Condensed Financial Statements.
5

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
September 30, 2017
(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 power markets in California (included in our West segment), Texas (included in our Texas segment) and the Northeast and Mid-Atlantic regions (included in our East segment) 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 getting closer to our customers through expansion of our retail platform which began with the acquisition of Champion Energy in 2015 and was followed by the acquisitions of Calpine Solutions in late 2016 and North American Power in early 2017. 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.
Merger Agreement — On August 17, 2017, we entered into the Merger Agreement with Volt Parent, LP (“Volt Parent”) and Volt Merger Sub, Inc. (“Merger Sub”), a wholly-owned subsidiary of Volt Parent, pursuant to which Merger Sub will merge with and into Calpine, with Calpine surviving the Merger as a subsidiary of Volt Parent.
At the effective time of the Merger, each share of Calpine’s common stock outstanding as of immediately prior to the effective time of the Merger (excluding common shares held directly by Volt Parent or Merger Sub, common shares held by Calpine as treasury stock, common shares that are subject to vesting or other applicable lapse restrictions, common shares held by any subsidiary of either Calpine or Volt Parent (other than Merger Sub), common shares held by Volt Energy Holdings, LP (“Volt Energy”), an affiliate of Energy Capital Partners III, LLC (“ECP”), and common shares pursuant to which dissenting rights under Delaware law have been properly exercised and not withdrawn or lost) will, at the effective time of the Merger, cease to be outstanding and be converted into the right to receive $15.25 per share in cash or approximately $5.6 billion. Calpine currently expects the Merger to be completed in the first quarter of 2018, subject to approval by stockholders representing a majority of outstanding shares of Calpine common stock, the receipt of certain regulatory approvals and the satisfaction or waiver of certain other customary closing conditions.
The Merger Agreement provides that, during the period beginning on August 17, 2017 and continuing through October 2, 2017, Calpine and its subsidiaries could solicit, initiate, facilitate or encourage “Alternative Transaction Proposals” (as defined in the Merger Agreement) from certain third parties. No Alternative Transaction Proposals were received prior to October 2, 2017. On October 2, 2017, we became subject to customary “no shop” restrictions prohibiting us from soliciting, facilitating, encouraging, discussing, negotiating or cooperating with respect to any “Alternative Transaction Proposals” or providing information to or participating in any discussions or negotiations with third parties regarding “Alternative Transaction Proposals”, subject to certain customary exceptions to permit our Board of Directors to comply with its fiduciary duties.
The Board of Directors has unanimously resolved to recommend that Calpine’s stockholders vote in favor of adoption of the Merger Agreement and the transactions contemplated thereby, including the Merger. Calpine’s stockholders will be asked to vote on the adoption of the Merger Agreement at a special stockholders’ meeting that will be held on a date to be announced as promptly as reasonably practicable following the customary SEC review process. The consummation of the Merger is subject to a condition that the Merger Agreement be adopted by the affirmative vote of the holders of at least a majority of the outstanding shares of Calpine’s common stock entitled to vote, the receipt of certain regulatory approvals and the satisfaction or waiver of certain other customary closing conditions.
The Merger Agreement contains certain termination rights, including, among others, the right of Calpine to terminate the Merger Agreement to accept a “Superior Proposal”, subject to specified limitations and payment by Calpine of a termination fee. The Merger Agreement also provides that Volt Parent will be required to pay Calpine a reverse termination fee under specified circumstances.
For further information on the Merger and the Merger Agreement, please refer to the Current Report on Form 8-K filed on August 22, 2017 and the preliminary proxy statement filed on October 19, 2017 by Calpine. The foregoing descriptions of the
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Merger Agreement is subject to, and qualified in its entirety by, the full text of the agreement as attached as an exhibit to the Form 8-K filed on August 22, 2017, and is incorporated by reference herein.
On September 15, 2017, we amended our Corporate Revolving Facility to, among other things, provide that the Merger does not constitute a “Change of Control” thereunder, effective upon consummation of the Merger. On October 20, 2017, we further amended our Corporate Revolving Facility to extend the maturity and reduce the capacity under the revolving credit facility from $1.79 billion to $1.47 billion. Both amendments to the Corporate Revolving Facility are effective upon consummation of the Merger.
During the three and nine months ended September 30, 2017, we recorded approximately $11 million in merger-related costs which was recorded in other operating expenses on our Consolidated Condensed Statement of Operation and primarily related to legal, investment banking and other professional fees associated with the Merger.
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, 2016, included in our 2016 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 and Statements of Cash Flows.
The table below represents the components of our restricted cash as of September 30, 2017 and December 31, 2016 (in millions):

| September 30, 2017 |  | December 31, 2016
| Current |  | Non-Current |  | Total |  | Current |  | Non-Current |  | Total
Debt service | $ | 22 |  |  | $ | 7 |  |  | $ | 29 |  |  | $ | 11 |  |  | $ | 8 |  |  | $ | 19 |
Construction/major maintenance | 25 |  |  | 17 |  |  | 42 |  |  | 45 |  |  | 6 |  |  | 51 |
Security/project/insurance | 145 |  |  | — |  |  | 145 |  |  | 114 |  |  | — |  |  | 114 |
Other | 4 |  |  | 2 |  |  | 6 |  |  | 3 |  |  | 1 |  |  | 4 |
Total | $ | 196 |  |  | $ | 26 |  |  | $ | 222 |  |  | $ | 173 |  |  | $ | 15 |  |  | $ | 188 |

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Property, Plant and Equipment, Net — At September 30, 2017 and December 31, 2016, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):

| September 30, 2017 |  | December 31, 2016 |  | Depreciable Lives
Buildings, machinery and equipment | $ | 16,512 |  |  | $ | 16,468 |  |  | 3 | – | 46 | Years
Geothermal properties | 1,480 |  |  | 1,377 |  |  | 13 | – | 58 | Years
Other | 235 |  |  | 259 |  |  | 3 | – | 46 | Years
| 18,227 |  |  | 18,104 |  |  |  |  |  |
Less: Accumulated depreciation | 6,265 |  |  | 5,865 |  |  |  |  |  |
| 11,962 |  |  | 12,239 |  |  |  |  |  |
Land | 117 |  |  | 116 |  |  |  |  |  |
Construction in progress | 754 |  |  | 658 |  |  |  |  |  |
Property, plant and equipment, net | $ | 12,833 |  |  | $ | 13,013 |  |  |  |  |  |

Capitalized Interest — The total amount of interest capitalized was $7 million and $5 million for the three months ended September 30, 2017 and 2016, respectively and $20 million and $14 million during the nine months ended September 30, 2017 and 2016, respectively.
Goodwill — We have not recorded any impairment losses associated with our goodwill. The change in goodwill by segment during the nine months ended September 30, 2017 was as follows (in millions):

| West |  | Texas |  | East |  | Total
Goodwill at December 31, 2016 | $ | 68 |  |  | $ | 31 |  |  | $ | 88 |  |  | $ | 187 |
Acquisition of North American Power | — |  |  | — |  |  | 49 |  |  | 49 |
Purchase price allocation adjustments(1) | (2 | ) |  | 1 |  |  | 8 |  |  | 7 |
Goodwill at September 30, 2017 | $ | 66 |  |  | $ | 32 |  |  | $ | 145 |  |  | $ | 243 |

____________

(1) | The purchase price allocation adjustment in the East segment represents adjustments of $17 million for North American Power and $(9) million for Calpine Solutions.

Related Party — Under the Accounts Receivables Sales Program, at September 30, 2017 and December 31, 2016, we had $228 million and $211 million, respectively, in trade accounts receivable outstanding that were sold to Calpine Receivables and $40 million and $32 million, respectively, in notes receivable from Calpine Receivables which were recorded on our Consolidated Condensed Balance Sheets. During the nine months ended September 30, 2017, we sold an aggregate of $1.6 billion in trade accounts receivable and recorded $1.6 billion in proceeds. For a further discussion of the Accounts Receivable Sales Program and Calpine Receivables, see Notes 2 and 5 in our 2016 Form 10-K.
Derivative Instruments — During 2008, we established our accounting policy related to the presentation of our derivative instruments on our Consolidated Condensed Balance Sheets. Historically, we separately reflected on a gross basis the fair value of our current and long-term derivative assets and liabilities and related cash collateral executed with the same counterparty under a master netting arrangement. Effective September 30, 2017, we reflect on a net basis the fair value amounts associated with our current and long-term derivative assets and liabilities and the related amounts recognized for the right to reclaim, or the obligation to return, cash collateral on our Consolidated Condensed Balance Sheets. This policy is preferable as it more accurately reflects counterparty credit risk, liquidity risk and the contractual rights and obligations under these arrangements.
The revised presentation of our derivative instruments is considered a change in accounting principle; thus, we retroactively applied the new accounting to our Consolidated Condensed Balance Sheet as of December 31, 2016 which did not result in a change in our total stockholder’s equity, results of operations or cash flows for any previously reported periods. See Notes 5, 6 and 7 for additional information on the assets and liabilities that are reflected on a net basis in our Consolidated Condensed Balance Sheets. The table below reflects the effect of the new accounting on previously reported financial information (in millions):
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|  | As Previously Reported |  | Effect of Offsetting Adjustment |  | As Adjusted
Consolidated Condensed Balance Sheet as of December 31, 2016 |  |  |  |  |  |
Margin deposits and other prepaid expense |  | $ | 441 |  |  | $ | (77 | ) |  | $ | 364 |
Derivative assets, current |  | $ | 1,725 |  |  | $ | (1,504 | ) |  | $ | 221 |
Total current assets |  | $ | 4,432 |  |  | $ | (1,581 | ) |  | $ | 2,851 |
Long-term derivative assets |  | $ | 543 |  |  | $ | (243 | ) |  | $ | 300 |
Total assets |  | $ | 19,317 |  |  | $ | (1,824 | ) |  | $ | 17,493 |
Derivative liabilities, current |  | $ | 1,630 |  |  | $ | (1,492 | ) |  | $ | 138 |
Other current liabilities |  | $ | 528 |  |  | $ | (5 | ) |  | $ | 523 |
Total current liabilities |  | $ | 3,702 |  |  | $ | (1,497 | ) |  | $ | 2,205 |
Long-term derivative liabilities |  | $ | 476 |  |  | $ | (327 | ) |  | $ | 149 |
Total liabilities |  | $ | 15,978 |  |  | $ | (1,824 | ) |  | $ | 14,154 |
Consolidated Condensed Statement of Cash Flows for the Nine Months Ended September 30, 2016 |  |  |  |  |  |
Change in operating assets and liabilities, net of effects of acquisitions: |  |  |  |  |  |
Derivative instruments, net |  | $ | (71 | ) |  | $ | (83 | ) |  | $ | (154 | )
Other assets |  | $ | (75 | ) |  | $ | 76 |  |  | $ | 1 |
Accounts payable and accrued expenses |  | $ | 46 |  |  | $ | 7 |  |  | $ | 53 |
Net cash provided by operating activities |  | $ | 667 |  |  | $ | — |  |  | $ | 667 |

New Accounting Standards and Disclosure Requirements
Revenue Recognition — In May 2014, the FASB issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers.” The comprehensive new revenue recognition standard will supersede all existing revenue recognition guidance. The core principle of the standard is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard also requires expanded disclosures surrounding revenue recognition. The standard allows for either full retrospective or modified retrospective adoption. In August 2015, the FASB deferred the effective date of Accounting Standards Update 2014-09 for public entities by one year, such that the standard will become effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017. The standard permits entities to adopt early, but only as of the original effective date. In March 2016, the FASB issued Accounting Standards Update 2016-08 “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)” which clarifies implementation guidance for principal versus agent considerations in the new revenue recognition standard. In May 2016, the FASB issued Accounting Standards Update 2016-12 “Narrow-Scope Improvements and Practical Expedients” which addresses assessing the collectability of a contract, the presentation of sales taxes and other taxes collected from customers, non-cash consideration and completed contracts and contract modifications at transition. We plan to adopt the standard in the first quarter of 2018 using the modified retrospective transition approach. We are finalizing our evaluation of the effect the revenue recognition standards will have on our revenue contracts such as our PPAs and tolling agreements as well as the additional disclosure requirements associated with the new standard; however, we do not expect the adoption of this standard will have a material effect on our financial condition, results of operations or cash flows. Upon adoption, we intend to elect the practical expedient that would allow an entity to recognize revenue in the amount to which the entity has the right to invoice to the extent we determine that we have a right to consideration from the customer in an amount that corresponds directly with the value provided based on our performance completed to date.
Inventory — In July 2015, the FASB issued Accounting Standards Update 2015-11, “Simplifying the Measurement of Inventory.” The standard changes the inventory valuation method from the lower of cost or market to the lower of cost or net realizable value for inventory valued under the first-in, first-out or average cost methods. This standard is effective for fiscal years beginning after December 15, 2016, including interim periods and requires prospective adoption with early adoption permitted. We adopted Accounting Standards Update 2015-11 in the first quarter of 2017 which did not have a material effect on our financial condition, results of operations or cash flows.
9

Leases — In February 2016, the FASB issued Accounting Standards Update 2016-02, “Leases.” The comprehensive new lease standard will supersede all existing lease guidance. The standard requires that a lessee should recognize a right-to-use asset and a lease liability for substantially all operating leases based on the present value of the minimum rental payments. Entities may make an accounting policy election to not recognize lease assets and liabilities for leases with a term of 12 months or less. For lessors, the accounting for leases remains substantially unchanged. The standard also requires expanded disclosures surrounding leases. The standard is effective for fiscal periods beginning after December 15, 2018, including interim periods within that reporting period and requires modified retrospective adoption with early adoption permitted. We expect to adopt the standard in the first quarter of 2019. We have completed our initial evaluation of the standard and believe that the key changes that will affect us relate to our accounting for operating leases that are currently off-balance sheet and tolling contracts which we currently account for as operating leases. Additionally, we are evaluating the potential effects of the removal of the real estate guidance currently applicable to lessors that will be abrogated under Accounting Standards Update 2014-09, “Revenue from Contracts with Customers.” We are also considering electing the practical expedient in our implementation of the standard; however, this may change as we complete our assessment of the standard.
Statement of Cash Flows — In August 2016, the FASB issued Accounting Standards Update 2016-15, “Classification of Certain Cash Receipts and Cash Payments.” The standard addresses several matters of diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows including the presentation of debt extinguishment costs and distributions received from equity method investments. The standard is effective for fiscal years beginning after December 15, 2017, including interim periods and requires retrospective adoption with early adoption permitted. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.
Restricted Cash — In November 2016, the FASB issued Accounting Standards Update 2016-18, “Restricted Cash.” The standard requires restricted cash to be included with cash and cash equivalents when reconciling the beginning and ending amounts in the statement of cash flows and also requires disclosures regarding the nature of restrictions on cash, cash equivalents and restricted cash. The standard is effective for fiscal years beginning after December 15, 2017, including interim periods and requires retrospective adoption with early adoption permitted. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.
Intangibles – Goodwill and Other — In January 2017, the FASB issued Accounting Standards Update 2017-04, “Simplifying the Test for Goodwill Impairment.” The standard eliminates the second step in the goodwill impairment test which requires an entity to determine the implied fair value of the reporting unit’s goodwill. Instead, an entity should recognize an impairment loss if the carrying value of the net assets assigned to the reporting unit exceeds the fair value of the reporting unit, with the impairment loss not to exceed the amount of goodwill allocated to the reporting unit. The standard is effective for annual and interim goodwill impairment tests conducted in fiscal years beginning after December 15, 2019, with early adoption permitted. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.
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 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. The standard is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We are currently assessing the future effect this standard may have on our financial condition, results of operations or cash flows.
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2. | Acquisitions and Divestitures

Acquisition of North American Power
On January 17, 2017, we, through an indirect, wholly-owned subsidiary, completed the purchase of 100% of the outstanding limited liability company membership interests in North American Power for approximately $105 million, excluding working capital and other adjustments. North American Power is a growing retail energy supplier for homes and small businesses and is primarily concentrated in the Northeast U.S. where Calpine has a substantial power generation presence and where Champion Energy has a substantial retail sales footprint that is enhanced by the addition of North American Power, which has been integrated into our Champion Energy retail platform. We funded the acquisition with cash on hand and the purchase price is allocated to the net assets of the business including intangible assets for the value of customer relationships and goodwill. The goodwill recorded associated with our acquisition of North American Power is deductible for tax purposes. We did not record any material adjustments to the preliminary purchase price allocation during the nine months ended September 30, 2017. The pro forma incremental effect of North American Power on our results of operations for each of the three and nine months ended September 30, 2017 and 2016 is not material.
Acquisition of Calpine Solutions, formerly Noble Solutions
We did not record any material adjustments to the preliminary purchase price allocation during the nine months ended September 30, 2017 associated with our acquisition of Calpine Solutions on December 1, 2016.
Acquisition of Granite Ridge Energy Center
On February 5, 2016, we, through our indirect, wholly-owned subsidiary Calpine Granite Holdings, LLC, completed the purchase of Granite Ridge Energy Center, a power plant with a nameplate capacity of 745 MW (summer peaking capacity of 695 MW), from Granite Ridge Holdings, LLC, for approximately $500 million, excluding working capital and other adjustments. The purchase price allocation was finalized during the first quarter of 2017 and did not result in any material adjustments or the recognition of goodwill.
Sale of Osprey Energy Center
On January 3, 2017, we completed the sale of the Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments. This transaction supports our effort to divest non-core assets outside our strategic concentration. We recorded a gain on sale of assets, net of approximately $27 million during the nine months ended September 30, 2017 associated with the sale of the Osprey Energy Center.
South Point Energy Center
As a result of the denial by the Nevada Public Utility Commission of the sale of South Point Energy Center to Nevada Power Company in February 2017, we terminated the corresponding asset sale agreement in the first quarter of 2017. We are currently assessing our options related to South Point Energy Center; however, we do not anticipate that the termination of the asset sale agreement will have a material effect on our financial condition, results of operations or cash flows. During the first quarter of 2017, we reclassified the assets of South Point Energy Center from current assets held for sale to held and used.

3. | 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 nine months ended September 30, 2017. See Note 5 in our 2016 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 8,423 MW and 9,491 MW at September 30, 2017 and December 31, 2016, 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 nine months ended September 30, 2017 and $1 million during each of the three and nine months ended September 30, 2016.
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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.
In December 2016, we acquired Calpine Receivables, a bankruptcy remote entity created for the special purpose of purchasing trade accounts receivable from Calpine Solutions under the Accounts Receivable Sales Program. Calpine Receivables is a VIE. 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 September 30, 2017 and December 31, 2016, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):

| Ownership Interest as of September 30, 2017 |  | September 30, 2017 |  | December 31, 2016
Greenfield LP | 50% |  | $ | 92 |  |  | $ | 73 |
Whitby | 50% |  | 4 |  |  | 16 |
Calpine Receivables | 100% |  | 10 |  |  | 10 |
Total investments in unconsolidated subsidiaries |  |  | $ | 106 |  |  | $ | 99 |

Our risk of loss related to our investments in Greenfield LP, Whitby and Calpine Receivables is limited to our investment balance. 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 September 30, 2017 and December 31, 2016, Greenfield LP’s debt was approximately $263 million and $259 million, respectively, and based on our pro rata share of our investment in Greenfield LP, our share of such debt would be approximately $132 million and $130 million at September 30, 2017 and December 31, 2016, respectively.
Our equity interest in the net income from our investments in unconsolidated subsidiaries for the three and nine months ended September 30, 2017 and 2016, is recorded in (income) from unconsolidated subsidiaries. We did not have any income or receive any distributions from our investment in Calpine Receivables for the three and nine months ended September 30, 2017. The following table sets forth details of our (income) from unconsolidated subsidiaries for the periods indicated (in millions):

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2017 |  | 2016 |  | 2017 |  | 2016
Greenfield LP | $ | (5 | ) |  | $ | (3 | ) |  | $ | (11 | ) |  | $ | (8 | )
Whitby | (2 | ) |  | (3 | ) |  | (6 | ) |  | (8 | )
Total | $ | (7 | ) |  | $ | (6 | ) |  | $ | (17 | ) |  | $ | (16 | )

Distributions from Greenfield LP were $4 million during each of the three and nine months ended September 30, 2017, and $1 million and $6 million during the three and nine months ended September 30, 2016, respectively. Distributions from Whitby were $2 million and $18 million during the three and nine months ended September 30, 2017, respectively, and nil and $13 million during the three and nine months ended September 30, 2016, respectively.
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4. | Debt

Our debt at September 30, 2017 and December 31, 2016, was as follows (in millions):

| September 30, 2017 |  | December 31, 2016
Senior Unsecured Notes | $ | 3,415 |  |  | $ | 3,412 |
First Lien Term Loans | 3,152 |  |  | 3,165 |
First Lien Notes | 1,843 |  |  | 2,290 |
Project financing, notes payable and other | 1,575 |  |  | 1,597 |
CCFC Term Loans | 1,544 |  |  | 1,553 |
Capital lease obligations | 121 |  |  | 162 |
Subtotal | 11,650 |  |  | 12,179 |
Less: Current maturities | 369 |  |  | 748 |
Total long-term debt | $ | 11,281 |  |  | $ | 11,431 |

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, decreased to 5.4% for the nine months ended September 30, 2017, from 5.5% for the same period in 2016. The issuance of our 2019 First Lien Term Loan in February 2017 and a portion of our 2023 First Lien Term Loans in May 2016 allowed us to reduce our overall cost of debt by replacing a portion of our First Lien Notes and First Lien Term Loans with debt carrying lower interest rates.
Senior Unsecured Notes
The amounts outstanding under our Senior Unsecured Notes are summarized in the table below (in millions):

| September 30, 2017 |  | December 31, 2016
2023 Senior Unsecured Notes | $ | 1,238 |  |  | $ | 1,237 |
2024 Senior Unsecured Notes | 643 |  |  | 643 |
2025 Senior Unsecured Notes | 1,534 |  |  | 1,532 |
Total Senior Unsecured Notes | $ | 3,415 |  |  | $ | 3,412 |

First Lien Term Loans
The amounts outstanding under our senior secured First Lien Term Loans are summarized in the table below (in millions):

| September 30, 2017 |  | December 31, 2016
2017 First Lien Term Loan(1) | $ | 149 |  |  | $ | 537 |
2019 First Lien Term Loan | 389 |  |  | — |
2023 First Lien Term Loans | 1,067 |  |  | 1,071 |
2024 First Lien Term Loan | 1,547 |  |  | 1,557 |
Total First Lien Term Loans | $ | 3,152 |  |  | $ | 3,165 |

____________

(1) | For the nine months ended September 30, 2017, we used cash on hand to repay $400 million of our outstanding 2017 First Lien Term Loan. We recorded approximately $1 million and $4 million in debt extinguishment costs for the three and nine months ended September 30, 2017, related to the partial repayment of our 2017 First Lien Term Loan.

On February 3, 2017, we entered into a $400 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 0.5% 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 2019 First Lien Term Loan credit agreement), plus an applicable margin of 0.75%, or (ii) LIBOR plus 1.75% per annum (with no LIBOR floor) and matures on December 31, 2019. An aggregate amount equal to 0.25% of the aggregate principal amount of the 2019 First Lien Term Loans is payable at the end of each quarter (beginning with the quarter ending June 2017) 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 2019 First Lien Term Loan, which is structured as original issue discount and recorded approximately $8 million in debt issuance costs during the
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first quarter of 2017 related to the issuance of our 2019 First Lien Term Loan. The 2019 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 the 2019 First Lien Term Loan, together with cash on hand, to redeem the remaining 2023 First Lien Notes.
First Lien Notes
The amounts outstanding under our senior secured First Lien Notes are summarized in the table below (in millions):

| September 30, 2017 |  | December 31, 2016
2022 First Lien Notes | $ | 741 |  |  | $ | 739 |
2023 First Lien Notes(1) | — |  |  | 450 |
2024 First Lien Notes | 485 |  |  | 485 |
2026 First Lien Notes | 617 |  |  | 616 |
Total First Lien Notes | $ | 1,843 |  |  | $ | 2,290 |

____________

(1) | On March 6, 2017, we used cash on hand along with the proceeds from our 2019 First Lien Term Loan to redeem the remaining $453 million of our 2023 First Lien Notes, plus accrued and unpaid interest. During the first quarter of 2017, we recorded approximately $21 million in debt extinguishment costs related to the redemption of our 2023 First Lien Notes.

Corporate Revolving Facility and Other Letter of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at September 30, 2017 and December 31, 2016 (in millions):

| September 30, 2017 |  | December 31, 2016
Corporate Revolving Facility(1) | $ | 474 |  |  | $ | 535 |
CDHI | 246 |  |  | 250 |
Various project financing facilities | 230 |  |  | 206 |
Total | $ | 950 |  |  | $ | 991 |

____________

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

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 September 30, 2017 and December 31, 2016 (in millions):

| September 30, 2017 |  | December 31, 2016
| Fair Value |  | Carrying Value |  | Fair Value |  | Carrying Value
Senior Unsecured Notes | $ | 3,307 |  |  | $ | 3,415 |  |  | $ | 3,343 |  |  | $ | 3,412 |
First Lien Term Loans | 3,202 |  |  | 3,152 |  |  | 3,244 |  |  | 3,165 |
First Lien Notes | 1,905 |  |  | 1,843 |  |  | 2,349 |  |  | 2,290 |
Project financing, notes payable and other(1) | 1,516 |  |  | 1,484 |  |  | 1,543 |  |  | 1,506 |
CCFC Term Loans | 1,554 |  |  | 1,544 |  |  | 1,567 |  |  | 1,553 |
Total | $ | 11,484 |  |  | $ | 11,438 |  |  | $ | 12,046 |  |  | $ | 11,926 |

____________

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

We measure the fair value of our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes and CCFC Term Loans using market information, including quoted market prices or dealer quotes for the identical liability when traded as an asset (categorized as level 2). We measure the fair value of our project financing, notes payable and other debt instruments using
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discounted cash flow analyses based on our current borrowing rates for similar types of borrowing arrangements (categorized as level 3). We do not have any debt instruments with fair value measurements categorized as level 1 within the fair value hierarchy.

5. | 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 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 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. OTC options are valued using industry-standard models, including the Black-Scholes option-pricing model. At each balance sheet date, we perform an analysis of all instruments subject to fair value measurement and include in level 3 all of those whose fair value is based on significant unobservable inputs.
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Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. 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 September 30, 2017 and December 31, 2016, by level within the fair value hierarchy:

| Assets and Liabilities with Recurring Fair Value Measures as of September 30, 2017
| Level 1 |  | Level 2 |  | Level 3 |  | Total
| (in millions)
Assets: |  |  |  |  |  |  |
Cash equivalents(1) | $ | 173 |  |  | $ | — |  |  | $ | — |  |  | $ | 173 |
Commodity instruments: |  |  |  |  |  |  |
Commodity exchange traded futures and swaps contracts | 605 |  |  | — |  |  | — |  |  | 605 |
Commodity forward contracts(2) | — |  |  | 362 |  |  | 332 |  |  | 694 |
Interest rate hedging instruments | — |  |  | 20 |  |  | — |  |  | 20 |
Effect of netting and allocation of collateral(3)(4) | (605 | ) |  | (203 | ) |  | (21 | ) |  | (829 | )
Total assets | $ | 173 |  |  | $ | 179 |  |  | $ | 311 |  |  | $ | 663 |
Liabilities: |  |  |  |  |  |  |
Commodity instruments: |  |  |  |  |  |  |
Commodity exchange traded futures and swaps contracts | 656 |  |  | — |  |  | — |  |  | 656 |
Commodity forward contracts(2) | — |  |  | 355 |  |  | 64 |  |  | 419 |
Interest rate hedging instruments | — |  |  | 52 |  |  | — |  |  | 52 |
Effect of netting and allocation of collateral(3)(4) | (656 | ) |  | (220 | ) |  | (35 | ) |  | (911 | )
Total liabilities | $ | — |  |  | $ | 187 |  |  | $ | 29 |  |  | $ | 216 |

| Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2016
| Level 1 |  | Level 2 |  | Level 3 |  | Total
| (in millions)
Assets: |  |  |  |  |  |  |
Cash equivalents(1) | $ | 153 |  |  | $ | — |  |  | $ | — |  |  | $ | 153 |
Commodity instruments: |  |  |  |  |  |  |
Commodity exchange traded futures and swaps contracts | 1,542 |  |  | — |  |  | — |  |  | 1,542 |
Commodity forward contracts(2) | — |  |  | 231 |  |  | 466 |  |  | 697 |
Interest rate hedging instruments | — |  |  | 29 |  |  | — |  |  | 29 |
Effect of netting and allocation of collateral(3)(4) | (1,542 | ) |  | (188 | ) |  | (17 | ) |  | (1,747 | )
Total assets | $ | 153 |  |  | $ | 72 |  |  | $ | 449 |  |  | $ | 674 |
Liabilities: |  |  |  |  |  |  |
Commodity instruments: |  |  |  |  |  |  |
Commodity exchange traded futures and swaps contracts | 1,570 |  |  | — |  |  | — |  |  | 1,570 |
Commodity forward contracts(2) | — |  |  | 411 |  |  | 67 |  |  | 478 |
Interest rate hedging instruments | — |  |  | 58 |  |  | — |  |  | 58 |
Effect of netting and allocation of collateral(3)(4) | (1,570 | ) |  | (215 | ) |  | (34 | ) |  | (1,819 | )
Total liabilities | $ | — |  |  | $ | 254 |  |  | $ | 33 |  |  | $ | 287 |

___________

(1) | At September 30, 2017 and December 31, 2016, we had cash equivalents of $32 million and $26 million included in cash and cash equivalents and $141 million and $127 million included in restricted cash, respectively.

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(2) | Includes OTC swaps and options and retail contracts.

(3) | During the third quarter of 2017, we elected to 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 1 for a further description of the change in accounting principle associated with our election to offset fair value amounts associated with our derivative instruments. See Note 6 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 $51 million, $17 million and $14 million, respectively, at September 30, 2017. Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $28 million, $27 million and $17 million, respectively, at December 31, 2016.

At September 30, 2017 and December 31, 2016, 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 September 30, 2017 and December 31, 2016:

|  | Quantitative Information about Level 3 Fair Value Measurements |
|  | September 30, 2017 |
|  | Fair Value, Net Asset |  |  |  | Significant Unobservable |  |  |  |  |
|  | (Liability) |  | Valuation Technique |  | Input |  | Range
|  | (in millions) |  |  |  |  |  |  |  |  |
Power Contracts |  | $ | 234 |  |  | Discounted cash flow |  | Market price (per MWh) |  | $ | 6.55 |  | — | $89.83 | /MWh
Power Congestion Products |  | $ | 10 |  |  | Discounted cash flow |  | Market price (per MWh) |  | $ | (13.13 | ) | — | $6.85 | /MWh
Natural Gas Contracts |  | $ | 38 |  |  | Discounted cash flow |  | Market price (per MMBtu) |  | $ | 0.97 |  | — | $9.35 | /MMBtu
|  | December 31, 2016 |
|  | Fair Value, Net Asset |  |  |  | Significant Unobservable |  |  |  |  |
|  | (Liability) |  | Valuation Technique |  | Input |  | Range
|  | (in millions) |  |  |  |  |  |  |  |  |
Power Contracts |  | $ | 376 |  |  | Discounted cash flow |  | Market price (per MWh) |  | $ | 9.60 |  | — | $86.34 | /MWh
Power Congestion Products |  | $ | 12 |  |  | Discounted cash flow |  | Market price (per MWh) |  | $ | (7.52 | ) | — | $13.62 | /MWh
Natural Gas Contracts |  | $ | 18 |  |  | Discounted cash flow |  | Market price (per MMBtu) |  | $ | 1.95 |  | — | $5.66 | /MMBtu

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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 September 30, |  | Nine Months Ended September 30,
|  | 2017 |  | 2016 |  | 2017 |  | 2016
Balance, beginning of period |  | $ | 303 |  |  | $ | (61 | ) |  | $ | 416 |  |  | $ | (46 | )
Realized and mark-to-market gains (losses): |  |  |  |  |  |  |  |
Included in net loss: |  |  |  |  |  |  |  |
Included in operating revenues(1) |  | 26 |  |  | 30 |  |  | 125 |  |  | 9 |
Included in fuel and purchased energy expense(2) |  | (12 | ) |  | (31 | ) |  | (1 | ) |  | (24 | )
Change in collateral |  | 4 |  |  | (2 | ) |  | (4 | ) |  | — |
Purchases and settlements: |  |  |  |  |  |  |  |
Purchases |  | 1 |  |  | 1 |  |  | 2 |  |  | 4 |
Settlements |  | (40 | ) |  | 15 |  |  | (129 | ) |  | (4 | )
Transfers in and/or out of level 3(3): |  |  |  |  |  |  |  |
Transfers into level 3(4) |  | 3 |  |  | 1 |  |  | (5 | ) |  | — |
Transfers out of level 3(5) |  | (3 | ) |  | 75 |  |  | (122 | ) |  | 89 |
Balance, end of period |  | $ | 282 |  |  | $ | 28 |  |  | $ | 282 |  |  | $ | 28 |
Change in unrealized gains (losses) relating to instruments still held at end of period |  | $ | 14 |  |  | $ | (1 | ) |  | $ | 124 |  |  | $ | (15 | )

___________

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

(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 nine months ended September 30, 2017 and 2016.

(4) | There were $3 million and $1 million in gains transferred out of level 2 into level 3 for the three months ended September 30, 2017 and 2016, and $(5) million and nil in losses transferred out of level 2 into level 3 for the nine months ended September 30, 2017 and 2016, respectively, due to changes in market liquidity in various power markets.

(5) | We had $3 million in gains and $(75) million in losses transferred out of level 3 into level 2 for the three months ended September 30, 2017 and 2016, respectively, and $122 million in gains and $(89) million in losses transferred out of level 3 into level 2 for the nine months ended September 30, 2017 and 2016, respectively, due to changes in market liquidity in various power markets.

6. | 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 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 nine months ended September 30, 2017 and 2016.
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
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potential adverse changes in interest rates. As of September 30, 2017, the maximum length of time over which we were hedging using interest rate hedging instruments designated as cash flow hedges was 8 years.
As of September 30, 2017 and December 31, 2016, 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 (in millions):

Derivative Instruments |  | Notional Amounts
| September 30, 2017 |  | December 31, 2016
Power (MWh) |  | (98 | ) |  | (86 | )
Natural gas (MMBtu) |  | 398 |  |  | 613 |
Environmental credits (Tonnes) |  | 19 |  |  | 16 |
Interest rate hedging instruments |  | $ | 4,600 |  | (1) | $ | 3,721 |

___________

(1) | We entered into interest rate hedging instruments during the first quarter of 2017 to hedge approximately $1.0 billion of variable rate debt for 2018 through 2020 and approximately $500 million of variable rate debt for 2021 through 2022. We also extended the tenor of certain interest rate hedging instruments, which effectively places a ceiling on LIBOR on $2.5 billion of variable rate corporate debt through 2020 and $1.25 billion of variable rate corporate debt in 2021.

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 September 30, 2017, was $17 million for which we have posted collateral of $1 million by posting margin deposits 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 $1 million related to our derivative liabilities would be required and that no counterparty could request immediate, full settlement.
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 only apply hedge accounting to our interest rate hedging instruments. We report the effective portion of 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. Gains and losses due to ineffectiveness on interest rate hedging instruments are recognized currently in earnings as a component of interest expense. 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 are 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
19

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
During the third quarter of 2017, we elected to begin offsetting 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 cash collateral in support of our derivative instruments which may also be subject to a master netting arrangement with the same counterparty. See Note 1 for a further description of the change in accounting principle associated with our election to offset fair value amounts associated with our derivative instruments.
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 September 30, 2017 and December 31, 2016 (in millions):

|  | September 30, 2017
|  | Gross Amounts of Assets and (Liabilities) |  | Gross Amounts Offset on the Consolidated Condensed Balance Sheets |  | Net Amount Presented on the Consolidated Condensed Balance Sheet(1)
Derivative assets: |  |  |  |  |  |
Commodity exchange traded futures and swaps contracts |  | $ | 472 |  |  | $ | (472 | ) |  | $ | — |
Commodity forward contracts |  | 338 |  |  | (133 | ) |  | 205 |
Interest rate hedging instruments |  | 2 |  |  | (1 | ) |  | 1 |
Total current derivative assets(2) |  | $ | 812 |  |  | $ | (606 | ) |  | $ | 206 |
Commodity exchange traded futures and swaps contracts |  | 133 |  |  | (133 | ) |  | — |
Commodity forward contracts |  | 356 |  |  | (82 | ) |  | 274 |
Interest rate hedging instruments |  | 18 |  |  | (8 | ) |  | 10 |
Total long-term derivative assets(2) |  | $ | 507 |  |  | $ | (223 | ) |  | $ | 284 |
Total derivative assets |  | $ | 1,319 |  |  | $ | (829 | ) |  | $ | 490 |
Derivative (liabilities): |  |  |  |  |  |
Commodity exchange traded futures and swaps contracts |  | $ | (496 | ) |  | $ | 496 |  |  | $ | — |
Commodity forward contracts |  | (236 | ) |  | 148 |  |  | (88 | )
Interest rate hedging instruments |  | (26 | ) |  | 1 |  |  | (25 | )
Total current derivative (liabilities)(2) |  | $ | (758 | ) |  | $ | 645 |  |  | $ | (113 | )
Commodity exchange traded futures and swaps contracts |  | (160 | ) |  | 160 |  |  | — |
Commodity forward contracts |  | (183 | ) |  | 98 |  |  | (85 | )
Interest rate hedging instruments |  | (26 | ) |  | 8 |  |  | (18 | )
Total long-term derivative (liabilities)(2) |  | $ | (369 | ) |  | $ | 266 |  |  | $ | (103 | )
Total derivative liabilities |  | $ | (1,127 | ) |  | $ | 911 |  |  | $ | (216 | )
Net derivative assets (liabilities) |  | $ | 192 |  |  | $ | 82 |  |  | $ | 274 |

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|  | December 31, 2016
|  | Gross Amounts of Assets and (Liabilities) |  | Gross Amounts Offset on the Consolidated Condensed Balance Sheets |  | Net Amount Presented on the Consolidated Condensed Balance Sheet(1)
Derivative assets: |  |  |  |  |  |
Commodity exchange traded futures and swaps contracts |  | $ | 1,344 |  |  | $ | (1,344 | ) |  | $ | — |
Commodity forward contracts |  | 380 |  |  | (160 | ) |  | 220 |
Interest rate hedging instruments |  | 1 |  |  | — |  |  | 1 |
Total current derivative assets(3) |  | $ | 1,725 |  |  | $ | (1,504 | ) |  | $ | 221 |
Commodity exchange traded futures and swaps contracts |  | 198 |  |  | (198 | ) |  | — |
Commodity forward contracts |  | 317 |  |  | (45 | ) |  | 272 |
Interest rate hedging instruments |  | 28 |  |  | — |  |  | 28 |
Total long-term derivative assets(3) |  | $ | 543 |  |  | $ | (243 | ) |  | $ | 300 |
Total derivative assets |  | $ | 2,268 |  |  | $ | (1,747 | ) |  | $ | 521 |
Derivative (liabilities): |  |  |  |  |  |
Commodity exchange traded futures and swaps contracts |  | $ | (1,327 | ) |  | $ | 1,327 |  |  | $ | — |
Commodity forward contracts |  | (275 | ) |  | 165 |  |  | (110 | )
Interest rate hedging instruments |  | (28 | ) |  | — |  |  | (28 | )
Total current derivative (liabilities)(3) |  | $ | (1,630 | ) |  | $ | 1,492 |  |  | $ | (138 | )
Commodity exchange traded futures and swaps contracts |  | (243 | ) |  | 243 |  |  | — |
Commodity forward contracts |  | (203 | ) |  | 84 |  |  | (119 | )
Interest rate hedging instruments |  | (30 | ) |  | — |  |  | (30 | )
Total long-term derivative (liabilities)(3) |  | $ | (476 | ) |  | $ | 327 |  |  | $ | (149 | )
Total derivative liabilities |  | $ | (2,106 | ) |  | $ | 1,819 |  |  | $ | (287 | )
Net derivative assets (liabilities) |  | $ | 162 |  |  | $ | 72 |  |  | $ | 234 |

____________

(1) | At September 30, 2017 and December 31, 2016, we had $115 million and $262 million of collateral under master netting arrangements that were not offset against our derivative instruments on the Consolidated Condensed Balance Sheets.

(2) | At September 30, 2017, current and long-term derivative assets are shown net of collateral of $(4) million and $(8) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $43 million and $51 million, respectively.

(3) | At December 31, 2016, current and long-term derivative assets are shown net of collateral of $(29) million and $(3) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $19 million and $85 million, respectively.

| September 30, 2017 |  | December 31, 2016
| 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 | $ | 11 |  |  | $ | 43 |  |  | $ | 29 |  |  | $ | 58 |
Total derivatives designated as cash flow hedging instruments | $ | 11 |  |  | $ | 43 |  |  | $ | 29 |  |  | $ | 58 |
Derivatives not designated as hedging instruments: |  |  |  |  |  |  |
Commodity instruments | $ | 479 |  |  | $ | 173 |  |  | $ | 492 |  |  | $ | 229 |
Total derivatives not designated as hedging instruments | $ | 479 |  |  | $ | 173 |  |  | $ | 492 |  |  | $ | 229 |
Total derivatives | $ | 490 |  |  | $ | 216 |  |  | $ | 521 |  |  | $ | 287 |

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Derivatives Included on Our Consolidated Condensed Statements of Operations
Changes in the fair values of our derivative instruments (both assets and liabilities) are reflected either in cash for option premiums paid or collected, in OCI, net of tax, for the effective portion of 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 September 30, |  | Nine Months Ended September 30,
| 2017 |  | 2016 |  | 2017 |  | 2016
Realized gain (loss)(1)(2) |  |  |  |  |  |  |
Commodity derivative instruments | $ | (53 | ) |  | $ | 32 |  |  | $ | 20 |  |  | $ | 213 |
Total realized gain (loss) | $ | (53 | ) |  | $ | 32 |  |  | $ | 20 |  |  | $ | 213 |
Mark-to-market gain (loss)(3) |  |  |  |  |  |  |
Commodity derivative instruments | $ | 66 |  |  | $ | 109 |  |  | $ | 39 |  |  | $ | (22 | )
Interest rate hedging instruments | — |  |  | — |  |  | 1 |  |  | 1 |
Total mark-to-market gain (loss) | $ | 66 |  |  | $ | 109 |  |  | $ | 40 |  |  | $ | (21 | )
Total activity, net | $ | 13 |  |  | $ | 141 |  |  | $ | 60 |  |  | $ | 192 |

___________

(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, Calpine Solutions and North American Power.

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

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2017 |  | 2016 |  | 2017 |  | 2016
Realized and mark-to-market gain (loss)(1) |  |  |  |  |  |  |
Derivatives contracts included in operating revenues(2)(3) | $ | 60 |  |  | $ | 308 |  |  | $ | 252 |  |  | $ | 240 |
Derivatives contracts included in fuel and purchased energy expense(2)(3) | (47 | ) |  | (167 | ) |  | (193 | ) |  | (49 | )
Interest rate hedging instruments included in interest expense(4) | — |  |  | — |  |  | 1 |  |  | 1 |
Total activity, net | $ | 13 |  |  | $ | 141 |  |  | $ | 60 |  |  | $ | 192 |

___________

(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, Calpine Solutions and North American Power.

(4) | In addition to changes in market value on interest rate hedging instruments not designated as hedges, changes in mark-to-market gain (loss) also includes hedge ineffectiveness.

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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 September 30, |  | Three Months Ended September 30,
| Gain (Loss) Recognized in OCI (Effective Portion) |  | Gain (Loss) Reclassified from AOCI into Income (Effective Portion)(3)
| 2017 |  | 2016 |  | 2017 |  | 2016 |  | Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate hedging instruments(1)(2) | $ | 7 |  |  | $ | 18 |  |  | $ | (10 | ) |  | $ | (11 | ) |  | Interest expense
Interest rate hedging instruments(1)(2) | 1 |  |  | — |  |  | (1 | ) |  | — |  |  | Depreciation expense
Total | $ | 8 |  |  | $ | 18 |  |  | $ | (11 | ) |  | $ | (11 | ) |  |

| Nine Months Ended September 30, |  | Nine Months Ended September 30,
| Gain (Loss) Recognized in OCI (Effective Portion) |  | Gain (Loss) Reclassified from AOCI into Income (Effective Portion)(3)
| 2017 |  | 2016 |  | 2017 |  | 2016 |  | Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate hedging instruments(1)(2) | $ | (12 | ) |  | $ | — |  |  | $ | (32 | ) |  | $ | (33 | ) |  | Interest expense
Interest rate hedging instruments(1)(2) | 5 |  |  | — |  |  | (5 | ) |  | — |  |  | Depreciation expense
Total | $ | (7 | ) |  | $ | — |  |  | $ | (37 | ) |  | $ | (33 | ) |  |

____________

(1) | We did not record any material gain (loss) on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during the three and nine months ended September 30, 2017 and 2016.

(2) | We recorded an income tax expense of $1 million and $3 million for each of the three and nine months ended September 30, 2017 and nil for each of the three and nine months ended September 30, 2016, 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 $101 million and $90 million at September 30, 2017 and December 31, 2016, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $7 million and $8 million at September 30, 2017 and December 31, 2016, respectively.

We estimate that pre-tax net losses of $35 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.

7. | 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 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.
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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 September 30, 2017 and December 31, 2016 (in millions):

| September 30, 2017 |  | December 31, 2016
Margin deposits(1) | $ | 216 |  |  | $ | 350 |
Natural gas and power prepayments | 27 |  |  | 25 |
Total margin deposits and natural gas and power prepayments with our counterparties(2) | $ | 243 |  |  | $ | 375 |
Letters of credit issued | $ | 731 |  |  | $ | 798 |
First priority liens under power and natural gas agreements | 193 |  |  | 206 |
First priority liens under interest rate hedging instruments | 41 |  |  | 55 |
Total letters of credit and first priority liens with our counterparties | $ | 965 |  |  | $ | 1,059 |
Margin deposits posted with us by our counterparties(1)(3) | $ | 19 |  |  | $ | 16 |
Letters of credit posted with us by our counterparties | 33 |  |  | 43 |
Total margin deposits and letters of credit posted with us by our counterparties | $ | 52 |  |  | $ | 59 |

___________

(1) | During the third quarter of 2017, we elected to 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 1 for a further description of the change in accounting principle associated with our election to offset fair value amounts associated with our derivative instruments. See Note 6 for further discussion of our derivative instruments subject to master netting arrangements.

(2) | At September 30, 2017 and December 31, 2016, $85 million and $78 million, respectively, were included in current and long-term derivative assets and liabilities, $149 million and $288 million, respectively, were included in margin deposits and other prepaid expense and $9 million and $9 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.

(3) | At September 30, 2017 and December 31, 2016, $3 million and $6 million, respectively, were included in current and long-term derivative assets and liabilities and $16 million and $10 million, respectively, were included in other current 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.

8. | 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 September 30, |  | Nine Months Ended September 30,
| 2017 |  | 2016 |  | 2017 |  | 2016
Income tax expense (benefit) | $ | (2 | ) |  | $ | (4 | ) |  | $ | — |  |  | $ | 17 |
Effective tax rate | (1 | )% |  | (1 | )% |  | — | % |  | 20 | %

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 nine months ended September 30, 2017 and 2016, our income tax expense (benefit) is largely comprised of discrete tax items and estimated state and foreign income
24

taxes in jurisdictions where we do not have NOLs or valuation allowances. During the nine months ended September 30, 2017, we recorded an income tax benefit of $17 million associated with a favorable adjustment to our reserve for uncertain tax positions.
NOL Carryforwards — As of December 31, 2016, our NOL carryforwards consist primarily of federal NOL carryforwards of approximately $6.7 billion, which expire between 2024 and 2033, and NOL carryforwards in 21 states and the District of Columbia totaling approximately $3.7 billion, which expire between 2017 and 2036, substantially all of which are offset with a full valuation allowance. Certain of the state NOL carryforwards may be subject to limitations on their annual usage. Under federal and state income tax law, our NOL carryforwards can be utilized to reduce future taxable income subject to certain new limitations including if we were to undergo an ownership change as defined by Section 382 of the Internal Revenue Code and similar state provisions.
We also have approximately $647 million in foreign NOLs, which expire between 2025 and 2033, and the associated deferred tax asset of approximately $161 million is partially offset by a valuation allowance of $101 million. Under Canadian income tax law, our NOL carryforwards can be utilized to reduce future taxable income subject to certain limitations including new applicable limitations resulting from an ownership change which will result in an increase in the valuation allowance and a related charge to deferred tax expense.
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 U.S. federal income tax examination for the year ended December 31, 2015 and 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.
Unrecognized Tax Benefits — At September 30, 2017, we had unrecognized tax benefits of $48 million. If recognized, $10 million of our unrecognized tax benefits could affect the annual effective tax rate and $38 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 $4 million for income tax matters at September 30, 2017. 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 $7 million in unrecognized tax benefits could occur within the next twelve months primarily related to foreign tax issues.

9. | Earnings (Loss) per Share

We include restricted stock units for which no future service is required as a condition to the delivery of the underlying common stock in our calculation of weighted average shares outstanding. As we incurred a net loss for the nine months ended September 30, 2017, diluted loss per share for this period is computed on the same basis as basic loss per share, as the inclusion of any other potential shares outstanding would be anti-dilutive. Reconciliation of the amounts used in the basic and diluted earnings (loss) per common share computations for the three and nine months ended September 30, 2017 and 2016, are as follows (shares in thousands):

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2017 |  | 2016 |  | 2017 |  | 2016
Diluted weighted average shares calculation: |  |  |  |  |  |  |
Weighted average shares outstanding (basic) | 355,442 |  |  | 354,215 |  |  | 355,164 |  |  | 353,929 |
Share-based awards | 3,402 |  |  | 2,137 |  |  | — |  |  | 2,051 |
Weighted average shares outstanding (diluted) | 358,844 |  |  | 356,352 |  |  | 355,164 |  |  | 355,980 |

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We excluded the following items from diluted earnings per common share for the three and nine months ended September 30, 2017 and 2016, because they were anti-dilutive (shares in thousands):

| Three Months Ended September 30, |  | Nine Months Ended September 30,
| 2017 |  | 2016 |  | 2017 |  | 2016
Share-based awards | 2,789 |  |  | 1,610 |  |  | 5,391 |  |  | 1,679 |

10. | Stock-Based Compensation

Calpine Equity Incentive Plans
The Calpine Equity Incentive Plans provide for the issuance of equity awards to all non-union employees as well as the non-employee members of our Board of Directors. The equity awards may include incentive or non-qualified stock options, restricted stock, restricted stock units, stock appreciation rights, performance compensation awards and other share-based awards. The equity awards granted under the Calpine Equity Incentive Plans include both graded and cliff vesting awards which vest over periods between one and five years, contain contractual terms between approximately five and ten years and are subject to forfeiture provisions under certain circumstances, including termination of employment prior to vesting. At September 30, 2017, 300,000 shares and 21,865,106 shares remain available for issuance under the 2017 Director Plan and the 2017 Equity Plan, respectively. There are no shares available for issuance under the 2008 Director Plan and the 2008 Equity Plan.
Equity Classified Share-Based Awards
Stock-based compensation expense recognized for our equity classified share-based awards was $9 million and $7 million for the three months ended September 30, 2017 and 2016, respectively, and $26 million and $22 million for the nine months ended September 30, 2017 and 2016, respectively. We did not record any significant tax benefits related to stock-based compensation expense in any period as we are not benefiting from a significant portion of our deferred tax assets, including deductions related to stock-based compensation expense. In addition, we did not capitalize any stock-based compensation expense as part of the cost of an asset for the nine months ended September 30, 2017 and 2016. At September 30, 2017, there was unrecognized compensation cost of $28 million related to restricted stock, $7 million related to restricted stock units and $5 million related to options which is expected to be recognized over a weighted average period of 1.5 years for restricted stock, 1.2 years for restricted stock units and 2.1 years for options. We issue new shares from our share reserves set aside for the Calpine Equity Incentive Plans when stock options are exercised and for other share-based awards.
A summary of all of our non-qualified stock option activity for the Equity Plans for the nine months ended September 30, 2017, is as follows:

| Number of Shares |  | Weighted Average Exercise Price |  | Weighted Average Remaining Term (in years) |  | Aggregate Intrinsic Value (in millions)
Outstanding — December 31, 2016 | 2,697,136 |  |  | $ | 13.59 |  |  | 3.0 |  | $ | 2 |
Granted | 1,476,480 |  |  | $ | 11.70 |  |  |  |  |
Exercised | 4,000 |  |  | $ | 9.49 |  |  |  |  |
Forfeited | 15,721 |  |  | $ | 11.69 |  |  |  |  |
Expired | 32,100 |  |  | $ | 17.70 |  |  |  |  |
Outstanding — September 30, 2017 | 4,121,795 |  |  | $ | 12.89 |  |  | 4.8 |  | $ | 10 |
Exercisable — September 30, 2017 | 2,661,036 |  |  | $ | 13.54 |  |  | 2.3 |  | $ | 5 |
Vested and expected to vest – September 30, 2017 | 3,949,676 |  |  | $ | 12.94 |  |  | 4.6 |  | $ | 9 |

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The fair value of options granted during the nine months ended September 30, 2017, was determined on the grant date using the Black-Scholes option-pricing model. Certain assumptions were used in order to estimate fair value for options as noted in the following table:

| 2017 |
Expected term (in years)(1) | 7.3 - 10.0 |  |
Risk-free interest rate(2) | 2.25 |  | %
Expected volatility(3) | 33 - 40 |  | %
Dividend yield(4) | — |  |
Weighted average grant-date fair value (per option) | $ | 5.38 |  |

___________

(1) | Expected term calculated using historical exercise data.

(2) | Zero Coupon U.S. Treasury rate or equivalent based on expected term.

(3) | Volatility calculated using the implied volatility of our exchange traded stock options.

(4) | We have never paid cash dividends on our common stock and we do not anticipate any cash dividend payments on our common stock in the near future.

A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the nine months ended September 30, 2017, is as follows:

| Number of Restricted Stock Awards |  | Weighted Average Grant-Date Fair Value
Nonvested — December 31, 2016 | 4,869,648 |  |  | $ | 15.83 |
Granted | 3,606,816 |  |  | $ | 11.76 |
Forfeited | 546,585 |  |  | $ | 13.90 |
Vested | 1,674,738 |  |  | $ | 17.07 |
Nonvested — September 30, 2017 | 6,255,141 |  | (1) | $ | 13.31 |

___________

(1) | Includes 63,075 shares of restricted stock and restricted stock units outstanding under the Director Plans and 6,192,066 shares of restricted stock and restricted stock units outstanding under the Equity Plans.

The total fair value of our restricted stock and restricted stock units that vested during the nine months ended September 30, 2017 and 2016 was approximately $20 million and $16 million, respectively.
Liability Classified Share-Based Awards
During the first quarter of 2017, our Board of Directors approved the award of performance share units to certain senior management employees. These performance share units will be settled in cash with payouts based on the relative performance of Calpine’s total shareholder return over the three-year performance period of January 1, 2017 through December 31, 2019. The performance share units vest on the last day of the performance period and will be settled in cash; thus, these awards are liability classified and are measured at fair value using a Monte Carlo simulation model at each reporting date until settlement. Stock-based compensation expense recognized related to our liability classified share-based awards was $2 million and $(1) million for the three months ended September 30, 2017 and 2016, respectively, and $5 million and $1 million for the nine months ended September 30, 2017 and 2016, respectively.
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A summary of our performance share unit activity for the nine months ended September 30, 2017, is as follows:

| Number of Performance Share Units |  | Weighted Average Grant-Date Fair Value
Nonvested — December 31, 2016 | 890,587 |  |  | $ | 17.90 |
Granted | 478,984 |  |  | $ | 10.73 |
Forfeited | 54,638 |  |  | $ | 18.38 |
Vested(1) | 30,312 |  |  | $ | 17.21 |
Nonvested — September 30, 2017 | 1,284,621 |  |  | $ | 15.22 |

___________

(1) | In accordance with the applicable performance share unit agreements, performance share units granted to employees who meet the retirement eligibility requirements stipulated in the Equity Plans are fully vested upon the later of the date on which the employee becomes eligible to retire or one-year anniversary of the grant date.

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.
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 September 30, 2017, 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 15 of our 2016 Form 10-K.

12. | 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 September 30, 2017, our reportable segments were West (including geothermal), Texas and East (including Canada). The results of our retail subsidiaries are reflected in the segment which corresponds with the geographic area in which the retail sales occur. We continue to evaluate the optimal manner in which we assess our performance including our segments and future changes may
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result in changes to the composition of our geographic segments. Commodity Margin is a key operational measure reviewed by our chief operating decision maker to assess the performance of our segments. The tables below show our financial data for our segments for the periods indicated (in millions):

| Three Months Ended September 30, 2017
| West |  | Texas |  | East |  | Consolidation and Elimination |  | Total
Revenues from external customers | $ | 553 |  |  | $ | 1,127 |  |  | $ | 906 |  |  | $ | — |  |  | $ | 2,586 |
Intersegment revenues | 2 |  |  | 4 |  |  | 2 |  |  | (8 | ) |  | — |
Total operating revenues | $ | 555 |  |  | $ | 1,131 |  |  | $ | 908 |  |  | $ | (8 | ) |  | $ | 2,586 |
Commodity Margin | $ | 327 |  |  | $ | 201 |  |  | $ | 336 |  |  | $ | — |  |  | $ | 864 |
Add: Mark-to-market commodity activity, net and other(1) | (40 | ) |  | 88 |  |  | (39 | ) |  | (8 | ) |  | 1 |
Less: |  |  |  |  |  |  |  |  |
Plant operating expense | 83 |  |  | 77 |  |  | 75 |  |  | (7 | ) |  | 228 |
Depreciation and amortization expense | 63 |  |  | 61 |  |  | 55 |  |  | — |  |  | 179 |
Sales, general and other administrative expense | 10 |  |  | 16 |  |  | 10 |  |  | 1 |  |  | 37 |
Other operating expenses | 13 |  |  | 6 |  |  | 6 |  |  | (2 | ) |  | 23 |
Impairment losses | — |  |  | 12 |  |  | — |  |  | — |  |  | 12 |
(Income) from unconsolidated subsidiaries | — |  |  | — |  |  | (7 | ) |  | — |  |  | (7 | )
Income from operations | 118 |  |  | 117 |  |  | 158 |  |  | — |  |  | 393 |
Interest expense |  |  |  |  |  |  |  |  | 156 |
Debt extinguishment costs and other (income) expense, net |  |  |  |  |  |  |  |  | 8 |
Income before income taxes |  |  |  |  |  |  |  |  | $ | 229 |

| Three Months Ended September 30, 2016
| West |  | Texas |  | East |  | Consolidation and Elimination |  | Total
Revenues from external customers | $ | 524 |  |  | $ | 1,067 |  |  | $ | 764 |  |  | $ | — |  |  | $ | 2,355 |
Intersegment revenues | 1 |  |  | 3 |  |  | 2 |  |  | (6 | ) |  | — |
Total operating revenues | $ | 525 |  |  | $ | 1,070 |  |  | $ | 766 |  |  | $ | (6 | ) |  | $ | 2,355 |
Commodity Margin | $ | 298 |  |  | $ | 198 |  |  | $ | 324 |  |  | $ | — |  |  | $ | 820 |
Add: Mark-to-market commodity activity, net and other(1) | 11 |  |  | 110 |  |  | (51 | ) |  | (7 | ) |  | 63 |
Less: |  |  |  |  |  |  |  |  |
Plant operating expense | 79 |  |  | 65 |  |  | 78 |  |  | (7 | ) |  | 215 |
Depreciation and amortization expense | 56 |  |  | 53 |  |  | 52 |  |  | — |  |  | 161 |
Sales, general and other administrative expense | 9 |  |  | 13 |  |  | 12 |  |  | (1 | ) |  | 33 |
Other operating expenses | 8 |  |  | 2 |  |  | 7 |  |  | 1 |  |  | 18 |
(Income) from unconsolidated subsidiaries | — |  |  | — |  |  | (6 | ) |  | — |  |  | (6 | )
Income from operations | 157 |  |  | 175 |  |  | 130 |  |  | — |  |  | 462 |
Interest expense |  |  |  |  |  |  |  |  | 158 |
Other (income) expense, net |  |  |  |  |  |  |  |  | 7 |
Income before income taxes |  |  |  |  |  |  |  |  | $ | 297 |

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| Nine Months Ended September 30, 2017
| West |  | Texas |  | East |  | Consolidation and Elimination |  | Total
Revenues from external customers | $ | 1,666 |  |  | $ | 2,723 |  |  | $ | 2,562 |  |  | $ | — |  |  | $ | 6,951 |
Intersegment revenues | 4 |  |  | 12 |  |  | 6 |  |  | (22 | ) |  | — |
Total operating revenues | $ | 1,670 |  |  | $ | 2,735 |  |  | $ | 2,568 |  |  | $ | (22 | ) |  | $ | 6,951 |
Commodity Margin | $ | 792 |  |  | $ | 516 |  |  | $ | 761 |  |  | $ | — |  |  | $ | 2,069 |
Add: Mark-to-market commodity activity, net and other(2) | (1 | ) |  | 28 |  |  | (65 | ) |  | (22 | ) |  | (60 | )
Less: |  |  |  |  |  |  |  |  |  |
Plant operating expense | 291 |  |  | 282 |  |  | 260 |  |  | (21 | ) |  | 812 |
Depreciation and amortization expense | 189 |  |  | 187 |  |  | 166 |  |  | — |  |  | 542 |
Sales, general and other administrative expense | 31 |  |  | 54 |  |  | 31 |  |  | 1 |  |  | 117 |
Other operating expenses | 30 |  |  | 12 |  |  | 23 |  |  | (2 | ) |  | 63 |
Impairment losses | 28 |  |  | 13 |  |  | — |  |  | — |  |  | 41 |
(Gain) on sale of assets, net | — |  |  | — |  |  | (27 | ) |  | — |  |  | (27 | )
(Income) from unconsolidated subsidiaries | — |  |  | — |  |  | (17 | ) |  | — |  |  | (17 | )
Income (loss) from operations | 222 |  |  | (4 | ) |  | 260 |  |  | — |  |  | 478 |
Interest expense |  |  |  |  |  |  |  |  | 469 |
Debt extinguishment costs and other (income) expense, net |  |  |  |  |  |  |  |  | 42 |
Loss before income taxes |  |  |  |  |  |  |  |  | $ | (33 | )

| Nine Months Ended September 30, 2016
| West |  | Texas |  | East |  | Consolidation and Elimination |  | Total
Revenues from external customers | $ | 1,159 |  |  | $ | 2,129 |  |  | $ | 1,846 |  |  | $ | — |  |  | $ | 5,134 |
Intersegment revenues | 4 |  |  | 10 |  |  | 9 |  |  | (23 | ) |  | — |
Total operating revenues | $ | 1,163 |  |  | $ | 2,139 |  |  | $ | 1,855 |  |  | $ | (23 | ) |  | $ | 5,134 |
Commodity Margin | $ | 749 |  |  | $ | 511 |  |  | $ | 797 |  |  | $ | — |  |  | $ | 2,057 |
Add: Mark-to-market commodity activity, net and other(2) | (5 | ) |  | 7 |  |  | (44 | ) |  | (21 | ) |  | (63 | )
Less: |  |  |  |  |  |  |  |  |
Plant operating expense | 268 |  |  | 236 |  |  | 258 |  |  | (21 | ) |  | 741 |
Depreciation and amortization expense | 168 |  |  | 159 |  |  | 163 |  |  | — |  |  | 490 |
Sales, general and other administrative expense | 27 |  |  | 43 |  |  | 36 |  |  | — |  |  | 106 |
Other operating expenses | 23 |  |  | 6 |  |  | 27 |  |  | (1 | ) |  | 55 |
Impairment losses | 13 |  |  | — |  |  | — |  |  | — |  |  | 13 |
(Income) from unconsolidated subsidiaries | — |  |  | — |  |  | (16 | ) |  | — |  |  | (16 | )
Income from operations | 245 |  |  | 74 |  |  | 285 |  |  | 1 |  |  | 605 |
Interest expense |  |  |  |  |  |  |  |  | 472 |
Debt extinguishment costs and other (income) expense, net |  |  |  |  |  |  |  |  | 33 |
Income before income taxes |  |  |  |  |  |  |  |  | $ | 100 |

_________
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(1) | Includes $33 million and $40 million of lease levelization and $39 million and $25 million of amortization expense for the three months ended September 30, 2017 and 2016, respectively.

(2) | Includes $(13) million and $(2) million of lease levelization and $143 million and $79 million of amortization expense for the nine months ended September 30, 2017 and 2016, respectively.

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

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 one of the largest power generators in the U.S. measured by power produced. We own and operate primarily natural gas-fired and geothermal power plants in North America and have a significant presence in major competitive wholesale power markets in California (included in our West segment), Texas (included in our Texas segment) and the Northeast and Mid-Atlantic regions (included in our East segment) 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 getting closer to our customers through expansion of our retail platform which began with the acquisition of Champion Energy in 2015 and was followed by the acquisitions of Calpine Solutions in late 2016 and North American Power in early 2017. We have invested in clean power generation to become a recognized leader in developing, constructing, owning and operating an environmentally responsible portfolio of flexible and reliable power plants.
In order to manage our various physical assets and contractual obligations, we execute commodity and commodity transportation agreements within the guidelines of our Risk Management Policy. 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. Seasonality and weather can have a significant effect on our results of operations and are also considered in our hedging and optimization activities.
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. Our reportable segments are West (including geothermal), Texas and East (including Canada).
Our portfolio, including partnership interests, consists of 80 power plants, including one under construction, with an aggregate current generation capacity of 25,967 MW and 828 MW under construction. Our fleet, including projects under construction, consists of 65 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 segments have an aggregate generation capacity of 7,425 MW in the West, 9,086 MW in Texas and 9,456 MW with an additional 828 MW under construction in the East. Inclusive of our power generation portfolio and our retail sales platforms, we serve customers in 25 states in the U.S. and in Canada and Mexico.
Our fleet of flexible and modern natural gas-fired, combined-cycle power plants performed exceptionally well during the sustained weather event caused by Hurricane Harvey during the third quarter of 2017. Despite very difficult conditions, the vast majority of our 9,086 MW Texas power plant fleet was available for dispatch with no material damage reported. In addition, our Geysers Assets did not sustain any damage as a result of the recent wildfires in northern California.
Merger Agreement
On August 17, 2017, we entered into a Merger Agreement with Volt Parent, LP (“Volt Parent”), and Volt Merger Sub, Inc. (“Merger Sub”), a wholly-owned subsidiary of Volt Parent, pursuant to which Merger Sub will merge with and into Calpine, with Calpine surviving the Merger as a subsidiary of Volt Parent.
At the effective time of the Merger, each share of Calpine’s common stock outstanding as of immediately prior to the effective time of the Merger (excluding common shares held directly by Volt Parent or Merger Sub, common shares held by Calpine as treasury stock, common shares that are subject to vesting or other applicable lapse restrictions, common shares held by any subsidiary of either Calpine or Volt Parent (other than Merger Sub), common shares held by Volt Energy Holdings, LP, an affiliate of Energy Capital Partners III, LLC, and common shares pursuant to which dissenting rights under Delaware law have been properly exercised and not withdrawn or lost) will, at the effective time of the Merger, cease to be outstanding and be converted into the right to receive $15.25 per share in cash or approximately $5.6 billion. Calpine currently expects the Merger to be completed
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in the first quarter of 2018, subject to approval by stockholders representing a majority of outstanding shares of Calpine common stock, the receipt of certain regulatory approvals and the satisfaction or waiver of certain other customary closing conditions. See Note 1 of the Notes to Consolidated Condensed Financial Statements for further information related to the Merger and the Merger Agreement.
Legislative and Regulatory Update
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 2016 Form 10-K.
U.S. Department of Energy Study and Proposed Rule
At the direction of U.S. Department of Energy (“DOE”) Secretary Rick Perry, DOE staff conducted a study to analyze the effect of regulations, mandates, and subsidies on baseload generation resources and electric grid reliability. The study was requested by the Secretary as a result of concerns over the closures of baseload resources, which the Secretary deems as critical to a well-functioning electric grid. The DOE staff studied the causes and effect of coal and nuclear retirements and made a number of targeted policy recommendations, including proposals for the FERC to expedite its efforts to improve energy price formation in the wholesale energy markets, to address essential reliability services by establishing fuel-neutral and market-based valuations of those services that are needed to support grid reliability, and a proposal that the DOE, NERC and RTOs/ISOs work collaboratively to address grid resilience.
On September 28, 2017, the Secretary of the DOE sent to the FERC a Notice of Proposed Rulemaking (“NOPR”), acting under his authority pursuant to Section 403 of the DOE Organization Act. On October 2, 2017, the FERC issued a Notice inviting comments on the submission of the DOE’s NOPR. Under the DOE’s proposed rule, generators located within ISOs or RTOs that have a 90-day on-site fuel supply and meet other reliability criteria would be eligible for the full recovery of costs and a return on equity. Comments on the NOPR were due October 23, 2017. Reply comments are due November 7, 2017. We believe that guaranteed rate recovery for certain generators in RTOs and ISOs is discriminatory and contrary to a competitive market structure, and we intend to raise our comments and concerns through the FERC comment process. We cannot predict at this time how the FERC will rule on the NOPR or what effect it could have on our business.
CAISO
The CAISO is increasingly concerned with the premature retirement of uneconomic generation resources. It is evaluating the viability of units upon request and on a case-by-case basis particularly focusing on the risk of retirement in local, reliability constrained areas. It is also considering modifications to the review and approval of compensation for units threatened by economic retirement, but needed for reliability under the Reliability Must Run or Capacity Procurement Mechanism portions of its tariff.
Due to an expected lack of adequate compensation, we informed the CAISO of our intent to make four of our California natural-gas fired peaking power plants and our Metcalf Energy Center unavailable for dispatch commencing in 2018. CAISO technical analyses determined that two of the peaking power plants, the Yuba City and Feather River Energy Centers, and Metcalf Energy Center are each needed to continue reliable operation of the power grid. The CAISO Board of Governors has approved the designation of Yuba City and Feather River Energy Centers as Reliability Must Run resources for the calendar year 2018 and we expect the CAISO Board of Governors to make a decision on our Metcalf Energy Center in the near future. We are currently negotiating Reliability Must Run contracts for these power plants and expect to file contracts in early November 2017. We do not anticipate the suspension of operations at our other two peaking power plants will have a material effect on our financial condition, results of operations or cash flows.
ERCOT
The PUCT is considering changes regarding its approach to resource adequacy, including price formation and scarcity pricing as operating reserves decline. ERCOT successfully launched the Operating Reserve Demand Curve (“ORDC”) functionality on June 1, 2014. This application produces a price “adder” to the clearing price of energy that increases as reserve capacity declines. The PUCT requested a review of the effectiveness of the ORDC and requested input from ERCOT and market participants, including any recommendations to improve the ORDC. The PUCT continues to consider the appropriate reliability standard that should be used to set ERCOT’s planning reserve margin.
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Additionally, the PUCT has established a project to assess price formation rules in ERCOT’s energy-only market in an effort to take market participant input on the white paper, Priorities for the Evolution of an Energy-Only Electricity Market Design in ERCOT, which was commissioned by Calpine and NRG Energy, Inc. The paper was authored by Drs. William W. Hogan of Harvard University and Susan L. Pope of FTI Consulting, both widely recognized experts in the field of wholesale electric market design and price formation. The PUCT held a public workshop in the docket on August 10, 2017 that featured Drs. Hogan and Pope reviewing the paper in detail and providing background on its recommendations. The PUCT followed up on October 13, 2017 with another public workshop as a forum for stakeholder advocacy for and against the recommendations. The PUCT staff will seek further direction from the commissioners at an upcoming open meeting and also indicated that they may ask for filed comments on what topics need more exploration and how they should be prioritized.
As these proceedings are ongoing and the timing of these changes is uncertain, we cannot predict the ultimate effect on our financial condition, results of operations or cash flows.
PJM
The Ohio utilities, led by American Electric Power, Inc. and FirstEnergy Corp. (“FE”), have indicated their intentions to advocate for some form of re-regulation in this year’s legislative session which began on January 3, 2017. Re-regulation will require enabling legislation, and to date no proposal has been made public by the utilities. On April 6, 2017, at the behest of FE, a bill was introduced in the Ohio Senate to subsidize FE’s Ohio nuclear power plants. An identical bill was introduced in the Ohio House of Representatives on April 10, 2017. Although these bills remain pending, a new bill to subsidize Ohio nuclear power plants was introduced on October 17, 2017, by the author of the prior Ohio House of Representatives legislation which has stalled before the House Public Utilities Committee. Consideration of the Ohio Senate companion legislation has similarly slowed in recent months. While we cannot predict the likelihood of these legislative efforts passing, we believe the proposed subsidies would frustrate the operation of PJM’s wholesale market structure that is regulated by the FERC.
Over significant opposition, the Illinois legislature voted to approve an out-of-market nuclear subsidy scheme put forward by Exelon Corporation (“Exelon”). Zero Emission Credits (“ZECs”) are to be paid to Exelon’s nuclear units beginning with the planning year commencing June 1, 2017. We believe these subsidies will frustrate the operation of the wholesale market structure regulated by the FERC. In February 2017, Calpine, along with a group of generators and our trade association, the Electric Power Supply Association, filed a lawsuit in federal district court challenging the ZEC legislation on constitutional grounds. On July 14, 2017, the federal district court dismissed the lawsuit in part for lack of subject-matter jurisdiction and in part for failure to state a claim. On July 17, 2017, the plaintiffs filed an appeal of this ruling to the U.S. Court of Appeals for the Seventh Circuit. Briefing is underway.
In November 2016, PJM filed proposed tariff changes with the FERC that allow increased seasonal resource participation in the Capacity Performance auction, effective for the 2020/2021 base residual auction that was held in May 2017. Because the FERC did not have a quorum of FERC commissioners to rule on the filing, the FERC staff accepted PJM’s filing, subject to refund. As a result, the 2020/2021 base residual auction was conducted subject to refund and further FERC order. We support PJM’s proposal and believe the tariff changes preserve the competitiveness of the PJM power market; however, we cannot predict whether the FERC will approve PJM’s proposal or the ultimate effect on our financial condition, results of operations or cash flows.
Effective May 11, 2017, PJM implemented transient shortage/scarcity pricing on a five minute basis as ordered by the FERC. This new pricing regime is expected to increase energy revenues in the real-time energy market as well as reserve revenues.
In June 2017, the U.S. Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”) denied the appeal filed by several entities related to the FERC’s orders which approved the PJM capacity market rule changes, referred to as Capacity Performance, which set forth stronger performance incentives and more significant penalties for failure to perform during emergency power system conditions. We support PJM’s capacity market rule changes and believe that, overall, they enhance the competitiveness and reliability of the PJM power market.
In July 2017, the D.C. Circuit granted an appeal filed by several generators regarding a May 2013 FERC order rejecting parts of a PJM proposal intended to make a component of PJM’s Reliability Pricing Model, the Minimum Offer Price Rule (“MOPR”), more transparent and objective. In the May 2013 order, the FERC accepted parts of PJM’s proposal but found that PJM must amend its tariff proposal in certain ways in order to make the proposal just and reasonable as required by the FERC’s regulations. PJM agreed to these changes, and the FERC approved the revised tariff filing. Several generators sought rehearing of the FERC’s order, which the FERC denied. In October 2015, an appeal followed. In the July 2017 decision, the D.C. Circuit found that the FERC does not have the authority under Section 205 of the Federal Power Act to propose its own tariff modifications, even though PJM agreed to the FERC’s proposed changes. The D.C. Circuit vacated the FERC’s orders with respect to several components of the tariff filing and remanded the matter to the FERC. We cannot predict how the FERC will address the case on remand or what effect, if any, the D.C. Circuit’s decision will have on our business.
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ISO-NE
In January, 2017, ISO-NE requested that the FERC approve a revised Cost of New Entry (“Net CONE”) parameter beginning with the 2018 Forward Capacity Auction for the 2021/2022 delivery period which is lower than the previous Net CONE. Our trade association protested the filing, but on October 6, 2017, the FERC issued an order approving ISO-NE’s revisions.
On March 27, 2017, the Massachusetts Department of Public Utilities approved the issuance of a Request for Proposals (“RFP”) for up to 1,200 MW of new “clean energy” resources. A separate RFP for at least 400 MW of offshore wind was issued on June 29, 2017. We believe the subsidies provided to these new renewable resources will adversely affect the power markets in ISO-NE by artificially suppressing prices.
The Connecticut Legislature has enacted legislation that, if signed by the Governor, would allow the Millstone nuclear power plant to bid into an RFP to potentially obtain a PPA. The legislation requires the state to undertake a review of Millstone’s financial needs and allows, but does not require, the state to issue an RFP. If a contract is ultimately awarded, we believe the subsidies provided through the legislation will adversely affect the power markets in ISO-NE by artificially suppressing prices.
New England Capacity Market Zero -Price Offer Requirement for Locked in Resources
ISO-NE seeks to encourage new generation to enter its power market by allowing new generators to lock in their capacity payment price for up to seven years. When a new generator agrees to this offer, ISO-NE requires that generator to offer its generation capacity into its capacity market auction during the lock-in period at a price of $0. Several parties, including Calpine, complained to FERC about this provision, arguing that it unfairly suppresses prices for existing generators. After the FERC rejected these complaints, several parties appealed the FERC’s decisions to the D.C. Circuit. On October 6, 2017, the D.C. Circuit heard oral argument on the case. A decision is expected within the next several months. We cannot predict how the D.C Circuit will rule on the appeal, but we believe that if the D.C. Circuit were to grant the appeal and the FERC, on remand, were to amend or remove the zero-price offer requirement, it would be a positive development for our business in New England.
ISO-NE and PJM Market Reform Proposals
Both ISO-NE and PJM have released draft proposals that would accommodate state procurement initiatives while at the same time protecting the integrity of their power markets. ISO-NE’s proposal focuses on changes to the Forward Capacity Market, while PJM’s proposals suggest possible changes to energy price formation, ancillary service procurement, as well as modifications to the Reliability Pricing Model. Stakeholder processes are underway in both ISOs to discuss possible revisions to each region’s capacity market and the stakeholder process on energy market reforms is pending in PJM. It is possible that the current proposals may be significantly modified, or possibly even withdrawn altogether. Because of this, and because it is unknown how the FERC will rule on any resulting tariff changes, we cannot predict the effect these changes will have on our business in those regions.
NYISO
On August 1, 2016, the New York State Department of Public Service (“NY DPS”) approved the Clean Energy Standard which requires 50% of the state’s generation to be produced by renewable resources by 2030. In addition, the Clean Energy Standard provides for out-of-market financial subsidies in the form of ZECs for some of the state’s existing nuclear generation facilities. In October 2016, a group of generators and our trade association, the Electric Power Supply Association, filed a lawsuit in federal court challenging the PSC’s ruling on constitution grounds. On July 25, 2017, the federal district court dismissed the lawsuit, finding that plaintiffs do not have a private right to bring the claims, and further finding that the ZEC program is not preempted by federal law and does not violate the dormant Commerce Clause. The plaintiffs appealed this ruling to the U.S. Court of Appeals for the Second Circuit. Briefing is underway. We cannot predict the outcome of the appeal, but if the PSC’s action is left unchecked, we believe these subsidies will adversely affect the power markets in NYISO by artificially suppressing prices. As we do not have a substantial power generation presence in NYISO, the potential effect of the out-of-market financial subsidies are not expected to have a material effect on our financial condition, results of operations or cash flows. However, the subsidies could be meaningful to other power companies in the NYISO region.
On August 10, 2017, NYISO and NY DPS jointly initiated a collaborative effort to potentially develop a method of pricing CO 2 in the NYISO wholesale energy market to support state decarbonization goals. The process does not have a definitive timeline and we currently cannot predict the potential effect it could have on our operations and financial performance.
Clean Power Plan
The Clean Power Plan requires a reduction in GHG emissions from existing power plants of 32% from 2005 levels by 2030. The U.S. Supreme Court issued a stay of the Clean Power Plan until the D.C. Circuit issues a ruling on the merits and through final determination in any further appeal to the U.S. Supreme Court from the D.C. Circuit decision. The D.C. Circuit heard oral argument on September 27, 2016. On March 28, 2017, the President issued an Executive Order, “Promoting Energy Independence
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and Economic Growth,” which orders, among other things, the EPA to review the Clean Power Plan for consistency with policies articulated by the Executive Order and, if appropriate, to commence a rulemaking to suspend, revise or rescind the Clean Power Plan. On the same day, the EPA asked the D.C. Circuit to hold the ongoing litigation in abeyance until completion of the ongoing review and any subsequent rulemaking. The D.C. Circuit has twice ordered the case held in abeyance temporarily. On October 10, 2017, the EPA Administrator signed a notice of proposed rulemaking to repeal the Clean Power Plan upon the basis that it exceeds the EPA’s authority. The notice also announced that the EPA continues to consider whether it should issue another rule addressing GHGs from existing power plants and, if so, what the appropriate form and scope of that rule should be. The notice also announced that the EPA will be issuing an advance NOPR in the near future to solicit information on systems of emission reduction that are in accord with the EPA’s proposed legal interpretation of its authority. On the same day, the EPA asked the D.C. Circuit to continue to hold the case in abeyance until completion of the proposed rulemaking to repeal the Clean Power Plan.
California: GHG – Cap-and-Trade Regulation
The Cap-and-Trade Regulation was subject to legal challenges claiming that, by requiring covered entities to obtain allowances, the Cap-and-Trade Regulation amounts to an unlawful tax. California law requires a two-thirds supermajority vote of the legislature to impose new taxes and AB 32 was not passed by a supermajority. On April 6, 2017, the California Court of Appeal affirmed the decision of the trial court that the Cap-and-Trade Regulation does not amount to an unlawful tax because allowances are valuable commodities, which entities voluntarily purchase to comply with the Cap-and-Trade Regulation. On June 28, 2017, the California Supreme Court rejected petitions for review of the decision, affirming the legality of the Cap-and-Trade program through 2020.
On July 17, 2017, the California legislature passed Assembly Bill (“AB”) 398, by a two-thirds supermajority vote, authorizing extension of the Cap-and-Trade Regulation through 2030. AB 398 requires the CARB to develop a price ceiling considering, among other things, the full social cost associated with emitting a ton of GHGs and the cost per ton of GHG emission reductions needed to achieve California’s goal of reducing statewide GHG emissions to 40 percent below 1990 levels by 2030. AB 398 was passed along with a companion bill, AB 617, which requires the CARB to prepare a statewide strategy to reduce emissions of toxic air contaminants and criteria air pollutants in communities affected by a high cumulative exposure burden and the local air districts to prepare community emissions reduction programs to achieve emissions reductions within such communities, as identified by the CARB. AB 398 and AB 617 were signed into law by California Governor Brown on July 25 and 26, 2017, respectively.
On July 27, 2017, the CARB adopted amendments to the Cap-and-Trade Regulation extending the program through 2030, incorporating requirements to align the Cap-and-Trade Regulation with the Clean Power Plan and linking the existing California-Québec market with the Cap-and-Trade program implemented by Ontario. The amended Cap-and-Trade Regulation became effective on October 1, 2017 and the linkage of the California-Québec market with Ontario will become effective on January 1, 2018. The CARB has since held workshops to propose further amendments to the Cap-and-Trade Regulation in accordance with the requirements of AB 398.
Several of our natural gas-fired power plants in California will likely remain subject to the Cap-and-Trade Regulation through 2030 as a result of passage of AB 398, although we believe the net effect of the Cap-and-Trade Regulation will be beneficial to us, particularly by increasing the appeal of our Geysers Assets. While it is too early to predict whether any of our California natural gas-fired power plants may ultimately be subject to a requirement to reduce emissions under AB 617 or what such a requirement might entail, much of our California fleet already meets emissions limits that are among the lowest in the U.S. and we do not anticipate that significant additional reductions will be required from our fleet pursuant to AB 617.
Massachusetts: Global Warming Solutions Act
On December 16, 2016, the Massachusetts Department of Environmental Protection proposed regulations that would impose new GHG limits on power plants and other sources. These regulations are notable because they are structured as annually-declining hard caps on CO 2 emissions from regulated facilities. The Massachusetts Department of Environmental Protection issued a final rule on August 11, 2017, which will become effective as of January 1, 2018. Although we view the regulations as likely to result in market distortions impeding the efficient operation of both power and emissions markets, we believe that we will be able to comply with its provisions.
California RPS
California’s RPS requires retail power providers to generate or procure 33% and 50% of the power they sell to retail customers from renewable resources by 2020 and 2030, respectively, with intermediate targets leading up to 2020 and 2030. Behind-the-meter solar generally does not count towards California’s RPS requirements. Under California’s RPS, there are limits on different “buckets” of procurement that can be used to satisfy the RPS. Load-serving entities must satisfy a growing fraction of their compliance obligations with renewable power from resources located in California or delivered into California within the
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hour, such as our Geysers Assets. The California legislature is considering increasing the RPS to 60% by 2030 and, potentially, a 100% CO 2-free RPS by 2045; however, a vote on this proposal is not likely until the 2018 legislative session. While the RPS generally depresses wholesale energy prices, the intermittency of many renewable resources raises operational flexibility challenges that present opportunities for natural gas-fired generation to provide capacity and ancillary services products.
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RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2017 AND 2016
Below are our results of operations for the three months ended September 30, 2017 as compared to the same period in 2016 (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.

| 2017 |  | 2016 |  | Change |  | % Change
Operating revenues: |  |  |  |  |  |  |
Commodity revenue | $ | 2,506 |  |  | $ | 2,063 |  |  | $ | 443 |  |  | 21 |
Mark-to-market gain | 76 |  |  | 287 |  |  | (211 | ) |  | (74 | )
Other revenue | 4 |  |  | 5 |  |  | (1 | ) |  | (20 | )
Operating revenues | 2,586 |  |  | 2,355 |  |  | 231 |  |  | 10 |
Operating expenses: |  |  |  |  |  |  |
Fuel and purchased energy expense: |  |  |  |  |  |  |
Commodity expense | 1,711 |  |  | 1,294 |  |  | (417 | ) |  | (32 | )
Mark-to-market loss | 10 |  |  | 178 |  |  | 168 |  |  | 94 |
Fuel and purchased energy expense | 1,721 |  |  | 1,472 |  |  | (249 | ) |  | (17 | )
Plant operating expense | 228 |  |  | 215 |  |  | (13 | ) |  | (6 | )
Depreciation and amortization expense | 179 |  |  | 161 |  |  | (18 | ) |  | (11 | )
Sales, general and other administrative expense | 37 |  |  | 33 |  |  | (4 | ) |  | (12 | )
Other operating expenses | 23 |  |  | 18 |  |  | (5 | ) |  | (28 | )
Total operating expenses | 2,188 |  |  | 1,899 |  |  | (289 | ) |  | (15 | )
Impairment losses | 12 |  |  | — |  |  | (12 | ) |  | # |
(Income) from unconsolidated subsidiaries | (7 | ) |  | (6 | ) |  | 1 |  |  | 17 |
Income from operations | 393 |  |  | 462 |  |  | (69 | ) |  | (15 | )
Interest expense | 156 |  |  | 158 |  |  | 2 |  |  | 1 |
Debt extinguishment costs | 1 |  |  | — |  |  | (1 | ) |  | # |
Other (income) expense, net | 7 |  |  | 7 |  |  | — |  |  | — |
Income before income taxes | 229 |  |  | 297 |  |  | (68 | ) |  | (23 | )
Income tax benefit | (2 | ) |  | (4 | ) |  | (2 | ) |  | (50 | )
Net income | 231 |  |  | 301 |  |  | (70 | ) |  | (23 | )
Net income attributable to the noncontrolling interest | (6 | ) |  | (6 | ) |  | — |  |  | — |
Net income attributable to Calpine | $ | 225 |  |  | $ | 295 |  |  | $ | (70 | ) |  | (24 | )

| 2017 |  | 2016 |  | Change |  | % Change
Operating Performance Metrics: |  |  |  |  |  |  |
MWh generated (in thousands)(1)(2) | 28,834 |  |  | 33,552 |  |  | (4,718 | ) |  | (14 | )
Average availability(2) | 95.1 | % |  | 97.3 | % |  | (2.2 | )% |  | (2 | )
Average total MW in operation(1) | 25,185 |  |  | 26,502 |  |  | (1,317 | ) |  | (5 | )
Average capacity factor, excluding peakers | 57.4 | % |  | 62.6 | % |  | (5.2 | )% |  | (8 | )
Steam Adjusted Heat Rate(2) | 7,407 |  |  | 7,333 |  |  | (74 | ) |  | (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.

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We evaluate our Commodity revenue and Commodity expense on a collective basis as the price of power and natural gas tend to move together because 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 and Adjusted Free Cash Flow.”
Commodity revenue, net of Commodity expense, increased $26 million for the three months ended September 30, 2017, compared to the same period in 2016, primarily due to (favorable variances are shown without brackets while unfavorable variances are shown with brackets):

(in millions) |  |
$ | 26 |  |  | Higher energy margins due to increased contribution from hedging activity following the acquisitions of Calpine Solutions in December 2016 and North American Power in January 2017. These factors were partially offset by the expiration of a PPA at our York Energy Center in our East segment, lower Spark Spreads in our East segment and lower generation across all segments(1)
35 |  |  | Higher regulatory capacity revenue primarily in our East segment(1)
(17 | ) |  | The net period-over-period effect of our portfolio management activities, primarily including the sales of the 375 MW Mankato Power Plant in October 2016 and the 599 MW Osprey Energy Center in January 2017(1)
(18 | ) |  | Contract amortization, lease levelization related to tolling contracts and other(2)
$ | 26 |  |  |

__________

(1) | These items comprise the period-over-period change in our Commodity Margin which is a non-GAAP financial measure. See “Commodity Margin and Adjusted Free Cash Flow” for a description of our non-GAAP financial measures and a discussion of the period-over-period change in Commodity Margin by segment.

(2) | 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.

Mark-to-market gain/loss, net from hedging our future generation, retail activities and fuel needs had an unfavorable variance of $43 million primarily driven by the change in forward commodity prices on our derivative contracts during the quarter ended September 30, 2017 partially offset by activity resulting from the expansion of our retail hedging portfolio following the acquisition of Calpine Solutions in December 2016.
Our normal, recurring plant operating expense increased by $1 million for the three months ended September 30, 2017 compared to the same period in 2016, after excluding the effect of a $17 million increase due to the period-over-period effect associated with the expansion of our retail portfolio through the acquisitions of Calpine Solutions in December 2016 and North American Power in January 2017 which was partially offset by the period-over-period effect of power plant portfolio changes, a $6 million increase in severance and other employee-related costs, a $6 million decrease due to the timing of receipt of insurance proceeds received for the Delta Energy Center for equipment failure costs and a $5 million decrease in major maintenance expense resulting from our plant outage schedule and costs from scrap parts related to outages.
Depreciation and amortization expense increased by $18 million for the three months ended September 30, 2017 compared to the same period in 2016 primarily due to the acquisitions of Calpine Solutions and North American Power in December 2016 and January 2017, respectively, and the reclassification of South Point Energy Center from held for sale to held and used during the first quarter of 2017.
Sales, general and other administrative expense increased by $4 million for the three months ended September 30, 2017 compared to the same period in 2016 primarily due to the acquisitions of Calpine Solutions and North American Power in December 2016 and January 2017, respectively, and higher stock-based compensation expense resulting from an increase in the value of our performance share units during the third quarter of 2017.
Other operating expenses increased by $5 million for the three months ended September 30, 2017 compared to the same period in 2016 primarily due to merger-related costs related to legal, investment banking and other professional fees associated with the Merger. See Note 1 of the Notes to Consolidated Condensed Financial Statements for further information related to the Merger and the Merger Agreement.
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During the three months ended September 30, 2017, we recorded an impairment of approximately $12 million to adjust the carrying value of turbine equipment to fair value following the initiation of marketing efforts during the third quarter of 2017.
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RESULTS OF OPERATIONS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2017 AND 2016
Below are our results of operations for the nine months ended September 30, 2017 as compared to the same period in 2016 (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.

| 2017 |  | 2016 |  | Change |  | % Change
Operating revenues: |  |  |  |  |  |  |
Commodity revenue | $ | 6,714 |  |  | $ | 5,199 |  |  | $ | 1,515 |  |  | 29 |
Mark-to-market gain (loss) | 224 |  |  | (79 | ) |  | 303 |  |  | # |
Other revenue | 13 |  |  | 14 |  |  | (1 | ) |  | (7 | )
Operating revenues | 6,951 |  |  | 5,134 |  |  | 1,817 |  |  | 35 |
Operating expenses: |  |  |  |  |  |  |
Fuel and purchased energy expense: |  |  |  |  |  |  |
Commodity expense | 4,757 |  |  | 3,197 |  |  | (1,560 | ) |  | (49 | )
Mark-to-market (gain) loss | 185 |  |  | (57 | ) |  | (242 | ) |  | # |
Fuel and purchased energy expense | 4,942 |  |  | 3,140 |  |  | (1,802 | ) |  | (57 | )
Plant operating expense | 812 |  |  | 741 |  |  | (71 | ) |  | (10 | )
Depreciation and amortization expense | 542 |  |  | 490 |  |  | (52 | ) |  | (11 | )
Sales, general and other administrative expense | 117 |  |  | 106 |  |  | (11 | ) |  | (10 | )
Other operating expenses | 63 |  |  | 55 |  |  | (8 | ) |  | (15 | )
Total operating expenses | 6,476 |  |  | 4,532 |  |  | (1,944 | ) |  | (43 | )
Impairment losses | 41 |  |  | 13 |  |  | (28 | ) |  | # |
(Gain) on sale of assets, net | (27 | ) |  | — |  |  | 27 |  |  | # |
(Income) from unconsolidated subsidiaries | (17 | ) |  | (16 | ) |  | 1 |  |  | 6 |
Income from operations | 478 |  |  | 605 |  |  | (127 | ) |  | (21 | )
Interest expense | 469 |  |  | 472 |  |  | 3 |  |  | 1 |
Debt extinguishment costs | 26 |  |  | 15 |  |  | (11 | ) |  | (73 | )
Other (income) expense, net | 16 |  |  | 18 |  |  | 2 |  |  | 11 |
Income (loss) before income taxes | (33 | ) |  | 100 |  |  | (133 | ) |  | # |
Income tax expense | — |  |  | 17 |  |  | 17 |  |  | # |
Net income (loss) | (33 | ) |  | 83 |  |  | (116 | ) |  | # |
Net income attributable to the noncontrolling interest | (14 | ) |  | (15 | ) |  | 1 |  |  | 7 |
Net income (loss) attributable to Calpine | $ | (47 | ) |  | $ | 68 |  |  | $ | (115 | ) |  | # |

| 2017 |  | 2016 |  | Change |  | % Change
Operating Performance Metrics: |  |  |  |  |  |  |
MWh generated (in thousands)(1)(2) | 71,507 |  |  | 84,032 |  |  | (12,525 | ) |  | (15 | )
Average availability(2) | 88.2 | % |  | 90.9 | % |  | (2.7 | )% |  | (3 | )
Average total MW in operation(1) | 25,196 |  |  | 26,414 |  |  | (1,218 | ) |  | (5 | )
Average capacity factor, excluding peakers | 48.3 | % |  | 53.4 | % |  | (5.1 | )% |  | (10 | )
Steam Adjusted Heat Rate(2) | 7,362 |  |  | 7,307 |  |  | (55 | ) |  | (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.

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

We evaluate our Commodity revenue and Commodity expense on a collective basis as the price of power and natural gas tend to move together because 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 and Adjusted Free Cash Flow.”
Commodity revenue, net of Commodity expense, decreased $45 million for the nine months ended September 30, 2017, compared to the same period in 2016, primarily due to (favorable variances are shown without brackets while unfavorable variances are shown with brackets):

(in millions) |  |
$ | 85 |  |  | Higher energy margins due to increased contribution from hedging activity following the acquisitions of Calpine Solutions in December 2016 and North American Power in January 2017. These factors were partially offset by the expiration of a PPA at our York Energy Center in our East segment, lower Spark Spreads in our East segment and lower generation across all segments(1)
14 |  |  | Higher regulatory capacity revenue primarily in our East segment(1)
(40 | ) |  | A natural gas pipeline transportation billing credit received in our West segment during the second quarter of 2016 with no similar credit received in 2017(1)
(47 | ) |  | The net period-over-period effect of our portfolio management activities, primarily including the sales of the 375 MW Mankato Power Plant in October 2016 and the 599 MW Osprey Energy Center in January 2017(1)
(57 | ) |  | Contract amortization, lease levelization related to tolling contracts and other(2)
$ | (45 | ) |  |

__________

(1) | These items comprise the period-over-period change in our Commodity Margin which is a non-GAAP financial measure. See “Commodity Margin and Adjusted Free Cash Flow” for a description of our non-GAAP financial measures and a discussion of the period-over-period change in Commodity Margin by segment.

(2) | 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.

Mark-to-market gain/loss, net from hedging our future generation, retail activities and fuel needs had a favorable variance of $61 million primarily driven by the change in forward commodity prices on our derivative contracts during the nine months ended September 30, 2017 as well as by activity resulting from the expansion of our retail hedging portfolio following the acquisition of Calpine Solutions in December 2016.
Our normal, recurring plant operating expense decreased by $7 million for the nine months ended September 30, 2017 compared to the same period in 2016, after excluding the effect of a $55 million increase due to the period-over-period effect associated with the expansion of our retail portfolio through the acquisitions of Calpine Solutions in December 2016 and North American Power in January 2017 which was partially offset by the period-over-period effect of power plant portfolio changes, an $18 million increase in severance and other employee-related costs, a $6 million increase in equipment failure costs primarily due to Delta Energy Center partially reduced by the receipt of insurance proceeds and a $1 million decrease in major maintenance expense resulting from our plant outage schedule and costs from scrap parts related to outages.
Depreciation and amortization expense increased by $52 million for the nine months ended September 30, 2017 compared to the same period in 2016 primarily due to the acquisitions of Calpine Solutions and North American Power in December 2016 and January 2017, respectively, and the reclassification of South Point Energy Center from held for sale to held and used during the first quarter of 2017.
Sales, general and other administrative expense increased by $11 million for the nine months ended September 30, 2017 compared to the same period in 2016 primarily due to the acquisitions of Calpine Solutions and North American Power in December 2016 and January 2017, respectively, and higher stock-based compensation expense resulting from an increase in the value of our performance share units during the nine months ended September 30, 2017.
Other operating expenses increased by $8 million for the nine months ended September 30, 2017 compared to the same period in 2016 primarily due merger-related costs related to legal, investment banking and other professional fees associated with
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the Merger. See Note 1 of the Notes to Consolidated Condensed Financial Statements for further information related to the Merger and the Merger Agreement.
During the nine months ended September 30, 2017, we recorded impairment losses of approximately $41 million related to our South Point Energy Center and to adjust the carrying value of turbine equipment to fair value following the initiation of marketing efforts during the third quarter of 2017.
In line with our strategy to focus on competitive wholesale markets and sell or contract power plants located in power markets dominated by regulated utilities or outside our strategic concentration, we completed the sale of the Osprey Energy Center in our East segment on January 3, 2017, resulting in a gain on sale of assets, net of $27 million during the nine months ended September 30, 2017.
Debt extinguishment costs for the nine months ended September 30, 2017, primarily consisted of $21 million in connection with the redemption of our 2023 First Lien Notes in March 2017, which is comprised of $18 million in prepayment penalty and $3 million from the write-off of debt issuance costs, and $4 million from the write-off of debt issuance costs associated with the $400 million partial repayment of our 2017 First Lien Term Loan. Debt extinguishment costs for the nine months ended September 30, 2016, consisted of $15 million from the write-off of deferred financing costs in connection with the repayment of our 2019 and 2020 First Lien Term Loans in May 2016.
During the nine months ended September 30, 2017, we recorded income tax expense of nil compared to an income tax expense of $17 million for the nine months ended September 30, 2016. The favorable period-over-period change primarily resulted from a favorable adjustment to our reserve for uncertain tax positions.
COMMODITY MARGIN AND ADJUSTED FREE CASH FLOW
Management’s Discussion and Analysis of Financial Condition and Results of Operations includes financial information prepared in accordance with U.S. GAAP, as well as the non-GAAP financial measures, Commodity Margin and Adjusted Free Cash Flow, discussed below, which we use as measures of our performance and liquidity, respectively. Generally, a non-GAAP financial measure is a numerical measure of financial performance or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with U.S. GAAP.
With respect to our non-GAAP financial measures, over the current quarterly reporting period, we are transitioning from using Adjusted EBITDA as a performance measure to using Commodity Margin and Adjusted Free Cash Flow as measures of our performance and liquidity, respectively.
We use Commodity Margin, a non-GAAP financial measure, 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, fuel and purchased energy expenses, commodity transmission and transportation expenses and environmental compliance expenses. We believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure reviewed by our chief operating decision maker. Commodity Margin is not a measure calculated in accordance with U.S. GAAP and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with U.S. GAAP. Commodity Margin does not intend to represent income (loss) from operations, the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. See Note 12 of the Notes to Consolidated Condensed Financial Statements for a reconciliation of Commodity Margin to income (loss) from operations by segment.
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Commodity Margin by Segment for the Three Months Ended September 30, 2017 and 2016
The following tables show our Commodity Margin and related operating performance metrics by segment for the three months ended September 30, 2017 and 2016 (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 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: | 2017 |  | 2016 |  | Change |  | % Change
Commodity Margin (in millions) | $ | 327 |  |  | $ | 298 |  |  | $ | 29 |  |  | 10 |
Commodity Margin per MWh generated | $ | 46.79 |  |  | $ | 35.72 |  |  | $ | 11.07 |  |  | 31 |
MWh generated (in thousands) | 6,989 |  |  | 8,343 |  |  | (1,354 | ) |  | (16 | )
Average availability | 93.5 | % |  | 98.9 | % |  | (5.4 | )% |  | (5 | )
Average total MW in operation | 7,425 |  |  | 7,425 |  |  | — |  |  | — |
Average capacity factor, excluding peakers | 45.4 | % |  | 54.5 | % |  | (9.1 | )% |  | (17 | )
Steam Adjusted Heat Rate | 7,351 |  |  | 7,213 |  |  | (138 | ) |  | (2 | )

West — Commodity Margin in our West segment increased by $29 million, or 10%, for the three months ended September 30, 2017 compared to the three months ended September 30, 2016, primarily due to the expansion of our retail hedging activities following the acquisition of Calpine Solutions in December 2016 and higher generation margin where we realized higher Spark Spreads during hours in which we generated, particularly evening peak times. Generation decreased 16% primarily resulting from an extended outage at our Delta Energy Center in 2017. Our Delta Energy Center was restored to simple-cycle operation during the second quarter of 2017 and we expect the power plant will be fully restored to service in the fourth quarter of 2017.

Texas: | 2017 |  | 2016 |  | Change |  | % Change
Commodity Margin (in millions) | $ | 201 |  |  | $ | 198 |  |  | $ | 3 |  |  | 2 |
Commodity Margin per MWh generated | $ | 15.51 |  |  | $ | 14.48 |  |  | $ | 1.03 |  |  | 7 |
MWh generated (in thousands) | 12,959 |  |  | 13,670 |  |  | (711 | ) |  | (5 | )
Average availability | 95.7 | % |  | 97.0 | % |  | (1.3 | )% |  | (1 | )
Average total MW in operation | 8,848 |  |  | 9,191 |  |  | (343 | ) |  | (4 | )
Average capacity factor, excluding peakers | 66.3 | % |  | 67.4 | % |  | (1.1 | )% |  | (2 | )
Steam Adjusted Heat Rate | 7,235 |  |  | 7,142 |  |  | (93 | ) |  | (1 | )

Texas — Commodity Margin in our Texas segment increased by $3 million, or 2%, for the three months ended September 30, 2017 compared to the three months ended September 30, 2016, primarily due to higher contribution from hedges. Generation decreased 5% primarily resulting from milder weather inclusive of the effect of Hurricane Harvey during the third quarter of 2017 and the retirement of our Clear Lake Power Plant in February 2017.

East: | 2017 |  | 2016 |  | Change |  | % Change
Commodity Margin (in millions) | $ | 336 |  |  | $ | 324 |  |  | $ | 12 |  |  | 4 |
Commodity Margin per MWh generated | $ | 37.81 |  |  | $ | 28.08 |  |  | $ | 9.73 |  |  | 35 |
MWh generated (in thousands) | 8,886 |  |  | 11,539 |  |  | (2,653 | ) |  | (23 | )
Average availability | 95.8 | % |  | 96.5 | % |  | (0.7 | )% |  | (1 | )
Average total MW in operation | 8,912 |  |  | 9,886 |  |  | (974 | ) |  | (10 | )
Average capacity factor, excluding peakers | 58.1 | % |  | 64.3 | % |  | (6.2 | )% |  | (10 | )
Steam Adjusted Heat Rate | 7,714 |  |  | 7,660 |  |  | (54 | ) |  | (1 | )

East — Commodity Margin in our East segment increased by $12 million, or 4%, for the three months ended September 30, 2017 compared to the three months ended September 30, 2016, primarily due to higher contribution from hedges including the expansion of our retail hedging activities following the acquisitions of Calpine Solutions in December 2016 and North American Power in January 2017 and higher regulatory capacity revenue. The increase in Commodity Margin was partially offset by the
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sales of the 375 MW Mankato Power Plant in October 2016 and the 599 MW Osprey Energy Center in January 2017, the expiration of a PPA associated with our York Energy Center in May 2017 and lower Spark Spreads during the third quarter of 2017. Generation decreased 23% primarily resulting from the power plant sales and weaker market conditions during the third quarter of 2017.
Commodity Margin by Segment for the Nine Months Ended September 30, 2017 and 2016
The following tables show our Commodity Margin and related operating performance metrics by segment for the nine months ended September 30, 2017 and 2016 (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 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: | 2017 |  | 2016 |  | Change |  | % Change
Commodity Margin (in millions) | $ | 792 |  |  | $ | 749 |  |  | $ | 43 |  |  | 6 |
Commodity Margin per MWh generated | $ | 49.31 |  |  | $ | 37.84 |  |  | $ | 11.47 |  |  | 30 |
MWh generated (in thousands) | 16,061 |  |  | 19,796 |  |  | (3,735 | ) |  | (19 | )
Average availability | 84.1 | % |  | 91.6 | % |  | (7.5 | )% |  | (8 | )
Average total MW in operation | 7,425 |  |  | 7,425 |  |  | — |  |  | — |
Average capacity factor, excluding peakers | 35.2 | % |  | 43.5 | % |  | (8.3 | )% |  | (19 | )
Steam Adjusted Heat Rate | 7,383 |  |  | 7,276 |  |  | (107 | ) |  | (1 | )

West — Commodity Margin in our West segment increased by $43 million, or 6%, for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016, primarily due to the expansion of our retail hedging activities following the acquisition of Calpine Solutions in December 2016 and higher generation margin where we realized higher Spark Spreads during hours in which we generated, particularly evening peak times. The increase in Commodity Margin was partially offset by receipt of a $40 million natural gas pipeline transportation billing credit during the second quarter of 2016. Generation decreased 19% primarily resulting from an increase in hydroelectric generation in the region and an extended outage at our Delta Energy Center in 2017. Our Delta Energy Center was restored to simple-cycle operation during the second quarter of 2017 and we expect the power plant will be fully restored to service in the fourth quarter of 2017.

Texas: | 2017 |  | 2016 |  | Change |  | % Change
Commodity Margin (in millions) | $ | 516 |  |  | $ | 511 |  |  | $ | 5 |  |  | 1 |
Commodity Margin per MWh generated | $ | 15.56 |  |  | $ | 13.70 |  |  | $ | 1.86 |  |  | 14 |
MWh generated (in thousands) | 33,166 |  |  | 37,306 |  |  | (4,140 | ) |  | (11 | )
Average availability | 88.9 | % |  | 90.8 | % |  | (1.9 | )% |  | (2 | )
Average total MW in operation | 8,855 |  |  | 9,191 |  |  | (336 | ) |  | (4 | )
Average capacity factor, excluding peakers | 57.2 | % |  | 61.7 | % |  | (4.5 | )% |  | (7 | )
Steam Adjusted Heat Rate | 7,144 |  |  | 7,113 |  |  | (31 | ) |  | — |

Texas — Commodity Margin in our Texas segment increased by $5 million, or 1%, for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016, primarily due to higher contribution from hedges. Generation decreased 11% primarily resulting from higher natural gas prices during the nine months ended September 30, 2017 compared to the same period in 2016.
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East: | 2017 |  | 2016 |  | Change |  | % Change
Commodity Margin (in millions) | $ | 761 |  |  | $ | 797 |  |  | $ | (36 | ) |  | (5 | )
Commodity Margin per MWh generated | $ | 34.16 |  |  | $ | 29.60 |  |  | $ | 4.56 |  |  | 15 |
MWh generated (in thousands) | 22,280 |  |  | 26,930 |  |  | (4,650 | ) |  | (17 | )
Average availability | 90.5 | % |  | 90.7 | % |  | (0.2 | )% |  | — |
Average total MW in operation | 8,916 |  |  | 9,798 |  |  | (882 | ) |  | (9 | )
Average capacity factor, excluding peakers | 50.0 | % |  | 52.4 | % |  | (2.4 | )% |  | (5 | )
Steam Adjusted Heat Rate | 7,692 |  |  | 7,614 |  |  | (78 | ) |  | (1 | )

East — Commodity Margin in our East segment decreased by $36 million, or 5%, for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016, primarily due to the sales of the 375 MW Mankato Power Plant in October 2016 and the 599 MW Osprey Energy Center in January 2017, the expiration of a PPA associated with our York Energy Center in May 2017 and lower Spark Spreads during the nine months ended September 30, 2017. The decrease in Commodity Margin was partially offset by the expansion of our retail hedging activities following the acquisitions of Calpine Solutions in December 2016 and North American Power in January 2017, higher regulatory capacity revenue and the positive effect of a new PPA associated with our Morgan Energy Center which became effective in February 2016. Generation decreased 17% primarily resulting from the power plant sales and weaker market conditions during the nine months ended September 30, 2017.
Adjusted Free Cash Flow
We define Adjusted Free Cash Flow, a non-GAAP liquidity measure, as cash flows from operating activities adjusted for certain items described below and presented in the accompanying reconciliation. We believe Adjusted Free Cash Flow is useful to investors and other users of our financial statements in evaluating our liquidity and operating performance as it provides an additional tool to compare financial results across companies and across periods. Additionally, we believe that Adjusted Free Cash Flow is widely used by investors to measure a company’s liquidity. Adjusted Free Cash Flow is not a measure calculated in accordance with U.S. GAAP, and should be viewed as a supplement to, and not a substitute for, our financial results presented in accordance with U.S. GAAP. Adjusted Free Cash Flow is not intended to represent cash flows from operations as defined by U.S. GAAP as an indicator of liquidity and is not necessarily comparable to similarly-titled measures reported by other companies.
As we define it, Adjusted Free Cash Flow represents cash flows from operating activities including the effects of maintenance capital expenditures, adjustments to reflect the Adjusted Free Cash Flow from unconsolidated investments and to exclude the noncontrolling interest, and other miscellaneous adjustments such as the effect of changes in working capital. We adjust for these items in our Adjusted Free Cash Flow as our management believes that they would distort their ability to efficiently view and assess our core operating and liquidity trends.
In summary, our management determined that Adjusted Free Cash Flow is a useful measure of liquidity to assist in comparing financial results from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with our Board of Directors, shareholders, creditors, analysts and investors concerning our financial results.
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In the following table, we have reconciled our cash flows from operating activities to our Adjusted Free Cash Flow for the three and nine months ended September 30, 2017 and 2016 (in millions):

|  | Three Months Ended September 30, |  | Nine Months Ended September 30,
|  | 2017 |  | 2016 |  | 2017 |  | 2016
Net cash provided by operating activities |  | $ | 561 |  |  | $ | 542 |  |  | $ | 807 |  |  | $ | 667 |
Maintenance capital expenditures |  | (30 | ) |  | (39 | ) |  | (139 | ) |  | (120 | )
Tax differences |  | 3 |  |  | (7 | ) |  | (13 | ) |  | (5 | )
Adjustments to reflect Adjusted Free Cash Flow from unconsolidated investments and exclude the non-controlling interest |  | (6 | ) |  | (3 | ) |  | (6 | ) |  | (5 | )
Capitalized corporate interest |  | (7 | ) |  | (5 | ) |  | (20 | ) |  | (14 | )
Changes in working capital(1) |  | (141 | ) |  | (150 | ) |  | (95 | ) |  | 101 |
Other(2) |  | 62 |  |  | 45 |  |  | 54 |  |  | 19 |
Adjusted Free Cash Flow(3) |  | $ | 442 |  |  | $ | 383 |  |  | $ | 588 |  |  | $ | 643 |
Net cash used in investing activities |  | $ | (144 | ) |  | $ | (165 | ) |  | $ | (195 | ) |  | $ | (841 | )
Net cash used in financing activities |  | $ | (285 | ) |  | $ | (31 | ) |  | $ | (604 | ) |  | $ | (171 | )

_________

(1) | Adjustment excludes $(18) million and $20 million in amortization of acquired derivatives contracts for the three months ended September 30, 2017 and 2016, respectively, and $(28) million and $65 million in amortization of acquired derivatives contracts for the nine months ended September 30, 2017 and 2016, respectively.

(2) | Other adjustments primarily represent miscellaneous items excluded from Adjusted Free Cash Flow that are included in cash flow from operations.

(3) | Adjusted Free Cash Flow is shown net of the following items for the three and nine months ended September 30, 2017 and 2016 (in millions):

|  | Three Months Ended September 30, |  | Nine Months Ended September 30,
|  | 2017 |  | 2016 |  | 2017 |  | 2016
Cash interest, net |  | $ | 156 |  |  | $ | 160 |  |  | $ | 467 |  |  | $ | 477 |
Operating lease payments |  | $ | 6 |  |  | $ | 6 |  |  | $ | 19 |  |  | $ | 19 |

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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 September 30, 2017 and December 31, 2016 (in millions):

| September 30, 2017 |  | December 31, 2016
Cash and cash equivalents, corporate(1) | $ | 346 |  |  | $ | 345 |
Cash and cash equivalents, non-corporate | 80 |  |  | 73 |
Total cash and cash equivalents | 426 |  |  | 418 |
Restricted cash | 222 |  |  | 188 |
Corporate Revolving Facility availability(2) | 1,316 |  |  | 1,255 |
CDHI letter of credit facility availability | 54 |  |  | 50 |
Total current liquidity availability(3) | $ | 2,018 |  |  | $ | 1,911 |

____________

(1) | Includes $19 million and $16 million of margin deposits posted with us by our counterparties at September 30, 2017 and December 31, 2016, respectively. See Note 7 of the Notes to Consolidated Condensed Financial Statements for further information related to our collateral.

(2) | Our ability to use availability under our Corporate Revolving Facility is unrestricted.

(3) | Our ability to use corporate cash and cash equivalents is unrestricted. 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. Our $300 million CDHI letter of credit facility is restricted to support certain obligations under PPAs and power transmission and natural gas transportation agreements.

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.
We have never paid cash dividends on our common stock. 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, 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. Utilizing our portfolio of transactions subject to collateral exposure, we estimate that as of September 30, 2017, an increase of $1/MMBtu in natural gas prices would result in a decrease of collateral required by
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approximately $117 million. If natural gas prices decreased by $1/MMBtu, we estimate that our collateral requirements would increase by approximately $124 million. Changes in Market Heat Rates also affect our liquidity. For example, as demand increases, less efficient generation is dispatched, which increases the Market Heat Rate and results in increased collateral requirements. Historical relationships of natural gas and Market Heat Rate movements for our portfolio of assets have been volatile over time and are influenced by the absolute price of natural gas and the regional characteristics of each power market. We estimate that at September 30, 2017, an increase of 500 Btu/KWh in the Market Heat Rate would result in an increase in collateral required by approximately $1 million. If Market Heat Rates were to fall at a similar rate, we estimate that our collateral required would decrease by approximately $1 million. These amounts are 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 2017 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 September 30, 2017 and December 31, 2016 (in millions):

| September 30, 2017 |  | December 31, 2016
Corporate Revolving Facility(1) | $ | 474 |  |  | $ | 535 |
CDHI | 246 |  |  | 250 |
Various project financing facilities | 230 |  |  | 206 |
Total | $ | 950 |  |  | $ | 991 |

____________

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

Disciplined Capital Allocation
In connection with our goal of disciplined capital allocation, we have completed the following key capital management transactions during 2017, as further described below.
Redemption of 2023 First Lien Notes
As part of our stated goal to reduce debt and interest expense, on March 6, 2017, we redeemed the remaining $453 million of our outstanding 2023 First Lien Notes using cash on hand along with the proceeds from the 2019 First Lien Term Loan which
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contains a substantially lower variable rate of LIBOR plus 1.75% per annum. We intend to repay the 2019 First Lien Term Loan in full by the end of 2018. This accelerates debt reduction and results in substantial annual interest savings of more than $20 million.
2017 First Lien Term Loan
We repaid approximately $475 million in borrowings under our 2017 First Lien Term Loan using cash on hand during 2017.
Optimizing our Portfolio
Our goal is to take advantage of favorable opportunities to continue to design, develop, acquire, construct and operate the next generation of highly efficient, operationally flexible and environmentally responsible power plants where such investment meets our rigorous financial hurdles, particularly if power contracts and financing are available and attractive returns are expected. Likewise, we actively seek to divest non-core assets where we can find opportunities to do so accretively. Our significant ongoing projects under construction, growth initiatives and strategic asset sales are as follows:

• | York 2 Energy Center is an 828 MW dual-fuel, combined-cycle project which is currently under construction and is co-located with our York Energy Center in Peach Bottom Township, Pennsylvania. The targeted construction completion date has been delayed from the second quarter of 2017 and the construction contractor has indicated it will be completed during the third quarter of 2018. Further, we are in discussions with the contractor on commercial issues including a request by the contractor for equitable adjustment related to construction delay and costs. We are continuing to work with the contractor to look for opportunities for schedule recovery and to advance the work.

• | Washington Parish Energy Center is an approximately 360 MW natural gas-fired, peaking power plant on a partially developed site that we own near Bogalusa, LA that will be sold to a third party for a fixed payment, including fair market return, after construction is completed.

• | Osprey Energy Center was sold for approximately $166 million, excluding working capital and other adjustments, on January 3, 2017.

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, 2016, our consolidated federal NOLs totaled approximately $6.7 billion. Under federal and state income tax law, our NOL carryforwards can be utilized to reduce future taxable income subject to certain new limitations including if we were to undergo an ownership change as defined by Section 382 of the Internal Revenue Code and similar state provisions.
Cash Flow Activities
The following table summarizes our cash flow activities for the nine months ended September 30, 2017 and 2016 (in millions):

| 2017 |  | 2016
Beginning cash and cash equivalents | $ | 418 |  |  | $ | 906 |
Net cash provided by (used in): |  |  |
Operating activities | 807 |  |  | 667 |
Investing activities | (195 | ) |  | (841 | )
Financing activities | (604 | ) |  | (171 | )
Net increase (decrease) in cash and cash equivalents | 8 |  |  | (345 | )
Ending cash and cash equivalents | $ | 426 |  |  | $ | 561 |

Net Cash Provided By Operating Activities
Cash provided by operating activities for the nine months ended September 30, 2017, was $807 million compared to $667 million for the nine months ended September 30, 2016. The increase was primarily due to the following:

• | Income from operations — Income from operations, adjusted for non-cash items, decreased by $66 million for the nine months ended September 30, 2017, compared to the same period in 2016. Non-cash items consist primarily of depreciation and amortization, income from unconsolidated investments in subsidiaries, gain on sale of assets and

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mark-to-market activity. The decrease in income from operations was primarily driven by increases in plant operating expense of $71 million and increase in sales, general and administrative expenses of $11 million during the period primarily driven by the acquisition of the Calpine Solutions and North American Power retail subsidiaries during December 2016 and January 2017, respectively, as well as an increase in other operating expense of $8 million offset by a $24 million increase in Commodity revenue, net of Commodity expense, excluding non-cash amortization. See “Results of Operations for the Nine Months ended September 30, 2017 and 2016” above for further discussion of these changes.

• | Working capital employed — Working capital employed decreased by $208 million for the nine months ended September 30, 2017, compared to the same period in 2016, after adjusting for changes in debt, restricted cash and mark-to-market related balances which did not affect cash provided by operating activities. The decrease was primarily due to the change in net margining requirements associated with our commodity hedging activity primarily related to Calpine Solutions which was acquired in December 2016 and a decrease in accounts receivable, net of accounts payable, resulting from timing of payments made during the periods.

Net Cash Used In Investing Activities
Cash used in investing activities for the nine months ended September 30, 2017, was $195 million compared to $841 million for the nine months ended September 30, 2016. The decrease was primarily due to the following:

• | Acquisitions and Divestitures — During the nine months ended September 30, 2017, we acquired North American Power for a net purchase price of $111 million and sold Osprey Energy Center receiving net proceeds of $162 million. During the nine months ended September 30, 2016, we acquired Granite Ridge Energy Center for a net purchase price of $526 million.

• | Capital expenditures — Capital expenditures for the nine months ended September 30, 2017 were $248 million, a decrease of $89 million compared to expenditures of $337 million for the nine months ended September 30, 2016. The decrease was primarily due to lower expenditures on construction projects during the nine months ended September 30, 2017 as compared to the same period in 2016.

Net Cash Used In Financing Activities
Cash used in financing activities for the nine months ended September 30, 2017, was $604 million compared to $171 million for the nine months ended September 30, 2016. The increase was primarily due to the following:

• | First Lien Term Loans and First Lien Notes — During the nine months ended September 30, 2017, we received proceeds of $396 million from the issuance of the 2019 First Lien Term Loan which was used, together with cash on hand, to redeem the remaining $453 million of the 2023 First Lien Notes. In addition, during the nine months ended September 30, 2017, we utilized cash on hand to repay $400 million of our outstanding 2017 First Lien Term Loan. During the nine months ended September 30, 2016, we utilized proceeds from the issuance of the New 2023 First Lien Term Loan and the 2026 First Lien Notes to repay the 2019 and 2020 First Lien Term Loans of $1.2 billion.

• | Financing costs — During the nine months ended September 30, 2017, we incurred finance costs of $9 million due to issuance of the 2019 First Lien Term Loan. During the nine months ended September 30, 2016, we incurred finance costs of $27 million due to the issuances of our 2026 First Lien Notes and a portion of our 2023 First Lien Term Loans and amending the Corporate Revolving Facility.

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 2016 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 2 and 5 of the Notes to Consolidated Financial Statements in our 2016 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, Otay Mesa Energy Center, LLC and Calpine Receivables.
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RISK MANAGEMENT AND COMMODITY ACCOUNTING
Our commercial hedging and optimization strategies are designed to maximize our risk-adjusted Commodity Margin by leveraging our knowledge, experience and fundamental views on natural gas and power. 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 affiliates, 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 subsidiaries also provide us with a hedging outlet for our wholesale power plant portfolio.
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 2017 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 to the extent they are effective with gains and losses reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. See Note 6 of the Notes to Consolidated Condensed Financial Statements for further discussion of our derivative instruments.
During the third quarter of 2017, we elected to begin offsetting 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 cash collateral in support of our derivative instruments which may also be subject to a master netting arrangement with the same counterparty. See Note 1 for a further description of the change in accounting principle associated with our election to offset fair value amounts associated with 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 decreased to approximately $490 million at September 30, 2017, when compared to approximately $521 million at December 31, 2016, and our derivative liabilities have decreased to approximately $216 million at September 30, 2017, when compared to approximately $287 million at December 31, 2016. The fair value of our level 3 derivative assets and liabilities at September 30, 2017 represents approximately 47% and 13% of our total assets and liabilities measured at fair value, respectively, with the majority of that value attributable to the fair value of retail sales contracts acquired in the acquisition of Calpine Solutions in December 2016. See Note 5 of the Notes to Consolidated Condensed Financial Statements for further information related to our level 3 derivative assets and liabilities.
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The change in fair value of our outstanding commodity and interest rate hedging instruments from January 1, 2017, through September 30, 2017, is summarized in the table below (in millions):

| Commodity Instruments |  | Interest Rate Hedging Instruments |  | Total
Fair value of contracts outstanding at January 1, 2017 | $ | 263 |  |  | $ | (29 | ) |  | $ | 234 |
Items recognized or otherwise settled during the period(1)(2) | (114 | ) |  | 20 |  |  | (94 | )
Fair value attributable to new contracts(3) | 151 |  |  | (3 | ) |  | 148 |
Changes in fair value attributable to price movements | 6 |  |  | (20 | ) |  | (14 | )
Fair value of contracts outstanding at September 30, 2017(4) | $ | 306 |  |  | $ | (32 | ) |  | $ | 274 |

__________

(1) | Commodity contract settlements consist of the realization of previously recognized gains on contracts not designated as hedging instruments of $87 million (represents a portion of Commodity revenue and Commodity expense as reported on our Consolidated Condensed Statements of Operations) and $27 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 $19 million related to realized losses from settlements of designated cash flow hedges and $1 million related to realized losses 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 $21 million and $18 million of fair value related to commodity contracts and interest rate hedging instruments, respectively, which are not reflected in OCI or earnings.

(4) | Net commodity and interest rate derivative assets and liabilities reported in Notes 5 and 6 of the Notes to Consolidated Condensed Financial Statements.

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 September 30, 2017, based on price source and the period during which the instruments will mature, are summarized in the table below (in millions):

Fair Value Source |  | 2017 |  | 2018-2019 |  | 2020-2021 |  | After 2021 |  | Total
Prices actively quoted |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Prices provided by other external sources |  | (6 | ) |  | 34 |  |  | 10 |  |  | — |  |  | 38 |
Prices based on models and other valuation methods |  | 41 |  |  | 166 |  |  | 48 |  |  | 13 |  |  | 268 |
Total fair value |  | $ | 35 |  |  | $ | 200 |  |  | $ | 58 |  |  | $ | 13 |  |  | $ | 306 |

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.
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The table below presents the high, low and average of our daily VAR for the three and nine months ended September 30, 2017 and 2016 (in millions):

| 2017 |  | 2016
Three months ended September 30: |  |  |
High | $ | 29 |  |  | $ | 39 |
Low | $ | 17 |  |  | $ | 15 |
Average | $ | 22 |  |  | $ | 27 |
Nine months ended September 30: |  |  |
High | $ | 29 |  |  | $ | 39 |
Low | $ | 16 |  |  | $ | 14 |
Average | $ | 20 |  |  | $ | 24 |
As of September 30 | $ | 22 |  |  | $ | 18 |

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. While the number of counterparties in these markets has decreased, to date this occurrence has not had a material adverse effect on our results of operations or financial condition. However, should these conditions persist or increase, it could decrease our ability to hedge our forward commodity price risk and create incremental volatility in our earnings. The effects of declining liquidity in the forward commodity markets is also mitigated by our retail subsidiaries which provides us with an additional outlet to transact hedging activities related to our wholesale power plant portfolio.
Liquidity Risk — Liquidity risk arises from the general funding requirements needed to manage our activities and assets and liabilities. Fluctuating natural gas prices or Market Heat Rates can cause our collateral requirements for our wholesale and retail activities to increase or decrease. Our liquidity management framework is intended to maximize liquidity access and minimize funding costs during times of rising prices. See further discussion regarding our uses of collateral as they relate to our commodity procurement and risk management activities in Note 7 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.

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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. 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 September 30, 2017, 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 September 30, 2017) |  | 2017 |  | 2018-2019 |  | 2020-2021 |  | After 2021 |  | Total
Investment grade |  | $ | 10 |  |  | $ | 92 |  |  | $ | 33 |  |  | $ | 7 |  |  | $ | 142 |
Non-investment grade |  | (9 | ) |  | (9 | ) |  | (7 | ) |  | (2 | ) |  | (27 | )
No external ratings(1) |  | 34 |  |  | 117 |  |  | 32 |  |  | 8 |  |  | 191 |
Total fair value |  | $ | 35 |  |  | $ | 200 |  |  | $ | 58 |  |  | $ | 13 |  |  | $ | 306 |

__________

(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 $(19) million at September 30, 2017.
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 2016 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 third quarter of 2017, 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.
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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

Various risk factors could have a negative effect on our business, financial position, cash flows and results of operations. These include the following risk factors, in addition to the risk factors previously disclosed in Part I, Item 1A “Risk Factors” of our 2016 Form 10-K:
Failure to complete the Merger, or to complete the Merger timely, as a result of the failure to obtain necessary regulatory approvals or to satisfy certain closing conditions, could negatively affect our business and the market price of Calpine Corporation’s common stock.
The proposed Merger is subject to various closing conditions such as the approval of our stockholders, as well as certain regulatory approvals in the United States, among other customary closing conditions. It is possible that our stockholders will not approve the Merger or that a government entity may prohibit, delay or refuse to grant approval for the consummation of the Merger. If any condition to the closing of the Merger is not satisfied or, if permissible, waived, the Merger will not be completed. In addition, satisfying the conditions to the closing of the Merger may take longer than we expect. There can be no assurance that any of the conditions to closing will be satisfied or waived or that other events will not intervene to delay or result in the failure to consummate the Merger.
If the Merger is not completed for any reason, our stockholders would not receive any payment for their shares in connection with the Merger while we will remain an independent public company, and our shares will continue to be traded on the NYSE. Depending on the circumstances that would have caused the Merger not to be completed, the price of our common stock may decline materially. If that were to occur, it is uncertain when, if ever, the price of the shares would return to the price levels at which the shares currently trade. In addition, any delay in closing or a failure to close the Merger could exacerbate any negative effect on our business and on our relationships with other parties with which we maintain business relationships, as well as negatively affect our ability to implement alternative business plans. Finally, if the Merger is not completed, our Board of Directors will continue to evaluate and review our business operations, properties and capitalization, among other things, make such changes as it deems appropriate and continue to seek to identify opportunities to enhance stockholder value. However, there can be no assurance that any other transaction acceptable to Calpine will be available or that our business, prospects or results of operation will not be materially adversely affected.
Failure to complete the Merger could trigger the payment of a termination fee and, whether or not the Merger is consummated, we have incurred and will continue to incur significant costs, fees and expenses relating to professional services and transaction fees.
If the Merger is not completed for any reason, we may be required to pay a termination fee. The Merger Agreement contains certain termination rights in favor of the Company and Volt Parent, including the right of the Company to terminate the Merger Agreement to accept a superior proposal, subject to specified limitations, and provides that, upon termination of the Merger Agreement by us or Volt Parent upon specified conditions, we will be required to pay Volt Parent a termination fee of up to $142 million. There can be no assurance that approval of our stockholders will be obtained or that the Merger Agreement will not otherwise be terminated under the circumstances triggering these obligations. Furthermore, whether or not the Merger is consummated, we have incurred and will continue to incur significant costs, fees and expenses relating to professional services and transaction fees in connection with the proposed Merger. Payment of these fees and costs could materially adversely affect our business, financial condition and results of operations.
Uncertainties associated with the Merger may cause us to lose key customers or suppliers and make it more difficult to retain and hire key personnel.
As a result of the uncertainty surrounding the conduct of our business during the pendency of the Merger, we may lose key customers and suppliers and our relationships with other parties with which we maintain business relationships may be materially adversely affected. Parties with which we maintain business relationships may experience uncertainty about our future and seek alternative relationships with third parties, seek to alter their business relationships with us or fail to extend an existing relationship with us. In addition, our employees, including key personnel, may be uncertain about their future roles and relationships with us following the completion of the Merger, which may adversely affect our ability to retain them or to hire new employees.
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Restrictions imposed on us pursuant to the Merger Agreement may prevent us from pursuing business opportunities, which could have a material adverse effect on our business, financial condition and results of operations.
The Merger Agreement restricts us from taking certain actions without Volt Parent’s consent while the Merger is pending. These restrictions may, among other matters, prevent us from pursuing otherwise attractive business opportunities, making certain investments or acquisitions, selling assets, engaging in capital expenditures in excess of certain agreed limits, incurring certain indebtedness or making certain other changes to our business pending the closing of the Merger. These restrictions could have a material adverse effect on our business, financial condition and results of operations.
State legislative and regulatory action could adversely affect our competitive position and business.
Certain states have taken or are considering taking anticompetitive actions by subsidizing or otherwise providing economic support to existing, uneconomic power plants in a manner that could have an adverse effect on the deregulated power markets. In addition, certain states in which we have retail operations are taking actions which we believe limit customer choice as well as other actions that we believe are anticompetitive and could negatively affect our retail operations. We are actively participating in many of the legislative, regulatory and judicial processes challenging these actions at the state and federal levels. If these anticompetitive actions are ultimately upheld and implemented, they could adversely affect capacity and energy prices in the deregulated electricity markets or impede our ability to maintain or expand our retail operations which in turn could have a material adverse effect on our business prospects and financial results.
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Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds

Repurchase of Equity Securities

Period |  | (a) Total Number of Shares Purchased(1) |  | (b) Average Price Paid Per Share |  | (c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(2) |  | (d) Maximum Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs (in millions)(2)
July |  | 2,349 |  |  | $ | 13.93 |  |  | — |  |  | $ | 307 |
August |  | 2,823 |  |  | $ | 14.27 |  |  | — |  |  | $ | 307 |
September |  | 2,946 |  |  | $ | 14.71 |  |  | — |  |  | $ | 307 |
Total |  | 8,118 |  |  | $ | 14.33 |  |  | — |  |  | $ | 307 |

___________

(1) | Represents shares withheld by us to satisfy tax withholding obligations associated with the vesting of restricted stock awarded to employees during the third quarter of 2017.

(2) | In November 2014, our Board of Directors authorized an increase in the total authorization of our multi-year share repurchase program to $1.0 billion. There is no expiration date on the repurchase authorization and the amount and timing of future share repurchases, if any, will be determined as market and business conditions warrant.

Item 3. | Defaults Upon Senior Securities

None.

Item 4. | Mine Safety Disclosures

Not applicable.

Item 5. | Other Information

None.
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Item 6. | Exhibits

EXHIBIT INDEX

Exhibit Number |  | Description
2.1 |  | Agreement and Plan of Merger, dated as of August 17, 2017, by and among Calpine Corporation, Volt Parent, LP and Volt Merger Sub, Inc. (incorporated by reference to Exhibit 2.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on August 22, 2017).
10.1 |  | Amendment No. 5 to the Credit Agreement, dated as of September 15, 2017, among Calpine Corporation, as borrower, the guarantors party thereto, The Bank of Tokyo-Mitsubishi UFJ 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 Calpine’s Current Report on Form 8-K, filed with the SEC on September 20, 2017).
18.1 |  | Letter of preferability regarding change in accounting principle from PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.
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.

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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: October 31, 2017
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