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 March 31, 2019
 
 
 
 
Or
 
 
 
[    ]
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
 
 
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File No. 001-12079
______________________
image0a08.jpg
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 [ ]    No [X]
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes [X]    No [    ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
[   ]
 
Accelerated filer            
[    ]
Non-accelerated filer
[X]
 
Smaller reporting company 
[    ]
Emerging growth company
[   ]
 
 
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes [    ]    No [X]

Securities registered pursuant to Section 12(b) of the Act: None
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: 105.2 shares of common stock, par value $0.001, were outstanding as of May 10, 2019, none of which were publicly traded.
 




CALPINE CORPORATION AND SUBSIDIARIES
REPORT ON FORM 10-Q
For the Quarter Ended March 31, 2019
INDEX
 
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

i


DEFINITIONS
As used in this report for the quarter ended March 31, 2019 (this “Report”), the following abbreviations and terms have the meanings as listed below. Additionally, the terms “Calpine,” “we,” “us” and “our” refer to Calpine Corporation and its consolidated subsidiaries, unless the context clearly indicates otherwise. The term “Calpine Corporation” refers only to Calpine Corporation and not to any of its subsidiaries. Unless and as otherwise stated, any references in this Report to any agreement means such agreement and all schedules, exhibits and attachments in each case as amended, restated, supplemented or otherwise modified to the date of filing this Report.
ABBREVIATION
 
DEFINITION
 
 
 
2018 Form 10-K
 
Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2018, filed with the SEC on March 28, 2019
 
 
 
2019 First Lien Term Loan
 
The $400 million first lien senior secured term loan, dated February 3, 2017, among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent and MUFG Union Bank, N.A., as collateral agent, repaid on April 5, 2019
 
 
 
2022 First Lien Notes
 
The $750 million aggregate principal amount of 6.0% senior secured notes due 2022, issued October 31, 2013
 
 
 
2023 First Lien Term Loans
 
The $550 million first lien senior secured term loan, dated December 15, 2015, among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent, repaid on April 5, 2019, and the $562 million first lien senior secured term loan, dated May 31, 2016, among Calpine Corporation, as borrower, the lenders party thereto, Citibank, N.A., as administrative agent and MUFG Union Bank, N.A., as collateral agent
 
 
 
2023 Senior Unsecured Notes
 
The $1.25 billion aggregate principal amount of 5.375% senior unsecured notes due 2023, issued July 22, 2014
 
 
 
2024 First Lien Notes
 
The $490 million aggregate principal amount of 5.875% senior secured notes due 2024, issued October 31, 2013
 
 
 
2024 First Lien Term Loan
 
The $1.6 billion first lien senior secured term loan, dated May 28, 2015 (as amended December 21, 2016), among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent
 
 
 
2024 Senior Unsecured Notes
 
The $650 million aggregate principal amount of 5.5% senior unsecured notes due 2024, issued February 3, 2015
 
 
 
2025 Senior Unsecured Notes
 
The $1.55 billion aggregate principal amount of 5.75% senior unsecured notes due 2025, issued July 22, 2014
 
 
 
2026 First Lien Notes
 
Collectively, the $625 million aggregate principal amount of 5.25% senior secured notes due 2026, issued May 31, 2016, and the $560 million aggregate principal amount of 5.25% senior secured notes due 2026, issued on December 15, 2017
 
 
 
2026 First Lien Term Loan
 
The $950 million first lien senior secured term loan, dated April 5, 2019, among Calpine Corporation, as borrower, the lenders party thereto, Morgan Stanley Senior Funding, Inc., as administrative agent and MUFG Union Bank, N.A., as collateral agent
 
 
 
Accounts Receivable Sales Program
 
Receivables purchase agreement between Calpine Solutions and Calpine Receivables and the purchase and sale agreement between Calpine Receivables and an unaffiliated financial institution, both which allows for the revolving sale of up to $250 million in certain trade accounts receivables to third parties
 
 
 
AOCI
 
Accumulated Other Comprehensive Income
 
 
 
Average availability
 
Represents the total hours during the period that our plants were in-service or available for service as a percentage of the total hours in the period

ii


ABBREVIATION
 
DEFINITION
 
 
 
Average capacity factor, excluding peakers
 
A measure of total actual power generation as a percent of total potential power generation. It is calculated by dividing (a) total MWh generated by our power plants, excluding peakers, by (b) the product of multiplying (i) the average total MW in operation, excluding peakers, during the period by (ii) the total hours in the period
 
 
 
Btu
 
British thermal unit(s), a measure of heat content
 
 
 
Calpine Receivables
 
Calpine Receivables, LLC, an indirect, wholly-owned subsidiary of Calpine, which was established as bankruptcy remote, special purpose subsidiary and is responsible for administering the Accounts Receivable Sales Program
 
 
 
Calpine Solutions
 
Calpine Energy Solutions, LLC, an indirect, wholly-owned subsidiary of Calpine, which is a supplier of power to commercial and industrial retail customers in the United States with customers in 20 states, including presence in California, Texas, the Mid-Atlantic and the Northeast
 
 
 
CCFC
 
Calpine Construction Finance Company, L.P., an indirect, wholly-owned subsidiary of Calpine
 
 
 
CCFC Term Loan
 
The $1.0 billion first lien senior secured term loan entered into on December 15, 2017 among CCFC as borrower, the lenders party thereto, and Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent
 
 
 
CDHI
 
Calpine Development Holdings, Inc., an indirect, wholly-owned subsidiary of Calpine
 
 
 
Champion Energy
 
Champion Energy Marketing, LLC, which owns a retail electric provider that serves residential, governmental, commercial and industrial customers in deregulated electricity markets in 14 states and the District of Columbia, including presence in California, Texas, the Mid-Atlantic and Northeast
 
 
 
Cogeneration
 
Using a portion or all of the steam generated in the power generating process to supply a customer with steam for use in the customer’s operations
 
 
 
Commodity expense
 
The sum of our expenses from fuel and purchased energy expense, commodity transmission and transportation expense, environmental compliance expenses, ancillary retail expense and realized settlements from our marketing, hedging and optimization activities including natural gas and fuel oil transactions hedging future power sales
 
 
 
Commodity Margin
 
Measure of profit reviewed by our chief operating decision maker that includes revenue recognized on our wholesale and retail power sales activity, electric capacity sales, REC sales, steam sales, realized settlements associated with our marketing, hedging, optimization and trading activities, fuel and purchased energy expenses, commodity transmission and transportation expenses, environmental compliance expenses and ancillary retail expense. Commodity Margin is a measure of segment profit or loss under FASB Accounting Standards Codification 280 used by our chief operating decision maker to make decisions about allocating resources to the relevant segments and assessing their performance
 
 
 
Commodity revenue
 
The sum of our revenues recognized on our wholesale and retail power sales activity, electric capacity sales, REC sales, steam sales and realized settlements from our marketing, hedging, optimization and trading activities
 
 
 
Company
 
Calpine Corporation, a Delaware corporation, and its subsidiaries
 
 
 
Corporate Revolving Facility
 
The approximately $2.02 billion aggregate amount revolving credit facility credit agreement, dated as of December 10, 2010, as amended on June 27, 2013, July 30, 2014, February 8, 2016, December 1, 2016, September 15, 2017, October 20, 2017, March 8, 2018, May 18, 2018 and April 5, 2019 among Calpine Corporation, the Bank of Tokyo-Mitsubishi UFJ, Ltd., as successor administrative agent, MUFG Union Bank, N.A., as successor collateral agent, the lenders party thereto and the other parties thereto
 
 
 
CPN Management
 
CPN Management, LP, which owns 100% of the common stock of Calpine Corporation
 
 
 
Exchange Act
 
U.S. Securities Exchange Act of 1934, as amended

iii


ABBREVIATION
 
DEFINITION
 
 
 
FASB
 
Financial Accounting Standards Board
 
 
 
FERC
 
U.S. Federal Energy Regulatory Commission
 
 
 
First Lien Notes
 
Collectively, the 2022 First Lien Notes, the 2024 First Lien Notes and the 2026 First Lien Notes
 
 
 
First Lien Term Loans
 
Collectively, the 2019 First Lien Term Loan, the 2023 First Lien Term Loans, the 2024 First Lien Term Loan and the 2026 First Lien Term Loan
 
 
 
Greenfield LP
 
Greenfield Energy Centre LP, a 50% partnership interest between certain of our subsidiaries and a third party which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant in Ontario, Canada
 
 
 
Heat Rate(s)
 
A measure of the amount of fuel required to produce a unit of power
 
 
 
IRS
 
U.S. Internal Revenue Service
 
 
 
ISO(s)
 
Independent System Operator which is an entity that coordinates, controls and monitors the operation of an electric power system
 
 
 
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
 
 
 
Lyondell
 
LyondellBasell Industries N.V.
 
 
 
Market Heat Rate(s)
 
The regional power price divided by the corresponding regional natural gas price
 
 
 
Merger
 
Merger of Volt Merger Sub, Inc. with and into Calpine pursuant to the terms of the Merger Agreement, which was consummated on March 8, 2018
 
 
 
Merger Agreement
 
Agreement and Plan of Merger, dated, August 17, 2017, by and among Calpine Corporation, Volt Parent, LP and Volt Merger Sub, Inc.
 
 
 
MMBtu
 
Million Btu
 
 
 
MW
 
Megawatt(s), a measure of plant capacity
 
 
 
MWh
 
Megawatt hour(s), a measure of power produced, purchased or sold
 
 
 
NOL(s)
 
Net operating loss(es)
 
 
 
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 retail energy supplier for homes and small businesses primarily concentrated in the Northeast U.S.
 
 
 
OCI
 
Other Comprehensive Income
 
 
 
OMEC
 
Otay Mesa Energy Center, LLC, an indirect, wholly owned subsidiary that owns the Otay Mesa Energy Center, a 608 MW power plant located in San Diego County, California
 
 
 
OTC
 
Over-the-Counter
 
 
 
PJM
 
PJM Interconnection is a RTO that coordinates the movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia
 
 
 

iv


ABBREVIATION
 
DEFINITION
PPA(s)
 
Any term power purchase agreement or other contract for a physically settled sale (as distinguished from a financially settled future, option or other derivative or hedge transaction) of any power product, including power, capacity and/or ancillary services, in the form of a bilateral agreement or a written or oral confirmation of a transaction between two parties to a master agreement, including sales related to a tolling transaction in which the purchaser provides the fuel required by us to generate such power and we receive a variable payment to convert the fuel into power and steam
 
 
 
REC(s)
 
Renewable energy credit(s)
 
 
 
Risk Management Policy
 
Calpine’s policy applicable to all employees, contractors, representatives and agents, which defines the risk management framework and corporate governance structure for commodity risk, interest rate risk, currency risk and other risks
 
 
 
RTO(s)
 
Regional Transmission Organization which is an entity that coordinates, controls and monitors the operation of an electric power system and administers the transmission grid on a regional basis
 
 
 
SDG&E
 
San Diego Gas & Electric Company
 
 
 
SEC
 
U.S. Securities and Exchange Commission
 
 
 
Securities Act
 
U.S. Securities Act of 1933, as amended
 
 
 
Senior Unsecured Notes
 
Collectively, the 2023 Senior Unsecured Notes, the 2024 Senior Unsecured Notes and the 2025 Senior Unsecured Notes
 
 
 
Spark Spread(s)
 
The difference between the sales price of power per MWh and the cost of natural gas to produce it
 
 
 
Steam Adjusted Heat Rate
 
The adjusted Heat Rate for our natural gas-fired power plants, excluding peakers, calculated by dividing (a) the fuel consumed in Btu reduced by the net equivalent Btu in steam exported to a third party by (b) the KWh generated. Steam Adjusted Heat Rate is a measure of fuel efficiency, so the lower our Steam Adjusted Heat Rate, the lower our cost of generation
 
 
 
U.S. GAAP
 
Generally accepted accounting principles in the U.S.
 
 
 
VAR
 
Value-at-risk
 
 
 
VIE(s)
 
Variable interest entity(ies)
 
 
 
Whitby
 
Whitby Cogeneration Limited Partnership, a 50% partnership interest between certain of our subsidiaries and a third party, which operates Whitby, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada

v


Forward-Looking Statements

This Report contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this Report, including without limitation, the “Management’s Discussion and Analysis” section. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will,” “should,” “estimate,” “potential,” “project” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. We believe that the forward-looking statements are based upon reasonable assumptions and expectations. However, you are cautioned that any such forward-looking statements are not guarantees of future performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to:
•
Financial results that may be volatile and may not reflect historical trends due to, among other things, seasonality of demand, fluctuations in prices for commodities such as natural gas and power, changes in U.S. macroeconomic conditions, fluctuations in liquidity and volatility in the energy commodities markets and our ability and extent to which we hedge risks;
•
Laws, regulations and market rules in the wholesale and retail markets in which we participate and our ability to effectively respond to changes in laws, regulations or market rules or the interpretation thereof including those related to the environment, derivative transactions and market design in the regions in which we operate;
•
Our ability to manage our liquidity needs, access the capital markets when necessary and comply with covenants under our Senior Unsecured Notes, First Lien Notes, First Lien Term Loans, Corporate Revolving Facility, CCFC Term Loan and other existing financing obligations;
•
Risks associated with the operation, construction and development of power plants, including unscheduled outages or delays and plant efficiencies;
•
Risks related to our geothermal resources, including the adequacy of our steam reserves, unusual or unexpected steam field well and pipeline maintenance requirements, variables associated with the injection of water to the steam reservoir and potential regulations or other requirements related to seismicity concerns that may delay or increase the cost of developing or operating geothermal resources;
•
Extensive competition in our wholesale and retail businesses, including from renewable sources of power, interference by states in competitive power markets through subsidies or similar support for new or existing power plants, lower prices and other incentives offered by retail competitors, and other risks associated with marketing and selling power in the evolving energy markets;
•
Structural changes in the supply and demand of power, resulting from the development of new fuels or technologies and demand-side management tools (such as distributed generation, power storage and other technologies);
•
The expiration or early termination of our PPAs and the related results on revenues;
•
Future capacity revenue may not occur at expected levels;
•
Natural disasters, such as hurricanes, earthquakes, droughts, wildfires and floods, acts of terrorism or cyber attacks that may affect our power plants or the markets our power plants or retail operations serve and our corporate offices;
•
Disruptions in or limitations on the transportation of natural gas or fuel oil and the transmission of power;
•
Our ability to manage our counterparty and customer exposure and credit risk, including our commodity positions or if a significant customer were to seek bankruptcy protection under Chapter 11;
•
Our ability to attract, motivate and retain key employees;
•
Present and possible future claims, litigation and enforcement actions that may arise from noncompliance with market rules promulgated by the SEC, Commodity Futures Trading Commission, FERC and other regulatory bodies; and
•
Other risks identified in this Report, in our 2018 Form 10-K and in other reports filed by us with the SEC.

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

vi


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

vii


PART I — FINANCIAL INFORMATION
Item 1.
Financial Statements

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
(Unaudited)
 
 
Three Months Ended March 31,
 
 
2019
 
2018
 
(in millions)
Operating revenues:
 
 
 
 
Commodity revenue
 
$
2,538

 
$
2,396

Mark-to-market gain (loss)
 
56

 
(391
)
Other revenue
 
5

 
4

Operating revenues

2,599

 
2,009

Operating expenses:
 
 
 
 
Fuel and purchased energy expense:
 
 
 
 
Commodity expense
 
1,758

 
1,790

Mark-to-market (gain) loss
 
10

 
(20
)
Fuel and purchased energy expense

1,768

 
1,770

Operating and maintenance expense
 
239

 
275

Depreciation and amortization expense
 
174

 
201

General and other administrative expense
 
32

 
60

Other operating expenses
 
34

 
37

Total operating expenses

2,247

 
2,343

(Income) from unconsolidated subsidiaries
 
(6
)
 
(6
)
Income (loss) from operations

358

 
(328
)
Interest expense
 
149

 
151

Gain on extinguishment of debt
 
(4
)
 
—

Other (income) expense, net
 
23

 
7

Income (loss) before income taxes

190

 
(486
)
Income tax expense
 
10

 
108

Net income (loss)

180

 
(594
)
Net income attributable to the noncontrolling interest
 
(5
)
 
(4
)
Net income (loss) attributable to Calpine

$
175

 
$
(598
)

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 March 31,
 
 
2019
 
2018
 
(in millions)
Net income (loss)
 
$
180

 
$
(594
)
Cash flow hedging activities:
 
 
 
 
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income (loss)
 
(23
)
 
48

Reclassification adjustment for (gain) loss on cash flow hedges realized in net income (loss)
 
(2
)
 
7

Foreign currency translation gain (loss)
 
2

 
(6
)
Income tax expense
 
—

 
(11
)
Other comprehensive income (loss)
 
(23
)
 
38

Comprehensive income (loss)
 
157

 
(556
)
Comprehensive (income) attributable to the noncontrolling interest
 
(5
)
 
(6
)
Comprehensive income (loss) attributable to Calpine
 
$
152


$
(562
)

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


2


CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited)
 
 
March 31,
 
December 31,
 
 
2019
 
2018
 
 
(in millions, except share and per share amounts)
ASSETS
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents ($35 and $43 attributable to VIEs)
 
$
184

 
$
205

Accounts receivable, net of allowance of $6 and $9
 
794

 
1,022

Inventories
 
515

 
525

Margin deposits and other prepaid expense
 
380

 
315

Restricted cash, current ($187 and $90 attributable to VIEs)
 
265

 
167

Derivative assets, current
 
136

 
142

Current assets held for sale
 
372

 
—

Other current assets
 
51

 
43

Total current assets
 
2,697

 
2,419

Property, plant and equipment, net ($3,902 and $3,919 attributable to VIEs)
 
12,048

 
12,442

Restricted cash, net of current portion ($37 and $33 attributable to VIEs)
 
69

 
34

Investments in unconsolidated subsidiaries
 
67

 
76

Long-term derivative assets
 
165

 
160

Goodwill
 
242

 
242

Intangible assets, net
 
391

 
412

Other assets ($98 and $30 attributable to VIEs)
 
472

 
277

Total assets
 
$
16,151

 
$
16,062

LIABILITIES & STOCKHOLDER’S EQUITY
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable
 
$
720

 
$
958

Accrued interest payable
 
120

 
96

Debt, current portion ($211 and $201 attributable to VIEs)
 
258

 
637

Derivative liabilities, current
 
224

 
303

Current liabilitites held for sale
 
25

 
—

Other current liabilities ($126 and $36 attributable to VIEs)
 
518

 
489

Total current liabilities
 
1,865

 
2,483

Debt, net of current portion ($1,925 and $1,978 attributable to VIEs)
 
10,533

 
10,148

Long-term derivative liabilities
 
113

 
140

Other long-term liabilities ($74 and $36 attributable to VIEs)
 
427

 
235

Total liabilities
 
12,938

 
13,006

 
 
 
 
 
Commitments and contingencies (see Note 11)
 

 

Stockholder’s equity:
 
 
 
 
Common stock, $0.001 par value per share; authorized 5,000 shares, 105.2 shares issued and outstanding
 
—

 
—

Additional paid-in capital
 
9,584

 
9,582

Accumulated deficit
 
(6,367
)
 
(6,542
)
Accumulated other comprehensive loss
 
(100
)
 
(77
)
Total Calpine stockholder’s equity
 
3,117

 
2,963

Noncontrolling interest
 
96

 
93

Total stockholder’s equity
 
3,213

 
3,056

Total liabilities and stockholder’s equity
 
$
16,151

 
$
16,062


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

3


CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF STOCKHOLDER’S EQUITY
For the Three Months Ended March 2019 and 2018
(Unaudited)
(in millions)
 
Common
Stock
 
Treasury
Stock
 
Additional
Paid-In
Capital
 
Accumulated
Deficit
 
Accumulated
Other
Comprehensive
Loss
 
Noncontrolling
Interest
 
Total
Stockholder’s
Equity
Balance, December 31, 2018
$
—

 
$
—

 
$
9,582

 
$
(6,542
)
 
$
(77
)
 
$
93

 
$
3,056

Net income
—

 
—

 
—

 
175

 
—

 
5

 
180

Other comprehensive loss
—

 
—

 
—

 
—

 
(23
)
 
—

 
(23
)
Other
—

 
—

 
2

 
—

 
—

 
(2
)
 
—

Balance, March 31, 2019
$
—

 
$
—

 
$
9,584

 
$
(6,367
)
 
$
(100
)
 
$
96

 
$
3,213


 
Common
Stock
 
Treasury
Stock
 
Additional
Paid-In
Capital
 
Accumulated
Deficit
 
Accumulated
Other
Comprehensive
Loss
 
Noncontrolling
Interest
 
Total
Stockholder’s
Equity
Balance, December 31, 2017
$
—

 
$
(15
)
 
$
9,661

 
$
(6,552
)
 
$
(106
)
 
$
79

 
$
3,067

Treasury stock transactions
—

 
(7
)
 
—

 
—

 
—

 
—

 
(7
)
Stock-based compensation expense
—

 
—

 
41

 
—

 
—

 
—

 
41

Effects of the Merger
—

 
22

 
(100
)
 
—

 
—

 
—

 
(78
)
Dividends
—

 
—

 
(20
)
 
—

 
—

 
—

 
(20
)
Contribution from the noncontrolling interest
—

 
—

 
—

 
—

 
—

 
2

 
2

Distribution to the noncontrolling interest
—

 
—

 
—

 
—

 
—

 
(2
)
 
(2
)
Net income (loss)
—

 
—

 
—

 
(598
)
 
—

 
4

 
(594
)
Other comprehensive income
—

 
—

 
—

 
—

 
36

 
2

 
38

Balance, March 31, 2018
$
—

 
$
—

 
$
9,582

 
$
(7,150
)
 
$
(70
)
 
$
85

 
$
2,447


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


4


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

 
 
Three Months Ended March 31,
 
 
2019
 
2018
 
 
(in millions)
Cash flows from operating activities:
 
 
 
 
Net income (loss)
 
$
180

 
$
(594
)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
 

 

Depreciation and amortization(1)
 
199

 
223

Gain on extinguishment of debt
 
(4
)
 
—

Deferred income taxes
 
7

 
69

Mark-to-market activity, net
 
(45
)
 
369

(Income) from unconsolidated subsidiaries
 
(6
)
 
(6
)
Return on investments from unconsolidated subsidiaries
 
11

 
3

Stock-based compensation expense
 
—

 
57

Other
 
19

 
6

Change in operating assets and liabilities:
 

 

Accounts receivable
 
228

 
164

Accounts payable
 
(229
)
 
(77
)
Margin deposits and other prepaid expense
 
(65
)
 
(72
)
Other assets and liabilities, net
 
27

 
(107
)
Derivative instruments, net
 
(81
)
 
(150
)
Net cash provided by (used in) operating activities
 
241

 
(115
)
Cash flows from investing activities:
 
 
 
 
Purchases of property, plant and equipment
 
(143
)
 
(114
)
Other
 
(9
)
 
(1
)
Net cash used in investing activities
 
(152
)
 
(115
)
Cash flows from financing activities:
 
 
 
 
Repayment of CCFC Term Loan and First Lien Term Loans
 
(10
)
 
(10
)
Repurchases of Senior Unsecured Notes
 
(44
)
 
—

Borrowings under Corporate Revolving Facility
 
170

 
325

Repayments of Corporate Revolving Facility
 
(50
)
 
—

Repayments of project financing, notes payable and other
 
(43
)
 
(43
)
Distribution to noncontrolling interest holder
 
—

 
(2
)
Financing costs
 
—

 
(6
)
Stock repurchases
 
—

 
(79
)
Shares repurchased for tax withholding on stock-based awards
 
—

 
(7
)
Dividends paid(2)
 
—

 
(20
)
Net cash provided by financing activities
 
23

 
158

Net increase (decrease) in cash, cash equivalents and restricted cash
 
112

 
(72
)
Cash, cash equivalents and restricted cash, beginning of period
 
406

 
443

Cash, cash equivalents and restricted cash, end of period(3)
 
$
518

 
$
371


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

5


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

 
 
Three Months Ended March 31,
 
 
2019
 
2018
 
 
(in millions)
Cash paid during the period for:
 
 
 
 
Interest, net of amounts capitalized
 
$
115

 
$
110

Income taxes
 
$
—

 
$
4

 
 
 
 
 
Supplemental disclosure of non-cash investing and financing activities:
 
 
 
 
Change in capital expenditures included in account payable
 
$
13

 
$
(6
)
Plant tax settlement offset in prepaid assets
 
$
(4
)
 
$
—

Asset retirement obligation adjustment offset in operating activities
 
$
(13
)
 
$
—

Garrison Energy Center and RockGen Energy Center property, plant and equipment, net, classified as current assets held for sale
 
$
(363
)
 
$
—

Garrison Energy Center capital lease liability classified as current liabilities held for sale
 
$
22

 
$
—

____________
(1)
Includes amortization recorded in Commodity revenue and Commodity expense associated with intangible assets and amortization recorded in interest expense associated with debt issuance costs and discounts.
(2)
Subsequent to the consummation of the Merger on March 8, 2018, we paid certain Merger-related costs incurred by CPN Management, our direct parent.
(3)
Our cash and cash equivalents, restricted cash, current and restricted cash, net of current portion are stated as separate line items on our Consolidated Condensed Balance Sheets.

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


6


CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
March 31, 2019
(Unaudited)
1.
Basis of Presentation and Summary of Significant Accounting Policies
We are a power generation company engaged in the ownership and operation of primarily natural gas-fired and geothermal power plants in North America. We have a significant presence in major competitive wholesale and retail power markets in California, Texas and the Northeast and Mid-Atlantic regions of the U.S. We sell power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. We continue to focus on providing products and services that are beneficial to our wholesale and retail customers. We purchase primarily natural gas and some fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We also purchase power for sale to our customers and purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas, power, environmental product, fuel oil and other physical and financial commodity contracts to hedge certain business risks and optimize our portfolio of power plants.
Basis of Interim Presentation — The accompanying unaudited, interim Consolidated Condensed Financial Statements of Calpine Corporation, a Delaware corporation, and consolidated subsidiaries have been prepared pursuant to the rules and regulations of the SEC. In the opinion of management, the Consolidated Condensed Financial Statements include the normal, recurring adjustments necessary for a fair statement of the information required to be set forth therein. Certain information and note disclosures, normally included in financial statements prepared in accordance with U.S. GAAP, have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, these financial statements should be read in conjunction with our audited Consolidated Financial Statements for the year ended December 31, 2018, included in our 2018 Form 10-K. The results for interim periods are not indicative of the results for the entire year primarily due to acquisitions and disposals of assets, seasonal fluctuations in our revenues and expenses, timing of major maintenance expense, variations resulting from the application of the method to calculate the provision for income tax for interim periods, volatility of commodity prices and mark-to-market gains and losses from commodity and interest rate derivative contracts.
Use of Estimates in Preparation of Financial Statements — The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures included in our Consolidated Condensed Financial Statements. Actual results could differ from those estimates.
Reclassifications — We have reclassified certain prior period amounts for comparative purposes. These reclassifications did not have a material effect on our financial condition, results of operations or cash flows.
Cash and Cash Equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have cash and cash equivalents held in non-corporate accounts relating to certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts. These accounts have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects.
Restricted Cash — Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted, making these cash funds unavailable for general use. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent and major maintenance or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Condensed Balance Sheets.

7


The table below represents the components of our restricted cash as of March 31, 2019 and December 31, 2018 (in millions):
 
March 31, 2019
 
December 31, 2018
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service
$
17

 
$
7

 
$
24

 
$
13

 
$
8

 
$
21

Construction/major maintenance
24

 
29

 
53

 
23

 
24

 
47

Security/project/insurance
203

 
31

 
234

 
120

 
—

 
120

Other
21

 
2

 
23

 
11

 
2

 
13

Total
$
265

 
$
69

 
$
334

 
$
167

 
$
34

 
$
201

Property, Plant and Equipment, Net — At March 31, 2019 and December 31, 2018, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
 
March 31, 2019
 
December 31, 2018
 
Depreciable Lives
Buildings, machinery and equipment
$
16,538

 
$
16,400

 
1.5
–
50
 Years
Geothermal properties
1,503

 
1,501

 
13
–
58
 Years
Other
264

 
286

 
3
–
50
 Years
 
18,305

 
18,187

 
 
 
 
 
Less: Accumulated depreciation
6,764

 
6,832

 
 
 
 
 
 
11,541

 
11,355

 
 
 
 
 
Land
121

 
121

 
 
 
 
 
Construction in progress
386

 
966

 
 
 
 
 
Property, plant and equipment, net
$
12,048

 
$
12,442

 
 
 
 
 
Capitalized Interest — The total amount of interest capitalized was $7 million and $7 million during the three months ended March 31, 2019 and 2018, respectively.
Goodwill — We have not recorded any impairment losses or changes in the carrying amount of our goodwill during the three months ended March 31, 2019 and 2018.
New Accounting Standards and Disclosure Requirements
Leases — On January 1, 2019, we adopted Accounting Standards Update 2016-02, “Leases” (“Topic 842”). The comprehensive new lease standard superseded all existing lease guidance. The standard requires that a lessee should recognize a right-of-use asset and a lease liability for substantially all operating leases based on the present value of the minimum rental payments. For lessors, the accounting for leases under Topic 842 remained substantially unchanged. The standard also requires expanded disclosures surrounding leases. We adopted the standards under Topic 842 using the modified retrospective method and elected a number of the practical expedients in our implementation of Topic 842. The key change that affected us relates to our accounting for operating leases for which we are the lessee that were historically off-balance sheet. The impact of adopting the standards resulted in the recognition of a right-of-use asset and lease obligation liability of $191 million on our Consolidated Condensed Balance Sheet on January 1, 2019, exclusive of previously recognized lease balances. The implementation of Topic 842 did not have a material effect on our Consolidated Condensed Statement of Operations or Consolidated Condensed Statement of Cash Flows for the three months ended March 31, 2019. See Note 3 for a discussion of the practical expedients we elected and additional disclosures required by Topic 842.
Derivatives and Hedging — In August 2017, the FASB issued Accounting Standards Update 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” The standard better aligns an entity’s hedging activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results in the financial statements. The standard will prospectively make hedge accounting easier to apply to hedging activities and also enhances disclosure requirements for how hedge transactions are reflected in the financial statements when hedge accounting is elected. We adopted Accounting Standards Update 2017-12 in the first quarter of 2019 which did not have a material effect on our financial condition, results of operations or cash flows.

8


Fair Value Measurements — In August 2018, the FASB issued Accounting Standards Update 2018-13, “Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement.” The standard removes, modifies and adds disclosures about fair value measurements and is effective for fiscal years beginning after December 15, 2019. The changes required by this standard to remove or modify disclosures may be early adopted with adoption of the additional disclosures required by this standard delayed until their effective date. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.
2.
Revenue from Contracts with Customers
Disaggregation of Revenues with Customers

The following tables represent a disaggregation of our revenue for the three months ended March 31, 2019 and 2018 by reportable segment (in millions). See Note 13 for a description of our segments.
 
Three Months Ended March 31, 2019
 
Wholesale
 
 
 
 
 
 
 
West
 
Texas
 
East
 
Retail
 
Elimination
 
Total
Third Party:
 
 
 
 
 
 
 
 
 
 
 
Energy & other products
$
292

 
$
302

 
$
203

 
$
412

 
$
—

 
$
1,209

Capacity
35

 
32

 
177

 
—

 
—

 
244

Revenues relating to physical or executory contracts – third party
$
327

 
$
334

 
$
380

 
$
412

 
$
—

 
$
1,453

 
 
 
 
 
 
 
 
 
 
 
 
Affiliate(1):
$
11

 
$
14

 
$
27

 
$
3

 
$
(55
)
 
$
—

 
 
 
 
 
 
 
 
 
 
 
 
Revenues relating to leases and derivative instruments(2)
 
 
 
 
 
 
 
 
 
 
$
1,146

Total operating revenues
 
 
 
 
 
 
 
 
 
 
$
2,599


 
Three Months Ended March 31, 2018
 
Wholesale
 
 
 
 
 
 
 
West
 
Texas
 
East
 
Retail
 
Elimination
 
Total
Third Party:
 
 
 
 
 
 
 
 
 
 
 
Energy & other products
$
199

 
$
304

 
$
132

 
$
443

 
$
—

 
$
1,078

Capacity
19

 
26

 
149

 
—

 
—

 
194

Revenues relating to physical or executory contracts – third party
$
218

 
$
330

 
$
281

 
$
443

 
$
—

 
$
1,272

 
 
 
 
 
 
 
 
 
 
 
 
Affiliate(1):
$
8

 
$
4

 
$
21

 
$
1

 
$
(34
)
 
$
—

 
 
 
 
 
 
 
 
 
 
 
 
Revenues relating to leases and derivative instruments(2)
 
 
 
 
 
 
 
 
 
 
$
737

Total operating revenues
 
 
 
 
 
 
 
 
 
 
$
2,009

___________
(1)
Affiliate energy, other and capacity revenues reflect revenues on transactions between wholesale and retail affiliates excluding affiliate activity related to leases and derivative instruments. All such activity supports retail supply needs from the wholesale business and/or allows for collateral margin netting efficiencies at Calpine.
(2)
Revenues relating to contracts accounted for as leases and derivatives include energy and capacity revenues relating to PPAs that we are required to account for as operating leases and physical and financial commodity derivative contracts, primarily relating to power, natural gas and environmental products. Revenue related to derivative instruments includes

9


revenue recorded in Commodity revenue and mark-to-market gain (loss) within our operating revenues on our Consolidated Condensed Statements of Operations.
Performance Obligations and Contract Balances
At March 31, 2019 and December 31, 2018, deferred revenue balances relating to contracts with our customers were included in other current liabilities on our Consolidated Condensed Balance Sheets and primarily relate to sales of environmental products and capacity. We classify deferred revenue as current or long-term based on the timing of when we expect to recognize revenue. The balance outstanding at March 31, 2019 and December 31, 2018 was $19 million and $14 million, respectively. The revenue recognized during the three months ended March 31, 2019 and 2018, relating to the deferred revenue balance at the beginning of each period was $2 million and $5 million, respectively, and resulted from our performance under the customer contracts. The change in the deferred revenue balance during the three months ended March 31, 2019 and 2018 was primarily due to the timing difference of when consideration was received and when the related good or service was transferred.
Performance Obligations not yet Satisfied
As of March 31, 2019, we have entered into certain contracts for fixed and determinable amounts with customers under which we have not yet completed our performance obligations which primarily includes agreements for which we are providing capacity from our generating facilities. We have revenues related to the sale of capacity through participation in various ISO capacity auctions estimated based upon cleared volumes and the sale of capacity to our customers of $430 million, $492 million, $441 million, $223 million and $47 million that will be recognized during the years ending December 31, 2019, 2020, 2021, 2022 and 2023, respectively, and $25 million thereafter. Revenues under these contracts will be recognized as we transfer control of the commodities to our customers.
3.
Leases
Accounting for Leases – Lessee
We evaluate contracts for lease accounting at contract inception and assess lease classification at the lease commencement date. For our leases, we recognize a right-of-use asset and corresponding lease obligation liability at the lease commencement date where the lease obligation liability is measured at the present value of the minimum lease payments. For our operating leases, the amortization of the right-of-use asset and the accretion of our lease obligation liability result in a single straight-line expense recognized over the lease term.
We determine the discount rate associated with our operating and finance leases using our incremental borrowing rate at lease commencement. For our operating leases, we use an interest rate commensurate with the interest rate to borrow on a collateralized basis over a similar term with an amount equal to the lease payments. Factors management considers in the calculation of the discount rate include the amount of the borrowing, the lease term including options that are reasonably certain of exercise, the current interest rate environment and the credit rating of the entity. For our finance leases, we use the interest rate commensurate with the interest rate for a project finance borrowing arrangement with a similar collateral package, repayment terms, restrictive covenants and guarantees.
Our operating leases are primarily related to office space for our corporate and regional offices as well as land and operating related leases for our power plants. Additionally, one of our power plants is accounted for as a long-term operating lease. Payments made by Calpine on this lease are recognized on a straight-line basis with capital improvements associated with our leased power plant deemed leasehold improvements that are amortized over the shorter of the term of the lease or the economic life of the capital improvement. Several of our leases contain renewal options held by us to extend the lease term. The inclusion of these renewal periods in the lease term and in the minimum lease payments included in our lease liabilities is dependent on specific facts and circumstances for each lease and whether it is determined to be reasonably certain that we will exercise our option to extend the term. Our office, land and other operating leases do not contain any material restrictive covenants or residual value guarantees.
We have entered into finance leases for certain power plants and related equipment with terms that range up to 37 years (including lease renewal options). The finance leases generally provide for the lessee to pay taxes, maintenance, insurance, and certain other operating costs of the leased property.
In connection with our adoption of Topic 842 on January 1, 2019, we elected certain practical expedients that were available under the new lease standards including:
•
we elected not to separate lease and nonlease components for our current classes of underlying leased assets as the lessee;

10


•
we did not evaluate existing and expired land easements that were not previously accounted for as leases prior to January 1, 2019; and
•
we did not reassess the classification of leases, the accounting for initial direct costs or whether contractual arrangements contained a lease for all contracts that expired or commenced prior to January 1, 2019.
Further, upon the adoption of Topic 842, we made an accounting policy election to not recognize lease assets and liabilities for leases with a term of 12 months or less. We do not have any material subleases associated with our operating and finance leases.
The components of our operating and finance lease expense are as follows for the period presented (in millions):
 
Three Months Ended March 31,
 
2019
Operating Leases
 
Operating lease expense
$
11

 
 
Finance Leases
 
Amortization of the right-of-use assets
$
3

Interest expense
2

Finance lease expense
$
5

 
 
Variable lease expense
$
1

 
 
Total lease expense
$
17

The following is a schedule by year of future minimum lease payments associated with our operating and finance leases together with the present value of the net minimum lease payments as of March 31, 2019 (in millions):
 
Operating Leases(1)
 
Finance Leases(2)
2019
$
44

 
$
12

2020
19

 
18

2021
19

 
18

2022
18

 
18

2023
17

 
21

Thereafter
191

 
72

Total minimum lease payments
308

 
159

Less: Amount representing interest
105

 
58

Total lease obligation
203

 
101

Less: current lease obligation
40

 
11

Long-term lease obligation
$
163

 
$
90

____________
(1)
The lease liabilities associated with our operating leases as of March 31, 2019 are included in other current liabilities and other long-term liabilities on our Consolidated Condensed Balance Sheet.
(2)
The lease liabilities associated with our finance leases as of March 31, 2019 are included in debt, current portion, current liabilities held for sale and debt, net of current portion on our Consolidated Condensed Balance Sheet.

11


Supplemental balance sheet information related to our operating and finance leases is as follows as of March 31, 2019 (in millions, except lease term and discount rate):
 
 
March 31, 2019
Operating leases(1)
 
 
Right-of-use assets associated with operating leases
 
$
182

 
 
 
Finance leases(2)
 
 
Property, plant and equipment, gross
 
$
390

Accumulated amortization
 
(177
)
Property, plant and equipment, net
 
$
213

 
 
 
Weighted average remaining lease term (in years)
 
 
Operating leases
 
15.7

Finance leases
 
12.1

 
 
 
Weighted average discount rate
 
 
Operating leases
 
5.3
%
Finance leases
 
7.5
%
____________
(1)
The right-of-use assets associated with our operating leases as of March 31, 2019 are included in other assets on our Consolidated Condensed Balance Sheet.
(2)
The right-of-use assets associated with our finance leases as of March 31, 2019 are included in current assets held for sale and property, plant and equipment, net on our Consolidated Condensed Balance Sheet.
We did not obtain any right-of-use assets in exchange for lease liabilities associated with operating or finance leases during the three months ended March 31, 2019. Supplemental cash flow information related to our operating and finance leases is as follows for the period presented (in millions):
 
Three Months Ended March 31,
 
2019
Cash paid for amounts included in the measurement of lease liabilities
 
Operating cash flows from operating leases
$
8

Operating cash flows from finance leases
$
2

Financing cash flows from finance leases
$
5

As of March 31, 2019, we have executed agreements that contain a lease with a future lease commencement date and future lease commitments of $1 million primarily related to an office lease which commences in September 2019.
Accounting for Leases – Lessor
We apply lease accounting to PPAs that meet the definition of a lease and determine lease classification treatment at commencement of the agreement. We currently do not have any contracts which are accounted for as sales-type leases or direct financing leases and all of our leases as the lessor are classified as operating leases. As part of the implementation of Topic 842, we elected the practical expedient to not reassess leases that have commenced prior to January 1, 2019.
Revenue from contracts accounted for as operating leases, such as certain tolling agreements, with minimum lease rentals (capacity payments) which vary over time must be levelized. Generally, we levelize these contract revenues on a straight-line basis over the term of the contract. Our operating leases that have commenced contain terms extending through December 2034. These contracts also generally contain variable payment components based on generation volumes or operating efficiency over a period of time. Revenues associated with the variable payments are recognized over time as the goods or services are provided to the lessee. Our operating leases generally do not contain renewal or purchase options or residual value guarantees. We have elected to not separate our lease and non-lease components as the lease components reflect the predominant characteristics of these agreements.

12


Revenue recognized related to fixed lease payments on our operating leases for the period presented is as follows (in millions):
 
Three Months Ended March 31,
 
2019
Operating Leases(1)
 
Fixed lease payments
$
69

____________
(1)
Revenues associated with our operating leases are included in Commodity revenue and other revenue on our Consolidated Condensed Statement of Operations.
The total contractual future minimum lease rentals for our contracts that have commenced and are accounted for as operating leases at March 31, 2019, are as follows (in millions):
2019
$
276

2020
265

2021
261

2022
226

2023
144

Thereafter
277

Total
$
1,449

We do not recognize lease receivables associated with our operating leases as the long-lived assets related to the power plants subject to the tolling contracts are recorded on our Consolidated Condensed Balance Sheets and are being depreciated over their estimated useful lives. Amounts recorded on our Consolidated Condensed Balance Sheet associated with the long-lived assets subject to our operating leases as of March 31, 2019 are as follows (in millions):
 
March 31, 2019
Power plants subject to tolling contracts accounted for as operating leases
 
Property, plant and equipment, gross
$
3,055

Accumulated depreciation
(880
)
Property, plant and equipment, net
$
2,175

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

13


Disclosures for periods prior to the adoption of Topic 842
Lessee    
The following is a schedule by year of future minimum lease payments under operating and capital leases as of December 31, 2018 (in millions):
 
Operating Leases
 
Capital Leases(1)
2019
$
50

 
$
40

2020
19

 
40

2021
20

 
38

2022
18

 
33

2023
17

 
27

Thereafter
192

 
92

Total minimum lease payments
$
316

 
270

Less: Amount representing interest
 
 
89

Present value of net minimum lease payments
 
 
$
181

____________
(1)
Includes a failed sale-leaseback transaction related to our Pasadena Power Plant.
At December 31, 2018, the asset balance for our assets under capital leases totaled approximately $715 million with accumulated amortization of $353 million.
Lessor
The total contractual future minimum lease rentals for our contracts accounted for as operating leases at December 31, 2018, are as follows (in millions):
2019
$
342

2020
261

2021
257

2022
224

2023
141

Thereafter
239

Total
$
1,464

4.
Divestitures
Sale of Garrison Energy Center and RockGen Energy Center
On April 8, 2019, we, through our indirect, wholly-owned subsidiaries Calpine Holdings, LLC and Calpine Northbrook Project Holdings, LLC, entered into an agreement with Cobalt Power, L.L.C. to sell 100% of our ownership interests in Garrison Energy Center LLC (“Garrison”) and RockGen Energy LLC (“RockGen”) for approximately $360 million, subject to certain working capital adjustments and the execution of contracts. Garrison is an indirect, wholly-owned subsidiary that owns the Garrison Energy Center, a 309 MW natural gas-fired, combined-cycle power plant located in Dover, Delaware and RockGen is an indirect, wholly-owned subsidiary that owns the RockGen Energy Center, a 503 MW natural gas-fired, simple-cycle power plant located in Christiana, Wisconsin. We expect the sale, which is subject to regulatory approvals, to close in the third quarter of 2019 and we will use the sale proceeds for our capital allocation activities and general corporate purposes.
At March 31, 2019, we have reclassified the assets and liabilities of Garrison Energy Center and RockGen Energy Center, which are part of our East segment, to current assets and liabilities held for sale on our Consolidated Condensed Balance Sheet consisting primarily of property, plant and equipment, net, and finance leases, respectively, and recorded an immaterial adjustment to the carrying value to reflect fair value less cost to sell.

14


5.
Variable Interest Entities and Unconsolidated Investments
We consolidate all of our VIEs where we have determined that we are the primary beneficiary. There were no changes to our determination of whether we are the primary beneficiary of our VIEs for the three months ended March 31, 2019. See Note 7 in our 2018 Form 10-K for further information regarding our VIEs.
VIE Disclosures
Our consolidated VIEs include natural gas-fired power plants with an aggregate capacity of 7,880 MW and 7,880 MW at March 31, 2019 and December 31, 2018, respectively. For these VIEs, we may provide other operational and administrative support through various affiliate contractual arrangements among the VIEs, Calpine Corporation and its other wholly-owned subsidiaries whereby we support the VIE through the reimbursement of costs and/or the purchase and sale of energy. Other than amounts contractually required, we provided support to these VIEs in the form of cash and other contributions of nil during each of the three months ended March 31, 2019 and 2018.
OMEC — OMEC has a ten-year tolling agreement with SDG&E which commenced on October 3, 2009. Under a ground lease agreement, OMEC held a put option to sell the Otay Mesa Energy Center for $280 million to SDG&E, pursuant to the terms and conditions of the agreement, which was exercisable until April 1, 2019 and SDG&E held a call option to purchase the Otay Mesa Energy Center for $377 million, which was exercisable through October 3, 2018. The call option held by SDG&E expired unexercised.
OMEC has executed a new 59-month Resource Adequacy (“RA”) contract with SDG&E which would commence on October 3, 2019. The RA contract received initial regulatory approval by the California Public Utilities Commission (“CPUC”) on February 21, 2019. This approval was subject to a 30 day appeal period from the date of the issuance of the CPUC decision. On March 27, 2019, an appeal of the CPUC decision was filed with the CPUC. We continue to work to commence the RA contract. However, in the event that we are not successful and another alternative is not reached with SDG&E prior to October 3, 2019, OMEC expects to close on the put and transfer the Otay Mesa Energy Center to SDG&E for $280 million on or about October 3, 2019, which transaction could result in a write down of the carrying value of the asset.
On December 19, 2018, we refinanced the project debt associated with OMEC which lowered the aggregate debt balance to $220 million and extended the maturity to August 2024. In the event that the exercise of the OMEC put option is not rescinded, the OMEC project debt will become payable on November 3, 2019.
We have concluded that we are the primary beneficiary of OMEC as we believe the activity that has the most effect on the financial performance of OMEC is operations and maintenance which is controlled by us. As a result, we consolidate OMEC.
Unconsolidated VIEs and Investments in Unconsolidated Subsidiaries
We have a 50% partnership interest in Greenfield LP and in Whitby. Greenfield LP and Whitby are VIEs; however, we do not have the power to direct the most significant activities of these entities and therefore do not consolidate them. Greenfield LP is a limited partnership between certain subsidiaries of ours and of Mitsui & Co., Ltd., which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant located in Ontario, Canada. We and Mitsui & Co., Ltd. each hold a 50% interest in Greenfield LP. Whitby is a limited partnership between certain of our subsidiaries and Atlantic Packaging Ltd., which operates the Whitby facility, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada. We and Atlantic Packaging Ltd. each hold a 50% partnership interest in Whitby.
Calpine Receivables is a VIE and a bankruptcy remote entity created for the special purpose of purchasing trade accounts receivable from Calpine Solutions under the Accounts Receivable Sales Program. We have determined that we do not have the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance nor the obligation to absorb losses or receive benefits from the VIE. Accordingly, we have determined that we are not the primary beneficiary of Calpine Receivables because we do not have the power to affect its financial performance as the unaffiliated financial institutions that purchase the receivables from Calpine Receivables control the selection criteria of the receivables sold and appoint the servicer of the receivables which controls management of default. Thus, we do not consolidate Calpine Receivables in our Consolidated Condensed Financial Statements and use the equity method of accounting to record our net interest in Calpine Receivables.
We account for these entities under the equity method of accounting and include our net equity interest in investments in unconsolidated subsidiaries on our Consolidated Condensed Balance Sheets. At March 31, 2019 and December 31, 2018, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):

15


 
Ownership Interest as of
March 31, 2019
 
March 31, 2019
 
December 31, 2018
Greenfield LP
50%
 
$
54

 
$
55

Whitby
50%
 
8

 
15

Calpine Receivables
100%
 
5

 
6

Total investments in unconsolidated subsidiaries
 
 
$
67

 
$
76

Our risk of loss related to our investments in Greenfield LP and Whitby is limited to our investment balance. Our risk of loss related to our investment in Calpine Receivables is $60 million which consists of our notes receivable from Calpine Receivables at March 31, 2019 and our initial investment associated with Calpine Receivables. See Note 12 for further information associated with our related party activity with Calpine Receivables.
Holders of the debt of our unconsolidated investments do not have recourse to Calpine Corporation and its other subsidiaries; therefore, the debt of our unconsolidated investments is not reflected on our Consolidated Condensed Balance Sheets. At March 31, 2019 and December 31, 2018, Greenfield LP’s debt was approximately $302 million and $301 million, respectively, and based on our pro rata share of our investment in Greenfield LP, our share of such debt would be approximately $151 million and $151 million at March 31, 2019 and December 31, 2018, respectively.
Our equity interest in the net income from our investments in unconsolidated subsidiaries for the three months ended March 31, 2019 and 2018, is recorded in (income) from unconsolidated subsidiaries. We did not have material income or receive any distributions from our investment in Calpine Receivables for the three months ended March 31, 2019 and 2018. The following table sets forth details of our (income) from unconsolidated subsidiaries for the periods indicated (in millions):
 
Three Months Ended March 31,
 
2019
 
2018
Greenfield LP
$
(2
)
 
$
(2
)
Whitby
(4
)
 
(4
)
Total
$
(6
)
 
$
(6
)
Distributions from Greenfield LP were nil during each of the three months ended March 31, 2019 and 2018. Distributions from Whitby were $11 million and $3 million during the three months ended March 31, 2019 and 2018, respectively.
Inland Empire Energy Center Put and Call Options — We held a call option to purchase the Inland Empire Energy Center (a 775 MW natural gas-fired power plant located in California) at predetermined prices from GE that could be exercised between years 2017 and 2024. GE held a put option whereby they could require us to purchase the power plant, if certain plant performance criteria were met by 2025. On February 1, 2019, we entered into an agreement with GE which, among other things, terminated our call option and GE’s put option related to the Inland Empire Energy Center. As per this agreement, we will take ownership of the facility site and certain remaining site infrastructure and equipment after closure and decommissioning of the facility at a future date, until such time GE continues to own, operate and maintain the power plant, including directing any closure activities. As GE continues to direct all such significant activities of the power plant, we have determined that we no longer hold any variable interests in the Inland Empire Energy Center and it is not a VIE to Calpine.

16


6.
Debt
Our debt at March 31, 2019 and December 31, 2018, was as follows (in millions):
 
March 31, 2019

December 31, 2018
Senior Unsecured Notes
$
2,989

 
$
3,036

First Lien Term Loans
2,972

 
2,976

First Lien Notes
2,401

 
2,400

Project financing, notes payable and other
1,228

 
1,264

CCFC Term Loan
972

 
974

Finance lease obligations
79

 
105

Corporate Revolving Facility
150

 
30

Subtotal
10,791

 
10,785

Less: Current maturities
258

 
637

Total long-term debt
$
10,533

 
$
10,148

Our effective interest rate on our consolidated debt, excluding the effects of capitalized interest and mark-to-market gains (losses) on interest rate hedging instruments, increased to 5.9% for the three months ended March 31, 2019, from 5.6% for the same period in 2018. Since the fourth quarter of 2018, we have cumulatively repurchased $438 million in aggregate principal of our Senior Unsecured Notes for $399 million.
Senior Unsecured Notes
The amounts outstanding under our Senior Unsecured Notes are summarized in the table below (in millions):
 
March 31, 2019
 
December 31, 2018
2023 Senior Unsecured Notes
$
1,228

 
$
1,227

2024 Senior Unsecured Notes
589

 
599

2025 Senior Unsecured Notes
1,172

 
1,210

Total Senior Unsecured Notes
$
2,989

 
$
3,036

During the three months ended March 31, 2019, we repurchased $48 million in aggregate principal of our Senior Unsecured Notes for $44 million. In connection with the repurchases, we recorded approximately $4 million in gain on extinguishment of debt.
First Lien Term Loans
The amounts outstanding under our senior secured First Lien Term Loans are summarized in the table below (in millions):
 
March 31, 2019
 
December 31, 2018
2019 First Lien Term Loan
$
389

 
$
389

2023 First Lien Term Loans
1,057

 
1,059

2024 First Lien Term Loan
1,526

 
1,528

Total First Lien Term Loans
$
2,972

 
$
2,976

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

17


First Lien Term Loan and a portion of our 2023 First Lien Term Loans with a maturity date in January 2023 and expect to record approximately $3 million in loss on extinguishment of debt during the second quarter of 2019 associated with the repayment.
First Lien Notes
The amounts outstanding under our senior secured First Lien Notes are summarized in the table below (in millions):
 
March 31, 2019
 
December 31, 2018
2022 First Lien Notes
$
744

 
$
743

2024 First Lien Notes
486

 
486

2026 First Lien Notes
1,171

 
1,171

Total First Lien Notes
$
2,401

 
$
2,400

Project Financing, Notes Payable and Other
On January 29, 2019, Pacific Gas and Electric Company (“PG&E”) and PG&E Corporation each filed voluntary petitions for relief under Chapter 11. Our power plants that sell energy and energy-related products to PG&E through PPAs, include Russell City Energy Center and Los Esteros Critical Energy Facility. As a result of PG&E’s bankruptcy, we are currently unable to make distributions from our Russell City and Los Esteros projects in accordance with the terms of the project debt agreements associated with each related project. If PG&E does not seek to assume our PPAs through their bankruptcy proceedings, unless otherwise modified, we will incur an event of default under the Russell City and Los Esteros project debt agreements 180 days after the date of PG&E’s bankruptcy filing. We continue to monitor the bankruptcy proceedings and are assessing our options. We plan to work with the lenders to determine a path forward. 
In the event that the exercise of the OMEC put option is not rescinded, the OMEC project debt will become payable on November 3, 2019. See Note 5 for further information related to the OMEC put option.
Corporate Revolving Facility and Other Letter of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at March 31, 2019 and December 31, 2018 (in millions):
 
March 31, 2019
 
December 31, 2018
Corporate Revolving Facility(1)
$
537

 
$
693

CDHI(2)
225

 
251

Various project financing facilities
243

 
228

Other corporate facilities(3)
196

 
193

Total
$
1,201

 
$
1,365

____________
(1)
The Corporate Revolving Facility represents our primary revolving facility. On April 5, 2019, we amended our Corporate Revolving Facility to increase the capacity by approximately $330 million from $1.69 billion to approximately $2.02 billion.
(2)
Pursuant to the terms and conditions of the CDHI credit agreement, the capacity under the CDHI letter of credit facility will be reduced to $125 million on June 30, 2019. The decrease in capacity will not have a material effect on our liquidity as alternative sources of liquidity are available.
(3)
We have two unsecured letter of credit facilities with third party financial institutions totaling $200 million at March 31, 2019. On May 6, 2019, we entered into a new unsecured letter of credit facility which increased the total capacity available to us by approximately $100 million.

18


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 March 31, 2019 and December 31, 2018 (in millions):
 
March 31, 2019
 
December 31, 2018
 
Fair Value
 
Carrying Value
 
Fair Value
 
Carrying Value
Senior Unsecured Notes
$
2,996

 
$
2,989

 
$
2,803

 
$
3,036

First Lien Term Loans
2,990

 
2,972

 
2,877

 
2,976

First Lien Notes
2,439

 
2,401

 
2,299

 
2,400

Project financing, notes payable and other(1)
1,132

 
1,152

 
1,209

 
1,188

CCFC Term Loan
975

 
972

 
938

 
974

Corporate Revolving Facility
150

 
150

 
30

 
30

Total
$
10,682

 
$
10,636

 
$
10,156

 
$
10,604

____________
(1)
Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.
Our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes, CCFC Term Loan and Corporate Revolving Facility are categorized as level 2 within the fair value hierarchy. Our project financing, notes payable and other debt instruments are categorized as level 3 within the fair value hierarchy. We do not have any debt instruments with fair value measurements categorized as level 1 within the fair value hierarchy.
7.
Assets and Liabilities with Recurring Fair Value Measurements
Cash Equivalents — Highly liquid investments which meet the definition of cash equivalents, primarily investments in money market accounts and other interest-bearing accounts, are included in both our cash and cash equivalents and our restricted cash on our Consolidated Condensed Balance Sheets. Certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. We do not have any cash equivalents invested in institutional prime money market funds which require use of a floating net asset value and are subject to liquidity fees and redemption restrictions. Certain of our cash equivalents are classified within level 1 of the fair value hierarchy.
Derivatives — The primary factors affecting the fair value of our derivative instruments at any point in time are the volume of open derivative positions (MMBtu, MWh and $ notional amounts); changing commodity market prices, primarily for power and natural gas; our credit standing and that of our counterparties and customers for energy commodity derivatives; and prevailing interest rates for our interest rate hedging instruments. Prices for power and natural gas and interest rates are volatile, which can result in material changes in the fair value measurements reported in our financial statements in the future.
We utilize market data, such as pricing services and broker quotes, and assumptions that we believe market participants would use in pricing our assets or liabilities including assumptions about the risks inherent to the inputs in the valuation technique. These inputs can be either readily observable, market corroborated or generally unobservable. The market data obtained from broker pricing services is evaluated to determine the nature of the quotes obtained and, where accepted as a reliable quote, used to validate our assessment of fair value. We use other qualitative assessments to determine the level of activity in any given market. We primarily apply the market approach and income approach for recurring fair value measurements and utilize what we believe to be the best available information. We utilize valuation techniques that seek to maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the observability of those inputs.
The fair value of our derivatives includes consideration of our credit standing, the credit standing of our counterparties and customers and the effect of credit enhancements, if any. We have also recorded credit reserves in the determination of fair value based on our expectation of how market participants would determine fair value. Such valuation adjustments are generally based on market evidence, if available, or our best estimate.
Our level 1 fair value derivative instruments primarily consist of power and natural gas swaps, futures and options traded on the NYMEX or Intercontinental Exchange.
Our level 2 fair value derivative instruments primarily consist of interest rate hedging instruments and OTC power and natural gas forwards for which market-based pricing inputs in the principal or most advantageous market are representative of

19


executable prices for market participants. These inputs are observable at commonly quoted intervals for substantially the full term of the instruments. In certain instances, our level 2 derivative instruments may utilize models to measure fair value. These models are industry-standard models, including the Black-Scholes option-pricing model, that incorporate various assumptions, including quoted interest rates, correlation, volatility, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Our level 3 fair value derivative instruments may consist of OTC power and natural gas forwards and options where pricing inputs are unobservable, as well as other complex and structured transactions primarily for the sale and purchase of power and natural gas to both wholesale counterparties and retail customers. Complex or structured transactions are tailored to our customers’ needs and can introduce the need for internally-developed model inputs which might not be observable in or corroborated by the market. When such inputs have a significant effect on the measurement of fair value, the instrument is categorized in level 3. Our valuation models may incorporate historical correlation information and extrapolate available broker and other information to future periods.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement at period end. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect our estimate of the fair value of our assets and liabilities and their placement within the fair value hierarchy levels. The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2019 and December 31, 2018, by level within the fair value hierarchy:
 
Assets and Liabilities with Recurring Fair Value Measures as of March 31, 2019
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
175

 
$
—

 
$
—

 
$
175

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded derivatives contracts
612

 
—

 
—

 
612

Commodity forward contracts(2)
—

 
343

 
218

 
561

Interest rate hedging instruments
—

 
23

 
—

 
23

Effect of netting and allocation of collateral(3)(4)
(612
)
 
(266
)
 
(17
)
 
(895
)
Total assets
$
175

 
$
100

 
$
201

 
$
476

Liabilities:
 
 
 
 
 
 
 
Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded derivatives contracts
$
688

 
$
—

 
$
—

 
$
688

Commodity forward contracts(2)
—

 
537

 
115

 
652

Interest rate hedging instruments
—

 
17

 
—

 
17

Effect of netting and allocation of collateral(3)(4)
(688
)
 
(313
)
 
(19
)
 
(1,020
)
Total liabilities
$
—

 
$
241

 
$
96

 
$
337


20


 
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2018
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
168

 
$
—

 
$
—

 
$
168

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded derivatives contracts
933

 
—

 
—

 
933

Commodity forward contracts(2)
—

 
338

 
212

 
550

Interest rate hedging instruments
—

 
40

 
—

 
40

Effect of netting and allocation of collateral(3)(4)
(933
)
 
(262
)
 
(26
)
 
(1,221
)
Total assets
$
168

 
$
116

 
$
186

 
$
470

Liabilities:
 
 
 
 
 
 
 
Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded derivatives contracts
$
932

 
$
—

 
$
—

 
$
932

Commodity forward contracts(2)
—

 
549

 
220

 
769

Interest rate hedging instruments
—

 
10

 
—

 
10

Effect of netting and allocation of collateral(3)(4)
(932
)
 
(310
)
 
(26
)
 
(1,268
)
Total liabilities
$
—

 
$
249

 
$
194

 
$
443

___________
(1)
At March 31, 2019 and December 31, 2018, we had cash equivalents of $19 million and $23 million included in cash and cash equivalents and $156 million and $145 million included in restricted cash, respectively.
(2)
Includes OTC swaps and options.
(3)
We offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation; therefore, amounts recognized for the right to reclaim, or the obligation to return, cash collateral are presented net with the corresponding derivative instrument fair values. See Note 8 for further discussion of our derivative instruments subject to master netting arrangements.
(4)
Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $76 million, $47 million and $2 million, respectively, at March 31, 2019. Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $(1) million, $48 million and nil, respectively, at December 31, 2018.

21


At March 31, 2019 and December 31, 2018, the derivative instruments classified as level 3 primarily included commodity contracts, which are classified as level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net derivative position classified as level 3 is predominantly driven by market commodity prices. The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at March 31, 2019 and December 31, 2018:
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
 
March 31, 2019
 
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
 
 
 
Power Contracts(1)
 
$
83

 
Discounted cash flow
 
Market price (per MWh)
 
$
2.20

—
$208.95
/MWh
Power Congestion Products
 
$
23

 
Discounted cash flow
 
Market price (per MWh)
 
$
(6.48
)
—
$8.24
/MWh
Natural Gas Contracts
 
$
(4
)
 
Discounted cash flow
 
Market price (per MMBtu)
 
$
0.03

—
$10.00
/MMBtu
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2018
 
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
 
 
 
Power Contracts(1)
 
$
36

 
Discounted cash flow
 
Market price (per MWh)
 
$
2.12

—
$227.98
/MWh
Power Congestion Products
 
$
26

 
Discounted cash flow
 
Market price (per MWh)
 
$
(11.71
)
—
$11.88
/MWh
Natural Gas Contracts
 
$
(73
)
 
Discounted cash flow
 
Market price (per MMBtu)
 
$
0.75

—
$8.87
/MMBtu
___________
(1)
Power contracts include power and heat rate instruments classified as level 3 in the fair value hierarchy.
The following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the periods indicated (in millions):
 
 
Three Months Ended March 31,
 
 
2019
 
2018
Balance, beginning of period
 
$
(8
)
 
$
197

Realized and mark-to-market gains (losses):
 
 
 
 
Included in net income (loss):
 
 
 
 
Included in operating revenues(1)
 
50

 
(57
)
Included in fuel and purchased energy expense(2)
 
2

 
(2
)
Change in collateral
 
2

 
(2
)
Purchases and settlements:
 
 
 
 
Purchases
 
2

 
4

Settlements
 
58

 
(14
)
Transfers in and/or out of level 3(3):
 
 
 
 
Transfers into level 3(4)
 
(1
)
 
6

Transfers out of level 3(5)
 
—

 
(3
)
Balance, end of period
 
$
105

 
$
129

Change in unrealized gains (losses) relating to instruments still held at end of period
 
$
52

 
$
(59
)
___________
(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.

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(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 months ended March 31, 2019 and 2018.
(4)
We had $(1) million in losses and $6 million in gains transferred out of level 2 into level 3 for the three months ended March 31, 2019 and 2018, respectively, due to changes in market liquidity in various power markets.
(5)
We had nil and $3 million in gains transferred out of level 3 into level 2 for the three months ended March 31, 2019 and 2018, respectively, due to changes in market liquidity in various power markets.
8.
Derivative Instruments
Types of Derivative Instruments and Volumetric Information
Commodity Instruments — We are exposed to changes in prices for the purchase and sale of power, natural gas, fuel oil, environmental products and other energy commodities. We use derivatives, which include physical commodity contracts and financial commodity instruments such as OTC and exchange traded swaps, futures, options, forward agreements and instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) or instruments that settle on power or natural gas price relationships between delivery points for the purchase and sale of power and natural gas to attempt to maximize the risk-adjusted returns by economically hedging a portion of the commodity price risk associated with our assets. By entering into these transactions, we are able to economically hedge a portion of our Spark Spread at estimated generation and prevailing price levels.
We also engage in limited trading activities related to our commodity derivative portfolio as authorized by our Board of Directors and monitored by our Chief Risk Officer and Risk Management Committee of senior management. These transactions are executed primarily for the purpose of providing improved price and price volatility discovery, greater market access, and profiting from our market knowledge, all of which benefit our asset hedging activities. Our trading results were not material for each of the three months ended March 31, 2019 and 2018.
Interest Rate Hedging Instruments — A portion of our debt is indexed to base rates, primarily LIBOR. We have historically used interest rate hedging instruments to adjust the mix between fixed and variable rate debt to hedge our interest rate risk for potential adverse changes in interest rates. As of March 31, 2019, the maximum length of time over which we were hedging using interest rate hedging instruments designated as cash flow hedges was 7 years.
As of March 31, 2019 and December 31, 2018, the net forward notional buy (sell) position of our outstanding commodity derivative instruments that did not qualify or were not designated under the normal purchase normal sale exemption and our interest rate hedging instruments were as follows (in millions):
Derivative Instruments
 
Notional Amounts
 
 
March 31, 2019
 
December 31, 2018
 
Power (MWh)
 
(167
)
 
(161
)
 
Natural gas (MMBtu)
 
1,093

 
1,045

 
Environmental credits (Tonnes)
 
12

 
13

 
Interest rate hedging instruments
 
$
4,500

 
$
4,500

 
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 March 31, 2019, was $228 million for which we have posted collateral of $139 million by posting margin deposits, letters of credit or granting additional first priority liens on the assets currently subject to first priority liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. However, if our credit rating were downgraded by one notch from its current level, we estimate that additional collateral of $4 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

23


Condensed Statements of Operations until the period of delivery. Revenues and expenses derived from instruments that qualified for hedge accounting or represent an economic hedge are recorded in the same financial statement line item as the item being hedged. Hedge accounting requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We present the cash flows from our derivatives in the same category as the item being hedged (or economically hedged) within operating activities on our Consolidated Condensed Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows are classified within financing activities.
Cash Flow Hedges — We currently apply hedge accounting to our interest rate hedging instruments. We report the mark-to-market gain or loss on our interest rate hedging instruments designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Prior to January 1, 2019, gains and losses due to ineffectiveness on interest rate hedging instruments were recognized in earnings as a component of interest expense. Upon the adoption of Accounting Standards Update 2017-12 on January 1, 2019, hedge ineffectiveness is no longer separately measured and recorded in earnings. If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value 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 activity) and fuel and purchased energy expense (for physical and financial natural gas, power, environmental product and fuel oil activity). Changes in fair value of interest rate derivatives not designated as hedging instruments are recognized currently in earnings as interest expense.
Derivatives Included on Our Consolidated Condensed Balance Sheets
We offset fair value amounts associated with our derivative instruments and related cash collateral and margin deposits on our Consolidated Condensed Balance Sheets that are executed with the same counterparty under master netting arrangements. Our netting arrangements include a right to set off or net together purchases and sales of similar products in the margining or settlement process. In some instances, we have also negotiated cross commodity netting rights which allow for the net presentation of activity with a given counterparty regardless of product purchased or sold. We also post and/or receive cash collateral in support of our derivative instruments which may also be subject to a master netting arrangement with the same counterparty.

24


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 March 31, 2019 and December 31, 2018 (in millions):
 
 
March 31, 2019
 
 
Gross Amounts of Assets and (Liabilities)
 
Gross Amounts Offset on the Consolidated Condensed Balance Sheets
 
Net Amount Presented on the Consolidated Condensed Balance Sheets(1)
Derivative assets:
 
 
 
 
 
 
Commodity exchange traded derivatives contracts
 
$
513

 
$
(513
)
 
$
—

Commodity forward contracts
 
340

 
(223
)
 
117

Interest rate hedging instruments
 
19

 
—

 
19

Total current derivative assets(2)
 
$
872

 
$
(736
)
 
$
136

Commodity exchange traded derivatives contracts
 
99

 
(99
)
 
—

Commodity forward contracts
 
221

 
(58
)
 
163

Interest rate hedging instruments
 
4

 
(2
)
 
2

Total long-term derivative assets(2)
 
$
324

 
$
(159
)
 
$
165

Total derivative assets
 
$
1,196

 
$
(895
)
 
$
301

 
 
 
 
 
 
 
Derivative (liabilities):
 
 
 
 
 
 
Commodity exchange traded derivatives contracts
 
$
(528
)
 
$
528

 
$
—

Commodity forward contracts
 
(487
)
 
267

 
(220
)
Interest rate hedging instruments
 
(4
)
 
—

 
(4
)
Total current derivative (liabilities)(2)
 
$
(1,019
)
 
$
795

 
$
(224
)
Commodity exchange traded derivatives contracts
 
(160
)
 
160

 
—

Commodity forward contracts
 
(165
)
 
63

 
(102
)
Interest rate hedging instruments
 
(13
)
 
2

 
(11
)
Total long-term derivative (liabilities)(2)
 
$
(338
)
 
$
225

 
$
(113
)
Total derivative liabilities
 
$
(1,357
)
 
$
1,020

 
$
(337
)
Net derivative assets (liabilities)
 
$
(161
)
 
$
125

 
$
(36
)

25


 
 
December 31, 2018
 
 
Gross Amounts of Assets and (Liabilities)
 
Gross Amounts Offset on the Consolidated Condensed Balance Sheets
 
Net Amount Presented on the Consolidated Condensed Balance Sheets(1)
Derivative assets:
 
 
 
 
 
 
Commodity exchange traded derivatives contracts
 
$
820

 
$
(820
)
 
$
—

Commodity forward contracts
 
341

 
(229
)
 
112

Interest rate hedging instruments
 
30

 
—

 
30

Total current derivative assets(3)
 
$
1,191

 
$
(1,049
)
 
$
142

Commodity exchange traded derivatives contracts
 
113

 
(113
)
 
—

Commodity forward contracts
 
209

 
(59
)
 
150

Interest rate hedging instruments
 
10

 
—

 
10

Total long-term derivative assets(3)
 
$
332

 
$
(172
)
 
$
160

Total derivative assets
 
$
1,523

 
$
(1,221
)
 
$
302

 
 
 
 
 
 
 
Derivative (liabilities):
 
 
 
 
 
 
Commodity exchange traded derivatives contracts
 
$
(764
)
 
$
764

 
$
—

Commodity forward contracts
 
(576
)
 
277

 
(299
)
Interest rate hedging instruments
 
(4
)
 
—

 
(4
)
Total current derivative (liabilities)(3)
 
$
(1,344
)
 
$
1,041

 
$
(303
)
Commodity exchange traded derivatives contracts
 
(168
)
 
168

 
—

Commodity forward contracts
 
(193
)
 
59

 
(134
)
Interest rate hedging instruments
 
(6
)
 
—

 
(6
)
Total long-term derivative (liabilities)(3)
 
$
(367
)
 
$
227

 
$
(140
)
Total derivative liabilities
 
$
(1,711
)
 
$
1,268

 
$
(443
)
Net derivative assets (liabilities)
 
$
(188
)
 
$
47

 
$
(141
)
____________
(1)
At March 31, 2019 and December 31, 2018, we had $187 million and $244 million, respectively, of collateral under master netting arrangements that were not offset against our derivative instruments on the Consolidated Condensed Balance Sheets primarily related to initial margin requirements.
(2)
At March 31, 2019, current and long-term derivative assets are shown net of collateral of $(17) million and $(3) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $76 million and $69 million, respectively.
(3)
At December 31, 2018, current and long-term derivative assets are shown net of collateral of $(58) million and $(8) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $49 million and $64 million, respectively.

26


 
March 31, 2019
 
December 31, 2018
 
Fair Value
of Derivative
Assets
 
Fair Value
of Derivative
Liabilities
 
Fair Value
of Derivative
Assets
 
Fair Value
of Derivative
Liabilities
Derivatives designated as cash flow hedging instruments:
 
 
 
 
 
 
 
Interest rate hedging instruments
$
21

 
$
15

 
$
40

 
$
10

Total derivatives designated as cash flow hedging instruments
$
21

 
$
15

 
$
40

 
$
10

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity instruments
$
280

 
$
322

 
$
262

 
$
433

Total derivatives not designated as hedging instruments
$
280

 
$
322

 
$
262

 
$
433

Total derivatives
$
301

 
$
337

 
$
302

 
$
443

Derivatives Included on Our Consolidated Condensed Statements of Operations
Changes in the fair values of our derivative instruments are reflected either in cash for option premiums paid or collected, in OCI, net of tax, for derivative instruments which qualify for and we have elected cash flow hedge accounting treatment, or on our Consolidated Condensed Statements of Operations as a component of mark-to-market activity within our earnings.
The following tables detail the components of our total activity for both the net realized gain (loss) and the net mark-to-market gain (loss) recognized from our derivative instruments in earnings and where these components were recorded on our Consolidated Condensed Statements of Operations for the periods indicated (in millions):
 
Three Months Ended March 31,
 
2019
 
2018
Realized gain (loss)(1)(2)
 
 
 
Commodity derivative instruments
$
111

 
$
(3
)
Total realized gain (loss)
$
111

 
$
(3
)
 
 
 
 
Mark-to-market gain (loss)(3)
 
 
 
Commodity derivative instruments
$
46

 
$
(371
)
Interest rate hedging instruments
(1
)
 
2

Total mark-to-market gain (loss)
$
45

 
$
(369
)
Total activity, net
$
156

 
$
(372
)
___________
(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 adjustments to reflect changes in credit default risk exposure.
 
Three Months Ended March 31,
 
2019
 
2018
Realized and mark-to-market gain (loss)(1)
 
 
 
Derivatives contracts included in operating revenues(2)(3)
$
37

 
$
(359
)
Derivatives contracts included in fuel and purchased energy expense(2)(3)
120

 
(15
)
Interest rate hedging instruments included in interest expense
(1
)
 
2

Total activity, net
$
156

 
$
(372
)
___________
(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.

27


(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.
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 March 31,
 
Three Months Ended March 31,
 
Gain (Loss) Recognized in OCI
 
Gain (Loss) Reclassified from AOCI into Income(3)(4)
 
2019
 
2018
 
2019
 
2018
 
Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate hedging instruments(1)(2)
$
(25
)
 
$
54

 
$
2

 
$
(6
)
 
Interest expense
Interest rate hedging instruments(1)(2)
—

 
1

 
—

 
(1
)
 
Depreciation and amortization expense
Total
$
(25
)
 
$
55

 
$
2

 
$
(7
)
 
 
____________
(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 months ended March 31, 2018. Upon the adoption of Accounting Standards Update 2017-12 on January 1, 2019, hedge ineffectiveness is no longer separately measured and recorded in earnings.
(2)
We recorded an income tax expense of nil and $11 million for the three months ended March 31, 2019 and 2018, respectively, in AOCI related to our cash flow hedging activities.
(3)
Cumulative cash flow hedge gains (losses) attributable to Calpine, net of tax, remaining in AOCI were $59 million and $34 million at March 31, 2019 and December 31, 2018, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $3 million and $3 million at March 31, 2019 and December 31, 2018, respectively.
(4)
Includes losses of $1 million and nil that were reclassified from AOCI to interest expense for the three months ended March 31, 2019 and 2018, respectively, where the hedged transactions became probable of not occurring.
We estimate that pre-tax net losses of an immaterial amount would be reclassified from AOCI into interest expense during the next 12 months as the hedged transactions settle; however, the actual amounts that will be reclassified will likely vary based on changes in interest rates. Therefore, we are unable to predict what the actual reclassification from AOCI into earnings (positive or negative) will be for the next 12 months.
9.
Use of Collateral
We use margin deposits, prepayments and letters of credit as credit support with and from our counterparties for commodity procurement and risk management activities. In addition, we have granted additional first priority liens on the assets currently subject to first priority liens under various debt agreements as collateral under certain of our power and natural gas agreements and certain of our interest rate hedging instruments in order to reduce the cash collateral and letters of credit that we would otherwise 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.

28


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 March 31, 2019 and December 31, 2018 (in millions):
 
March 31, 2019
 
December 31, 2018
Margin deposits(1)
$
448

 
$
343

Natural gas and power prepayments
32

 
31

Total margin deposits and natural gas and power prepayments with our counterparties(2)
$
480

 
$
374

 
 
 
 
Letters of credit issued
$
1,001

 
$
1,166

First priority liens under power and natural gas agreements
49

 
92

First priority liens under interest rate hedging instruments
11

 
10

Total letters of credit and first priority liens with our counterparties
$
1,061

 
$
1,268

 
 
 
 
Margin deposits posted with us by our counterparties(1)(3)
$
136

 
$
52

Letters of credit posted with us by our counterparties
36

 
27

Total margin deposits and letters of credit posted with us by our counterparties
$
172

 
$
79

___________
(1)
We offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation; therefore, amounts recognized for the right to reclaim, or the obligation to return, cash collateral are presented net with the corresponding derivative instrument fair values. See Note 8 for further discussion of our derivative instruments subject to master netting arrangements.
(2)
At March 31, 2019 and December 31, 2018, $135 million and $79 million, respectively, were included in current and long-term derivative assets and liabilities, $337 million and $286 million, respectively, were included in margin deposits and other prepaid expense and $8 million and $9 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.
(3)
At March 31, 2019 and December 31, 2018, $10 million and $32 million, respectively, were included in current and long-term derivative assets and liabilities, $85 million and $20 million, respectively, were included in other current liabilities and $41 million and nil, respectively, were included in other long-term liabilities on our Consolidated Condensed Balance Sheets.
Future collateral requirements for cash, first priority liens and letters of credit may increase or decrease based on the extent of our involvement in hedging and optimization contracts, movements in commodity prices, and also based on our credit ratings and general perception of creditworthiness in our market.
10.
Income Taxes
Income Tax Expense

The table below shows our consolidated income tax expense and our effective tax rates for the periods indicated (in millions):
 
Three Months Ended March 31,
 
2019
 
2018
Income tax expense
$
10

 
$
108

Effective tax rate
5
%
 
(22
)%
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 months ended March 31, 2019 and 2018, our income tax expense is largely comprised of discrete tax items and estimated state and foreign income taxes in jurisdictions where we do not have NOLs or valuation allowances.

29


Income Tax Audits — We remain subject to periodic audits and reviews by taxing authorities; however, we do not expect these audits will have a material effect on our tax provision. Any NOLs we claim in future years to reduce taxable income could be subject to IRS examination regardless of when the NOLs were generated. Any adjustment of state or federal returns could result in a reduction of deferred tax assets rather than a cash payment of income taxes in tax jurisdictions where we have NOLs. We are currently under various state income tax audits for various periods. Our Canadian subsidiaries are currently under examination by the Canada Revenue Agency for the years ended December 31, 2013 through 2016.
Valuation Allowance — U.S. GAAP requires that we consider all available evidence, both positive and negative, and tax planning strategies to determine whether, based on the weight of that evidence, a valuation allowance is needed to reduce the value of deferred tax assets. Future realization of the tax benefit of an existing deductible temporary difference or carryforward ultimately depends on the existence of sufficient taxable income of the appropriate character within the carryback or carryforward periods available under the tax law. Due to our history of losses, we were unable to assume future profits; however, we are able to consider available tax planning strategies.
Unrecognized Tax Benefits — At March 31, 2019, we had unrecognized tax benefits of $28 million. If recognized, $16 million of our unrecognized tax benefits could affect the annual effective tax rate and $12 million, related to deferred tax assets, could be offset against the recorded valuation allowance resulting in no effect on our effective tax rate. We had accrued interest and penalties of $2 million for income tax matters at March 31, 2019. We recognize interest and penalties related to unrecognized tax benefits in income tax expense on our Consolidated Condensed Statements of Operations. We believe that it is reasonably possible that a decrease within the range of nil and $8 million in unrecognized tax benefits could occur within the next twelve months primarily related to state tax issues.
11.
Commitments and Contingencies
Litigation
We are party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business. At the present time, we do not expect that the outcome of any of these proceedings, individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.
On a quarterly basis, we review our litigation activities and determine if an unfavorable outcome to us is considered “remote,” “reasonably possible” or “probable” as defined by U.S. GAAP. Where we determine an unfavorable outcome is probable and is reasonably estimable, we accrue for potential litigation losses. The liability we may ultimately incur with respect to such litigation matters, in the event of a negative outcome, may be in excess of amounts currently accrued, if any; however, we do not expect that the reasonably possible outcome of these litigation matters would, individually or in the aggregate, have a material adverse effect on our financial condition, results of operations or cash flows. Where we determine an unfavorable outcome is not probable or reasonably estimable, we do not accrue for any potential litigation loss. The ultimate outcome of these litigation matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated. As a result, we give no assurance that such litigation matters would, individually or in the aggregate, not have a material adverse effect on our financial condition, results of operations or cash flows.
Environmental Matters
We are subject to complex and stringent environmental laws and regulations related to the operation of our power plants. On occasion, we may incur environmental fees, penalties and fines associated with the operation of our power plants. At the present time, we do not have environmental violations or other matters that would have a material effect on our financial condition, results of operations or cash flows or that would significantly change our operations.
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 March 31, 2019, there are no material outstanding claims related to our guarantee and indemnification obligations and we do not anticipate that we will be required to make any material payments under our guarantee and indemnification obligations. There have been no material changes to our guarantees and indemnifications from those disclosed in Note 16 of our 2018 Form 10-K.

30


12.
Related Party Transactions
We have entered into various agreements with related parties associated with the operation of our business. A description of these related party transactions is provided below:
Calpine Receivables — Under the Accounts Receivable Sales Program, at March 31, 2019 and December 31, 2018, we had $256 million and $238 million, respectively, in trade accounts receivable outstanding that were sold to Calpine Receivables and $50 million and $34 million, respectively, in notes receivable from Calpine Receivables which were recorded on our Consolidated Condensed Balance Sheets. During the three months ended March 31, 2019 and 2018, we sold an aggregate of $597 million and $579 million, respectively, in trade accounts receivable and recorded $579 million and $573 million, respectively, in proceeds. For a further discussion of the Accounts Receivable Sales Program and Calpine Receivables, see Notes 7 and 17 in our 2018 Form 10-K.
Lyondell — We have a ground lease agreement with Houston Refining LP (“Houston Refining”), a subsidiary of Lyondell, for our Channel Energy Center site from which we sell power, capacity and steam to Houston Refining under a PPA. We purchase refinery gas and raw water from Houston Refining under a facilities services agreement. One of the entities which obtained an ownership interest in Calpine through the Merger which closed on March 8, 2018, also has an ownership interest in Lyondell whereby they may significantly influence the management and operating policies of Lyondell. The terms of the PPA with Lyondell were negotiated prior to the Merger closing. We recorded $20 million and $19 million in Commodity revenue during the three months ended March 31, 2019 and 2018, respectively, and $3 million and $2 million in Commodity expense during the three months ended March 31, 2019 and 2018, respectively, associated with this contract with Lyondell. At March 31, 2019 and December 31, 2018, the related party receivable and payable associated with this contract with Lyondell were immaterial.
Other — Following the Merger, we have identified other related party contracts for the sale of power, capacity and RECs which are entered into in the ordinary course of our business. Most of these contracts relate to the sale of commodities and capacity for varying tenors. The terms of most of these contracts were negotiated prior to the Merger. As of March 31, 2019 and December 31, 2018, the related party receivables and payables associated with these transactions were immaterial.
13.
Segment Information
We assess our business on a regional basis due to the effect on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors affecting supply and demand. At March 31, 2019, our geographic reportable segments for our wholesale business are West (including geothermal), Texas and East (including Canada) and we have a separate reportable segment for our retail business. We continue to evaluate the optimal manner in which we assess our performance including our segments and future changes may result in changes to the composition of our geographic segments.
Commodity Margin is a key operational measure of profit reviewed by our chief operating decision maker to assess the performance of our segments. The tables below show financial data for our segments (including a reconciliation of our Commodity Margin to income (loss) from operations by segment) for the periods indicated (in millions):

31


 
Three Months Ended March 31, 2019
 
Wholesale
 
 
 
Consolidation
 
 
 
West
 
Texas
 
East
 
Retail
 
Elimination
 
Total
Total operating revenues(1)
$
682

 
$
743

 
$
689

 
$
998

 
$
(513
)
 
$
2,599

 
 
 
 
 
 
 
 
 
 
 
 
Commodity Margin
$
264

 
$
162

 
$
265

 
$
88

 
$
—

 
$
779

Add: Mark-to-market commodity activity, net and other(2)
56

 
44

 
13

 
(53
)
 
(8
)
 
52

Less:
 
 
 
 
 
 
 
 
 
 


Operating and maintenance expense
81

 
65

 
67

 
34

 
(8
)
 
239

Depreciation and amortization expense
73

 
45

 
43

 
13

 
—

 
174

General and other administrative expense
7

 
12

 
9

 
4

 
—

 
32

Other operating expenses
9

 
2

 
23

 
—

 
—

 
34

(Income) from unconsolidated subsidiaries
—

 
—

 
(6
)
 
—

 
—

 
(6
)
Income (loss) from operations
150

 
82

 
142

 
(16
)
 
—

 
358

Interest expense
 
 
 
 
 
 
 
 
 
 
149

Gain on extinguishment of debt and other (income) expense, net
 
 
 
 
 
 
 
 
 
 
19

Income before income taxes
 
 
 
 
 
 
 
 
 
 
$
190

 
Three Months Ended March 31, 2018
 
Wholesale
 
 
 
Consolidation
 
 
 
West
 
Texas
 
East
 
Retail
 
Elimination
 
Total
Total operating revenues(1)
$
480

 
$
140

 
$
614

 
$
938

 
$
(163
)
 
$
2,009

 
 
 
 
 
 
 
 
 
 
 
 
Commodity Margin
$
185

 
$
166

 
$
184

 
$
77

 
$
—

 
$
612

Add: Mark-to-market commodity activity, net and other(2)
13

 
(547
)
 
40

 
128

 
(7
)
 
(373
)
Less:
 
 
 
 
 
 
 
 
 
 
 
Operating and maintenance expense
90

 
80

 
71

 
40

 
(6
)
 
275

Depreciation and amortization expense
67

 
76

 
45

 
13

 
—

 
201

General and other administrative expense
16

 
25

 
15

 
4

 
—

 
60

Other operating expenses
14

 
16

 
7

 
—

 
—

 
37

(Income) from unconsolidated subsidiaries
—

 
—

 
(6
)
 
—

 
—

 
(6
)
Income (loss) from operations
11


(578
)
 
92

 
148

 
(1
)
 
(328
)
Interest expense
 
 
 
 
 
 
 
 
 
 
151

Other (income) expense, net
 
 
 
 
 
 
 
 
 
 
7

Loss before income taxes
 
 
 
 
 
 
 
 
 
 
$
(486
)
_________
(1)
Includes intersegment revenues of $162 million and $114 million in the West, $211 million and $(67) million in Texas, $137 million and $115 million in the East and $3 million and $1 million in Retail for the three months ended March 31, 2019 and 2018, respectively.
(2)
Includes $(16) million and $(16) million of lease levelization and $21 million and $28 million of amortization expense for the three months ended March 31, 2019 and 2018, respectively.

32


Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Forward-Looking Information
This Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our accompanying Consolidated Condensed Financial Statements and related Notes. See the cautionary statement regarding forward-looking statements at the beginning of this Report for a description of important factors that could cause actual results to differ from expected results.
Introduction and Overview
We are a power generation company engaged in the ownership and operation of primarily natural gas-fired and geothermal power plants in North America. We have a significant presence in major competitive wholesale and retail power markets in California, Texas and the Northeast and Mid-Atlantic regions of the U.S. We sell power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. We continue to focus on providing products and services that are beneficial to our wholesale and retail customers. We purchase primarily natural gas and some fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We also purchase power for sale to our customers and purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas, power, environmental product, fuel oil and other physical and financial commodity contracts to hedge certain business risks and optimize our portfolio of power plants.
We assess our wholesale business on a regional basis due to the effect on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors affecting supply and demand. Our geographic reportable segments for our wholesale business are West (including geothermal), Texas and East (including Canada) and we have a separate reportable segment for our retail business.
Our wholesale power plant portfolio, including partnership interests, consists of 80 power plants, including one under construction, with an aggregate current generation capacity of 26,678 MW and 361 MW under construction. In March 2019, our York 2 Energy Center commenced commercial operations, bringing online approximately 828 MW of combined-cycle, natural gas-fired capacity with dual-fuel capability. Our fleet consists of 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 wholesale geographic segments have an aggregate generation capacity of 7,425 MW in the West, 9,086 MW in Texas and 10,167 MW with an additional 361 MW under construction in the East. Inclusive of our power generation portfolio and our retail sales platforms, we serve customers in 24 states in the U.S. and in Canada and Mexico.
Governmental and Regulatory Matters
We are subject to complex and stringent energy, environmental and other laws and regulations at the federal, state and local levels as well as rules within the ISO and RTO markets in which we participate. Federal and state legislative and regulatory actions, including those by ISO/RTOs, continue to change how our business is regulated. We are actively participating in these debates at the federal, regional, state and ISO/RTO levels. Significant updates are discussed below. For a further discussion of the environmental and other governmental regulations that affect us, see “— Governmental and Regulatory Matters” in Part I, Item 1 of our 2018 Form 10-K.
PJM
The Independent Market Monitor (“IMM”) for PJM filed a complaint with the FERC on February 21, 2019 regarding a component of PJM’s Reliability Pricing Model (“RPM”) that allows sellers of the Capacity Performance product (“CP”) to offer CP at prices above the competitive level, thereby potentially allowing them to exercise market power. The IMM argues that this provision of the tariff is unjust and unreasonable because the tariff does not provide a mechanism for the IMM to review these offers. Additionally, the IMM argues that the tariff should be revised to lower the Market Seller Offer Cap. This change would require nearly all competitive suppliers to submit their offers to the IMM for review prior to bidding in the RPM. In response to the IMM’s complaint, Calpine joined with many other competitive suppliers to urge the FERC to reject the IMM’s proposed resolution as inconsistent with CP and, alternatively, to enhance the penalty provisions of CP. This course of action would address the IMM’s concerns and would also be more consistent with the CP design. FERC action on the IMM’s complaint is pending.

33


RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2019 AND 2018
Below are our results of operations for the three months ended March 31, 2019 as compared to the same period in 2018 (in millions, except for percentages and operating performance metrics). In the comparative tables below, increases in revenue/income or decreases in expense (favorable variances) are shown without brackets while decreases in revenue/income or increases in expense (unfavorable variances) are shown with brackets.
 
2019
 
2018
 
Change
 
% Change
Operating revenues:
 
 
 
 
 
 
 
Commodity revenue
$
2,538

 
$
2,396

 
$
142

 
6

Mark-to-market gain (loss)
56

 
(391
)
 
447

 
#

Other revenue
5

 
4

 
1

 
25

Operating revenues
2,599

 
2,009

 
590

 
29

Operating expenses:
 
 
 
 
 
 
 
Fuel and purchased energy expense:
 
 
 
 
 
 
 
Commodity expense
1,758

 
1,790

 
32

 
2

Mark-to-market (gain) loss
10

 
(20
)
 
(30
)
 
#

Fuel and purchased energy expense
1,768

 
1,770

 
2

 
—

Operating and maintenance expense
239

 
275

 
36

 
13

Depreciation and amortization expense
174

 
201

 
27

 
13

General and other administrative expense
32

 
60

 
28

 
47

Other operating expenses
34

 
37

 
3

 
8

Total operating expenses
2,247

 
2,343

 
96

 
4

(Income) from unconsolidated subsidiaries
(6
)
 
(6
)
 
—

 
—

Income (loss) from operations
358

 
(328
)
 
686

 
#

Interest expense
149

 
151

 
2

 
1

Gain on extinguishment of debt
(4
)
 
—

 
4

 
#

Other (income) expense, net
23

 
7

 
(16
)
 
#

Income (loss) before income taxes
190

 
(486
)
 
676

 
#

Income tax expense
10

 
108

 
98

 
91

Net income (loss)
180

 
(594
)
 
774

 
#

Net income attributable to the noncontrolling interest
(5
)
 
(4
)
 
(1
)
 
(25
)
Net income (loss) attributable to Calpine
$
175

 
$
(598
)
 
$
773

 
#

 
2019
 
2018
 
Change
 
% Change
Operating Performance Metrics:
 
 
 
 
 
 
 
MWh generated (in thousands)(1)(2)
22,101

 
20,800

 
1,301

 
6

Average availability(2)
88.1
%
 
87.6
%
 
0.5
%
 
1

Average total MW in operation(1)
25,208

 
25,187

 
21

 
—

Average capacity factor, excluding peakers
45.8
%
 
43.0
%
 
2.8
%
 
7

Steam Adjusted Heat Rate(2)
7,274

 
7,325

 
51

 
1

__________
#
Variance of 100% or greater
(1)
Represents generation and capacity from power plants that we both consolidate and operate and excludes Greenfield LP, Whitby, Freeport Energy Center, 21.5% of Hidalgo Energy Center and 25% each of Freestone Energy Center and Russell City Energy Center.
(2)
Generation, average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive.

34


We evaluate our Commodity revenue and Commodity expense on a collective basis because the price of power and natural gas tend to move together as the price for power is generally determined by the variable operating cost of the next marginal generator to be dispatched to meet demand. The spread between our Commodity revenue and Commodity expense represents a significant portion of our Commodity Margin. Our financial performance is correlated to how we maximize our Commodity Margin through management of our portfolio of power plants, as well as our hedging and optimization activities. See additional segment discussion in “Commodity Margin by Segment.”
Commodity revenue, net of Commodity expense, increased $174 million for the three months ended March 31, 2019, compared to the same period in 2018, primarily due to (favorable variances are shown without brackets while unfavorable variances are shown with brackets):
(in millions)
 
 
$
153

 
Higher energy margins primarily associated with higher market Spark Spreads in the West and higher contribution from hedging activities across all regions. The increase was partially offset by a gain associated with the cancellation of a PPA recorded in the first quarter of 2018
45

 
Higher regulatory capacity revenue in our East segment
(31
)
 
Lower revenue associated with the sale of environmental credits in our Texas segment during the first quarter of 2018 with no similar activity in 2019
7

 
Period-over-period change in contract amortization, lease levelization relating to tolling contracts and other(1)
$
174

 
 
__________
(1)
Commodity Margin excludes amortization expense related to contracts recorded at fair value, non-cash GAAP-related adjustments to levelize revenues from tolling agreements, Commodity revenue and Commodity expense attributable to the noncontrolling interest and other unusual items or non-recurring items.     
Mark-to-market gain/loss, net from hedging our future generation, fuel supply requirements and retail activities had a favorable variance of $417 million primarily driven by a substantial increase in forward power prices during the three months ended March 31, 2018 compared to the three months ended March 31, 2019.
Our normal, recurring operating and maintenance expense, excluding the effect of restarting our Sutter and South Point Energy Centers and the acceleration of stock-based compensation expense during the first quarter of 2018 in connection with the consummation of the Merger, was relatively unchanged during the first quarter of 2019 compared to the same period in 2018. The decrease of $36 million for the three months ended March 31, 2019 compared to the same period in 2018 primarily resulted from the acceleration of stock-based compensation expense during the first quarter of 2018 partially offset by the effect of our new Long-Term Cash Incentive Plan, which became effective after the Merger. Our Long-Term Cash Incentive Plan provides cash-based incentive awards to most non-executive employees and vests ratably over a three year service period from the date of grant.
Depreciation and amortization expense decreased by $27 million for the three months ended March 31, 2019 compared to the same period in 2018 primarily due to the change in estimated useful lives for our componentized balance of plant parts and rotable parts initiated in 2018 partially offset by adjustments related to our asset retirement obligations during the first quarter of 2019.
General and other administrative expense decreased by $28 million for the three months ended March 31, 2019 compared to the same period in 2018 primarily resulting from the acceleration of stock-based compensation expense recorded during the first quarter of 2018 in connection with the consummation of the Merger in March 2018. We no longer incur stock-based compensation expense subsequent to the consummation of the Merger. Our normal, recurring general and other administrative expense decreased by $2 million during the first quarter of 2019 compared to the same period in 2018.
Gain on extinguishment of debt for the three months ended March 31, 2019 consisted of $4 million associated with the repurchase of a portion of our Senior Unsecured Notes in the first quarter of 2019.
Other (income) expense, net increased by $16 million for the three months ended March 31, 2019 compared to the same period in 2018 primarily due to the net effect of a settlement agreement with GE executed in February 2019 which, among other things, terminated our call option and GE’s put option related to the Inland Empire Energy Center. See Note 5 of the Notes to Consolidated Condensed Financial Statements for further information related to the Inland Empire Energy Center.
During the three months ended March 31, 2019, we recorded an income tax expense of $10 million compared to $108 million for the three months ended March 31, 2018. The favorable period-over-period change primarily resulted from a valuation

35


allowance recorded on our foreign NOLs in the first quarter of 2018 and higher state income tax expense in 2018 due to higher income in tax jurisdictions where we do not have state NOLs.
COMMODITY MARGIN BY SEGMENT
We use Commodity Margin to assess reportable segment performance. Commodity Margin includes revenues recognized on our wholesale and retail power sales activity, electric capacity sales, REC sales, steam sales, realized settlements associated with our marketing, hedging, optimization and trading activity less costs from our fuel and purchased energy expenses, commodity transmission and transportation expenses, environmental compliance expenses and ancillary retail expense. We believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure of profit reviewed by our chief operating decision maker. See Note 13 of the Notes to Consolidated Condensed Financial Statements for a reconciliation of Commodity Margin to income (loss) from operations by segment.
Commodity Margin by Segment for the Three Months Ended March 31, 2019 and 2018
The following tables show our Commodity Margin by segment and related operating performance metrics by regional segment for our wholesale business for the three months ended March 31, 2019 and 2018 (exclusive of the noncontrolling interest). In the comparative tables below, favorable variances are shown without brackets while unfavorable variances are shown with brackets. The MWh generated by regional segment below represent generation from power plants that we both consolidate and operate. Generation, average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive.
West:
2019
 
2018
 
Change
 
% Change
Commodity Margin (in millions)
$
264

 
$
185

 
$
79

 
43

Commodity Margin per MWh generated
$
39.00

 
$
36.21

 
$
2.79

 
8

 
 
 
 
 
 
 
 
MWh generated (in thousands)
6,769

 
5,109

 
1,660

 
32

Average availability
91.1
%
 
87.1
%
 
4.0
%
 
5

Average total MW in operation
7,425

 
7,425

 
—

 
—

Average capacity factor, excluding peakers
45.4
%
 
33.5
%
 
11.9
%
 
36

Steam Adjusted Heat Rate
7,325

 
7,215

 
(110
)
 
(2
)
West — Commodity Margin in our West segment increased by $79 million, or 43%, for the three months ended March 31, 2019 compared to the three months ended March 31, 2018, primarily resulting from higher market Spark Spreads and higher resource adequacy revenue. The increase in Commodity Margin was partially offset by lower contribution from hedging activities for the three months ended March 31, 2019 compared to the three months ended March 31, 2018. Generation increased 32% due to higher market Spark Spreads and a new contract at our Sutter Energy Center which became effective during the second quarter of 2018.
Texas:
2019
 
2018
 
Change
 
% Change
Commodity Margin (in millions)
$
162

 
$
166

 
$
(4
)
 
(2
)
Commodity Margin per MWh generated
$
15.86

 
$
17.21

 
$
(1.35
)
 
(8
)
 
 
 
 
 
 
 
 
MWh generated (in thousands)
10,216

 
9,647

 
569

 
6

Average availability
82.6
%
 
85.1
%
 
(2.5
)%
 
(3
)
Average total MW in operation
8,850

 
8,850

 
—

 
—

Average capacity factor, excluding peakers
53.4
%
 
50.5
%
 
2.9
 %
 
6

Steam Adjusted Heat Rate
7,071

 
7,118

 
47

 
1

Texas — Commodity Margin in our Texas segment decreased by $4 million, or 2%, for the three months ended March 31, 2019 compared to the three months ended March 31, 2018, primarily due to higher revenue in the first quarter of 2018 associated with the sale of environmental credits with no similar activity in 2019. The decrease in Commodity Margin was partially offset by higher contribution from hedging activities during the three months ended March 31, 2019 compared to the same period in 2018.

36


East:
2019
 
2018
 
Change
 
% Change
Commodity Margin (in millions)
$
265

 
$
184

 
$
81

 
44

Commodity Margin per MWh generated
$
51.80

 
$
30.44

 
$
21.36

 
70

 
 
 
 
 
 
 
 
MWh generated (in thousands)
5,116

 
6,044

 
(928
)
 
(15
)
Average availability
91.5
%
 
90.6
%
 
0.9
 %
 
1

Average total MW in operation
8,933

 
8,912

 
21

 
—

Average capacity factor, excluding peakers
36.0
%
 
41.1
%
 
(5.1
)%
 
(12
)
Steam Adjusted Heat Rate
7,629

 
7,729

 
100

 
1

East — Commodity Margin in our East segment increased by $81 million, or 44%, for the three months ended March 31, 2019 compared to the three months ended March 31, 2018, primarily due to higher regulatory capacity revenue in ISO-NE and PJM and higher contribution from hedging activities. The increase in Commodity Margin was partially offset by a 15% decrease in generation primarily driven by milder weather during January 2019 when compared to the same period during 2018 and a gain associated with the cancellation of a PPA recorded during first quarter 2018 with no similar activity during the first quarter of 2019.
Retail:
2019
 
2018
 
Change
 
% Change
Commodity Margin (in millions)
$
88

 
$
77

 
$
11

 
14

Retail — Commodity Margin in our retail segment increased by $11 million, or 14%, for the three months ended March 31, 2019 compared to the three months ended March 31, 2018, primarily due to increased contribution from power and gas supply hedging activity during the first quarter of 2019 compared to the same period in 2018.


37


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 March 31, 2019 and December 31, 2018 (in millions):
 
March 31, 2019
 
December 31, 2018
Cash and cash equivalents, corporate(1)
$
129

 
$
141

Cash and cash equivalents, non-corporate(2)
55

 
64

Total cash and cash equivalents
184

 
205

Restricted cash(2)
334

 
201

Corporate Revolving Facility availability(3)
1,152

 
966

CDHI letter of credit facility availability(4)
75

 
49

Other facilities availability(5)
4

 
7

Total current liquidity availability(6)
$
1,749

 
$
1,428

____________
(1)
Our ability to use corporate cash and cash equivalents is unrestricted.
(2)
See Note 1 of the Notes to Consolidated Condensed Financial Statements for a description of the restrictions on our use of non-corporate cash and cash equivalents and restricted cash.
(3)
Our ability to use availability under our Corporate Revolving Facility is unrestricted. On April 5, 2019, we amended our Corporate Revolving Facility to increase the capacity by approximately $330 million from $1.69 billion to approximately $2.02 billion.
(4)
Our $300 million CDHI letter of credit facility is restricted to support certain obligations under PPAs and power transmission and natural gas transportation agreements as well as fund the construction of our Washington Parish Energy Center. Pursuant to the terms and conditions of the CDHI credit agreement, the capacity under the CDHI letter of credit facility will be reduced to $125 million on June 30, 2019. The decrease in capacity will not have a material effect on our liquidity as alternative sources of liquidity are available.
(5)
We have two unsecured letter of credit facilities with third party financial institutions totaling $200 million at March 31, 2019. On May 6, 2019, we entered into a new unsecured letter of credit facility which increased the total capacity available to us by approximately $100 million.
(6)
Includes $136 million and $52 million of margin deposits posted with us by our counterparties at March 31, 2019 and December 31, 2018, respectively. See Note 9 of the Notes to Consolidated Condensed Financial Statements for further information related to our collateral.
Our principal source for future liquidity is cash flows generated from our operations. We believe that cash on hand and expected future cash flows from operations will be sufficient to meet our liquidity needs for our operations, both in the near and longer term. See “Cash Flow Activities” below for a further discussion of our change in cash and cash equivalents.
Our principal uses of liquidity and capital resources, outside of those required for our operations, include, but are not limited to, collateral requirements to support our commercial hedging and optimization activities, debt service obligations including principal and interest payments, capital expenditures for construction, project development and other growth initiatives and opportunistically repaying debt to manage our balance sheet.
Cash Management — We manage our cash in accordance with our cash management system subject to the requirements of our Corporate Revolving Facility and requirements under certain of our project debt and lease agreements or by regulatory agencies. Our cash and cash equivalents, as well as our restricted cash balances, are invested in money market funds that are not FDIC insured. We place our cash, cash equivalents and restricted cash in what we believe to be creditworthy financial institutions.

38


Future cash dividends, if any, may be authorized at the discretion of our Board of Directors and will depend upon, among other things, our future operations and earnings, capital requirements, asset sales, general financial condition, contractual and financing restrictions and such other factors as our Board of Directors may deem relevant.
Liquidity Sensitivity
Significant changes in commodity prices and Market Heat Rates can affect our liquidity as we use margin deposits, cash prepayments and letters of credit as credit support (collateral) with and from our counterparties for commodity procurement and risk management activities. We estimate that as of March 31, 2019, a three standard deviation shift in collateral exposure based on commodity market price changes for the previous 12 months applied to our current portfolio of margined transactions would result in an increase in collateral posted of approximately $279 million. This amount is not necessarily indicative of the actual amounts that could be required, which may be higher or lower than the amounts estimated above, and also exclude any correlation between the changes in natural gas prices and Market Heat Rates that may occur concurrently. These sensitivities will change as new contracts or hedging activities are executed.
In order to effectively manage our future Commodity Margin, we have economically hedged a portion of our expected generation and natural gas portfolio as well as retail load supply obligations, where appropriate, mostly through power and natural gas forward physical and financial transactions including retail power sales; however, we currently remain susceptible to significant price movements for 2019 and beyond. In addition to the price of natural gas, our Commodity Margin is highly dependent on other factors such as:
•
the level of Market Heat Rates;
•
our continued ability to successfully hedge our Commodity Margin;
•
changes in U.S. macroeconomic conditions;
•
maintaining acceptable availability levels for our fleet;
•
the effect of current and pending environmental regulations in the markets in which we participate;
•
improving the efficiency and profitability of our operations;
•
increasing future contractual cash flows; and
•
our significant counterparties performing under their contracts with us.
Additionally, scheduled outages related to the life cycle of our power plant fleet in addition to unscheduled outages may result in maintenance expenditures that are disproportionate in differing periods. In order to manage such liquidity requirements, we maintain additional liquidity availability in the form of our Corporate Revolving Facility (noted in the table above), letters of credit and the ability to issue first priority liens for collateral support. It is difficult to predict future developments and the amount of credit support that we may need to provide should such conditions occur, we experience another economic recession or energy commodity prices increase significantly.
Letter of Credit Facilities 
The table below represents amounts issued under our letter of credit facilities at March 31, 2019 and December 31, 2018 (in millions):
 
March 31, 2019
 
December 31, 2018
Corporate Revolving Facility(1)
$
537

 
$
693

CDHI(2)
225

 
251

Various project financing facilities
243

 
228

Other corporate facilities(3)
196

 
193

Total
$
1,201

 
$
1,365

____________
(1)
The Corporate Revolving Facility represents our primary revolving facility. On April 5, 2019, we amended our Corporate Revolving Facility to increase the capacity by approximately $330 million from $1.69 billion to approximately $2.02 billion.
(2)
Pursuant to the terms and conditions of the CDHI credit agreement, the capacity under the CDHI letter of credit facility will be reduced to $125 million on June 30, 2019. The decrease in capacity will not have a material effect on our liquidity as alternative sources of liquidity are available.

39


(3)
We have two unsecured letter of credit facilities with third party financial institutions totaling $200 million at March 31, 2019. On May 6, 2019, we entered into a new unsecured letter of credit facility which increased the total capacity available to us by approximately $100 million.
NOLs
We have significant NOLs that will provide future tax deductions when we generate sufficient taxable income during the applicable carryover periods. At December 31, 2018, our consolidated federal NOLs totaled approximately $6.4 billion.
Cash Flow Activities
The following table summarizes our cash flow activities for the three months ended March 31, 2019 and 2018 (in millions):
 
2019
 
2018
Beginning cash, cash equivalents and restricted cash
$
406

 
$
443

Net cash provided by (used in):
 
 
 
Operating activities
241

 
(115
)
Investing activities
(152
)
 
(115
)
Financing activities
23

 
158

Net increase (decrease) in cash, cash equivalents and restricted cash
112

 
(72
)
Ending cash, cash equivalents and restricted cash
$
518

 
$
371

Net Cash Provided By (Used In) Operating Activities
Cash provided by operating activities for the three months ended March 31, 2019, was $241 million compared to cash used in operating activities of $115 million for the three months ended March 31, 2018. The increase was primarily due to:
•
Income from operations — Income from operations, adjusted for non-cash items, increased by $251 million for the three months ended March 31, 2019, compared to the same period in 2018. Non-cash items consist primarily of depreciation and amortization, income from unconsolidated investments in subsidiaries, gain on sale of assets and mark-to-market activity. The increase in income from operations was primarily driven by a $174 million increase in Commodity revenue, net of Commodity expense associated with normal, recurring activity, and a $64 million decrease in operating and maintenance expense and general and other administrative expense driven in large part by Merger-related costs incurred in 2018 including recognition of stock-based compensation expense where similar activity was not incurred during 2019. See “Results of Operations for the Three Months Ended March 31, 2019 and 2018” above for further discussion of these changes.
•
Working capital employed — Working capital employed decreased by $94 million for the three months ended March 31, 2019 compared to the same period in 2018 after adjusting for changes in debt extinguishment costs and mark-to-market related balances. This change was primarily due to a net decrease in margin posting requirements for the three months ended March 31, 2019 when compared to the three month period ended March 31, 2018.
Net Cash Used In Investing Activities
Cash used in investing activities for the three months ended March 31, 2019, was $152 million compared to $115 million for the three months ended March 31, 2018. The increase was primarily due to:
•
Capital expenditures — The increase was primarily due to higher capital expenditures on construction projects during the first quarter of 2019 as compared to the first quarter of 2018.
Net Cash Provided By Financing Activities
Cash provided by financing activities for the three months ended March 31, 2019, was $23 million compared to cash provided by financing activities of $158 million for the three months ended March 31, 2018. The decrease was primarily due to:
•
Corporate Revolving Facility — During the three months ended March 31, 2019, we borrowed a net $120 million, under our Corporate Revolving Facility, compared to $325 million borrowed under our Corporate Revolving Facility during the three months ended March 31, 2018. The 2018 borrowing was made in part to cover one-time costs associated with the consummation of the Merger including the repurchase of our equity-classified share based awards on the effective date of the Merger.

40


•
Repurchases of Senior Unsecured Notes — During the three months ended March 31, 2019, we repurchased $48 million in aggregate principal of our Senior Unsecured Notes for $44 million. There was no similar activity during the three months ended March 31, 2018.
Off Balance Sheet Arrangements
There have been no material changes to our off balance sheet arrangements from those disclosed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2018 Form 10-K.
Special Purpose Subsidiaries
Pursuant to applicable transaction agreements, we have established certain of our entities separate from Calpine Corporation and our other subsidiaries. In accordance with applicable accounting standards, we consolidate these entities with the exception of Calpine Receivables (see Notes 7 and 17 of the Notes to Consolidated Financial Statements in our 2018 Form 10-K for further information related to Calpine Receivables). As of the date of filing of this Report, these entities included: Russell City Energy Company, LLC, OMEC and Calpine Receivables.
OMEC — OMEC has a ten-year tolling agreement with SDG&E which commenced on October 3, 2009. Under a ground lease agreement, OMEC held a put option to sell the Otay Mesa Energy Center for $280 million to SDG&E, pursuant to the terms and conditions of the agreement, which was exercisable until April 1, 2019 and SDG&E held a call option to purchase the Otay Mesa Energy Center for $377 million, which was exercisable through October 3, 2018. The call option held by SDG&E expired unexercised.
OMEC has executed a new 59-month Resource Adequacy (“RA”) contract with SDG&E which would commence on October 3, 2019. The RA contract received initial regulatory approval by the California Public Utilities Commission (“CPUC”) on February 21, 2019. This approval was subject to a 30 day appeal period from the date of the issuance of the CPUC decision. On March 27, 2019, an appeal of the CPUC decision was filed with the CPUC. We continue to work to commence the RA contract. However, in the event that we are not successful and another alternative is not reached with SDG&E prior to October 3, 2019, OMEC expects to close on the put and transfer the Otay Mesa Energy Center to SDG&E for $280 million on or about October 3, 2019, which transaction could result in a write down of the carrying value of the asset.

41


RISK MANAGEMENT AND COMMODITY ACCOUNTING
Our commercial hedging and optimization strategies are designed to maximize our risk-adjusted Commodity Margin by leveraging our knowledge, experience and fundamental views on natural gas and power. We actively manage our risk exposures with a variety of physical and financial instruments with varying time horizons. These instruments include PPAs, tolling arrangements, Heat Rate swaps and options, retail power sales including through our retail subsidiaries, steam sales, buying and selling standard physical power and natural gas products, buying and selling exchange traded instruments, buying and selling environmental and capacity products, natural gas transportation and storage arrangements, electric transmission service and other contracts for the sale and purchase of power products. We utilize these instruments to maximize the risk-adjusted returns for our Commodity Margin. Our retail portfolio has been established to provide an additional source of liquidity for our generation fleet as we hedge retail load from our wholesale generation assets as appropriate.
We conduct our hedging and optimization activities within a structured risk management framework based on controls, policies and procedures. We monitor these activities through active and ongoing management and oversight, defined roles and responsibilities, and daily risk estimates and reporting. Additionally, we seek to manage the associated risks through diversification, by controlling position sizes, by using portfolio position limits, and by actively managing hedge positions to lock in margin. We are exposed to commodity price movements (both profits and losses) in connection with these transactions. These positions are included in and subject to our consolidated risk management portfolio position limits and controls structure. Changes in fair value of commodity positions that do not qualify for or for which we do not elect either hedge accounting or the normal purchase normal sale exemption are recognized currently in earnings and are separately stated on our Consolidated Condensed Statements of Operations in mark-to-market gain/loss as a component of operating revenues (for physical and financial power and Heat Rate and commodity option activity) and fuel and purchased energy expense (for physical and financial natural gas, power, environmental product and fuel oil activity). Our future hedged status and marketing and optimization activities are subject to change as determined by our commercial operations group, Chief Risk Officer, senior management and Board of Directors.
At any point in time, the relative quantity of our products hedged or sold under longer-term contracts is determined by the availability of forward product sales opportunities and our view of the attractiveness of the pricing available for forward sales. We have economically hedged a portion of our expected generation and natural gas portfolio as well as retail load supply obligations, where appropriate, mostly through power and natural gas forward physical and financial transactions including retail power sales; however, we currently remain susceptible to significant price movements for 2019 and beyond. When we elect to enter into these transactions, we are able to economically hedge a portion of our Spark Spread at pre-determined generation and price levels.
We have historically used interest rate hedging instruments to adjust the mix between our fixed and variable rate debt. To the extent eligible, our interest rate hedging instruments have been designated as cash flow hedges, and changes in fair value are recorded in OCI with gains and losses reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. See Note 8 of the Notes to Consolidated Condensed Financial Statements for further discussion of our derivative instruments.
The primary factors affecting our market risk and the fair value of our derivatives at any point in time are the volume of open derivative positions (MMBtu, MWh and $ notional amounts); changing commodity market prices, primarily for power and natural gas; our credit standing and that of our counterparties for energy commodity derivatives; and prevailing interest rates for our interest rate hedging instruments. Since prices for power and natural gas and interest rates are volatile, there may be material changes in the fair value of our derivatives over time, driven both by price volatility and the changes in volume of open derivative transactions. Our derivative assets have decreased to approximately $301 million at March 31, 2019, compared to approximately $302 million at December 31, 2018, and our derivative liabilities have decreased to approximately $337 million at March 31, 2019, compared to approximately $443 million at December 31, 2018. The fair value of our level 3 derivative assets and liabilities at March 31, 2019 represents approximately 42% and 28% of our total assets and liabilities measured at fair value, respectively. See Note 7 of the Notes to Consolidated Condensed Financial Statements for further information related to our level 3 derivative assets and liabilities.

42


The change in fair value of our outstanding commodity and interest rate hedging instruments from January 1, 2019, through March 31, 2019, is summarized in the table below (in millions):
 
Commodity Instruments
 
Interest Rate Hedging Instruments
 
Total
Fair value of contracts outstanding at January 1, 2019
$
(171
)
 
$
30

 
$
(141
)
Items recognized or otherwise settled during the period(1)(2)
(129
)
 
(6
)
 
(135
)
Fair value attributable to new contracts(3)
16

 
—

 
16

Changes in fair value attributable to price movements
242

 
(18
)
 
224

Fair value of contracts outstanding at March 31, 2019(4)
$
(42
)
 
$
6

 
$
(36
)
__________
(1)
Commodity contract settlements consist of the realization of previously recognized gains on contracts not designated as hedging instruments of $133 million (represents a portion of Commodity revenue and Commodity expense as reported on our Consolidated Condensed Statements of Operations) and $4 million related to current period gains from other changes in derivative assets and liabilities not reflected in OCI or earnings.
(2)
Interest rate settlements consist of $6 million related to realized gains from settlements of designated cash flow hedges and nil related to roll-off from settlements of undesignated interest rate hedging instruments (represents a portion of interest expense as reported on our Consolidated Condensed Statements of Operations).
(3)
Fair value attributable to new contracts includes $1 million and nil of fair value related to commodity contracts and interest rate hedging instruments, respectively, which are not reflected in OCI or earnings.
(4)
We netted all amounts allowed under the derivative accounting guidance on the Consolidated Condensed Balance Sheet, which includes derivative transactions under enforceable master netting arrangements and related cash collateral. Net commodity and interest rate derivative assets and liabilities reported in Notes 7 and 8 of the Notes to Consolidated Condensed Financial Statements are shown net of collateral paid to and received from counterparties under legally enforceable master netting arrangements.
Commodity Price Risk — Commodity price risks result from exposure to changes in spot prices, forward prices, price volatilities and correlations between the price of power, steam and natural gas. We manage the commodity price risk and the variability in future cash flows from forecasted sales of power and purchases of natural gas of our entire portfolio of generating assets and contractual positions by entering into various derivative and non-derivative instruments.
The net fair value of outstanding derivative commodity instruments, net of allocated collateral, at March 31, 2019, based on price source and the period during which the instruments will mature, are summarized in the table below (in millions):
Fair Value Source
 
2019
 
2020-2021
 
2022-2023
 
After 2023
 
Total
Prices actively quoted
 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Prices provided by other external sources
 
(121
)
 
(28
)
 
2

 
—

 
(147
)
Prices based on models and other valuation methods
 
11

 
39

 
17

 
38

 
105

Total fair value
 
$
(110
)
 
$
11

 
$
19

 
$
38

 
$
(42
)
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.

43


The table below presents the high, low and average of our daily VAR for the three months ended March 31, 2019 and 2018 (in millions):
 
2019
 
2018
Three months ended March 31:
 
 
 
High
$
50

 
$
36

Low
$
26

 
$
19

Average
$
35

 
$
26

As of March 31
$
31

 
$
31

Due to the inherent limitations of statistical measures such as VAR, the VAR calculation may not capture the full extent of our commodity price exposure. As a result, actual changes in the value of our energy commodity portfolio could be different from the calculated VAR, and could have a material effect on our financial results. In order to evaluate the risks of our portfolio on a comprehensive basis and augment our VAR analysis, we also measure the risk of the energy commodity portfolio using several analytical methods including sensitivity analysis, non-statistical scenario analysis, including stress testing, and daily position report analysis.
We utilize the forward commodity markets to hedge price risk associated with our power plant portfolio. Our ability to hedge relies in part on market liquidity and the number of counterparties with which to transact. If the number of counterparties in these markets were to decrease, it could decrease our ability to hedge our forward commodity price risk and create incremental volatility in our earnings. The effects of declining liquidity in the forward commodity markets is also mitigated by our retail subsidiaries which provides us with an additional outlet to transact hedging activities related to our wholesale power plant portfolio.
Liquidity Risk — Liquidity risk arises from the general funding requirements needed to manage our activities and assets and liabilities. Fluctuating natural gas prices or Market Heat Rates can cause our collateral requirements for our wholesale and retail activities to increase or decrease. Our liquidity management framework is intended to maximize liquidity access and minimize funding costs during times of rising prices. See further discussion regarding our uses of collateral as they relate to our commodity procurement and risk management activities in Note 9 of the Notes to Consolidated Condensed Financial Statements.
Credit Risk — Credit risk relates to the risk of loss resulting from nonperformance or non-payment by our counterparties or customers related to their contractual obligations with us. Risks surrounding counterparty and customer performance and credit could ultimately affect the amount and timing of expected cash flows. We also have credit risk if counterparties or customers are unable to provide collateral or post margin. We monitor and manage our credit risk through credit policies that include:
•
credit approvals;
•
routine monitoring of counterparties’ and customer’s credit limits and their overall credit ratings;
•
limiting our marketing, hedging and optimization activities with high risk counterparties;
•
margin, collateral, or prepayment arrangements; and
•
payment netting arrangements, or master netting arrangements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty.
We have concentrations of credit risk with a few of our wholesale counterparties and retail customers relating to our sales of power and steam and our hedging, optimization and trading activities. For example, our wholesale business currently has contracts with investor owned California utilities which could be affected should they be found liable for recent wildfires in California and, accordingly, incur substantial costs associated with the wildfires.
On January 29, 2019, PG&E and PG&E Corporation each filed voluntary petitions for relief under Chapter 11. We currently have several power plants that provide energy and energy-related products to PG&E under PPAs, many of which have PG&E collateral posting requirements. Since the bankruptcy filing, we have received all material payments under the PPAs, either directly or through the application of collateral. We also currently have numerous other agreements with PG&E related to the operation of our power plants in Northern California, under which PG&E has continued to provide service since its bankruptcy filing. We cannot predict the ultimate outcome of this matter and continue to monitor the bankruptcy proceedings.

44


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 March 31, 2019, and the period during which the instruments will mature are summarized in the table below (in millions):
Credit Quality
(Based on Credit Ratings
as of March 31, 2019)
 
2019
 
2020-2021
 
2022-2023
 
After 2023
 
Total
Investment grade
 
$
(125
)
 
$
(21
)
 
$
1

 
$
16

 
$
(129
)
Non-investment grade
 
(3
)
 
(7
)
 
(2
)
 
—

 
(12
)
No external ratings(1)
 
18

 
39

 
20

 
22

 
99

Total fair value
 
$
(110
)
 
$
11

 
$
19

 
$
38

 
$
(42
)
__________
(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 $(15) million at March 31, 2019.
New Accounting Standards and Disclosure Requirements
See Note 1 of the Notes to Consolidated Condensed Financial Statements for a discussion of new accounting standards and disclosure requirements.
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
The information required to be disclosed under this Item 3 is set forth under Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Risk Management and Commodity Accounting.” This information should be read in conjunction with the information disclosed in our 2018 Form 10-K.
Item 4.
Controls and Procedures
Disclosure Controls and Procedures
As of the end of the period covered by this Report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rule 13a-15(e) and Rule 15d-15(e) of the Exchange Act. Based upon, and as of the date of, this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective such that the information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Changes in Internal Control Over Financial Reporting
During the first quarter of 2019, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


45


PART II — OTHER INFORMATION
Item 1.
Legal Proceedings

See Note 11 of the Notes to Consolidated Condensed Financial Statements for a description of our legal proceedings.
Item 1A.
Risk Factors
There were no material changes to the description of the risk factors associated with our business previously disclosed in Part I, Item 1A “Risk Factors” of our 2018 Form 10-K.
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds

None.
Item 3.
Defaults Upon Senior Securities
None.
Item 4.
Mine Safety Disclosures

Not applicable.
Item 5.
Other Information

None.

46


Item 6.
Exhibits
EXHIBIT INDEX
Exhibit
Number
 
Description
 
 
 
 
Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
 
Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
 
Certification of the Chief Executive Officer and the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. *
 
 
 
101.INS
 
XBRL Instance Document.
 
 
 
101.SCH
 
XBRL Taxonomy Extension Schema.
 
 
101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase.
 
 
101.DEF
 
XBRL Taxonomy Extension Definition Linkbase.
 
 
101.LAB
 
XBRL Taxonomy Extension Label Linkbase.
 
 
101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase.
_______________
*
Furnished herewith.
†
Management contract or compensatory plan, contract or arrangement.


47


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: May 10, 2019


48



EXHIBIT 31.1
CERTIFICATIONS
I, John B. (Thad) Hill III, certify that:
1.
I have reviewed this quarterly report on Form 10-Q of Calpine Corporation (the “registrant”);
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: May 10, 2019
 
/s/ JOHN B. (THAD) HILL III
John B. (Thad) Hill III
President, Chief Executive Officer and Director
Calpine Corporation




EXHIBIT 31.2
CERTIFICATIONS
I, Zamir Rauf, certify that:
1.
I have reviewed this quarterly report on Form 10-Q of Calpine Corporation (the “registrant”);
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: May 10, 2019
 
/s/ ZAMIR RAUF
Zamir Rauf
Executive Vice President and
Chief Financial Officer
Calpine Corporation




EXHIBIT 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of Calpine Corporation (the “Company”) on Form 10-Q for the period ended March 31, 2019, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each of the undersigned does hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his or her knowledge, based upon a review of the Report:
(1)
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
 
 
 
 
 
 
 
 
 
/s/ JOHN B. (THAD) HILL III
 
 
 
/s/ ZAMIR RAUF
 
 
John B. (Thad) Hill III
 
 
 
Zamir Rauf
 
 
President,
 
 
 
Executive Vice President and
 
 
Chief Executive Officer and Director
 
 
 
Chief Financial Officer
 
 
Calpine Corporation
 
 
 
Calpine Corporation
 
Dated: May 10, 2019
A signed original of this written statement required by Section 906 has been provided to Calpine Corporation and will be retained by Calpine Corporation and furnished to the Securities and Exchange Commission or its staff upon request.


v3.19.1
Document and Entity Information - shares
 3 Months Ended
Mar. 31, 2019
May 10, 2019
Entity Information [Line Items]    
Entity Registrant Name CALPINE CORP  
Entity Central Index Key 0000916457  
Current Fiscal Year End Date --12-31  
Entity Filer Category Non-accelerated Filer  
Document Type 10-Q  
Document Period End Date Mar. 31, 2019  
Document Fiscal Year Focus 2019  
Document Fiscal Period Focus Q1  
Amendment Flag false  
Entity Small Business false  
Entity Emerging Growth Company false  
Entity Common Stock, Shares Outstanding   105.2

v3.19.1
Consolidated Condensed Statements of Operations - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2019
Mar. 31, 2018
Operating revenues:    
Commodity revenue $ 2,538 $ 2,396
Mark-to-market gain (loss) 56 (391)
Other revenue 5 4
Operating revenues [1] 2,599 2,009
Operating expenses:    
Commodity expense 1,758 1,790
Mark-to-market (gain) loss 10 (20)
Fuel and purchased energy expense 1,768 1,770
Operating and maintenance expense 239 275
Depreciation and amortization expense 174 201
General and other administrative expense 32 60
Other operating expenses 34 37
Total operating expenses 2,247 2,343
(Income) from unconsolidated subsidiaries (6) (6)
Income (loss) from operations 358 (328)
Interest expense 149 151
Gain on extinguishment of debt (4) 0
Other (income) expense, net 23 7
Income (loss) before income taxes 190 (486)
Income tax expense 10 108
Net income (loss) 180 (594)
Net income attributable to the noncontrolling interest (5) (4)
Net income (loss) attributable to Calpine $ 175 $ (598)
[1] Includes intersegment revenues of $162 million and $114 million in the West, $211 million and $(67) million in Texas, $137 million and $115 million in the East and $3 million and $1 million in Retail for the three months ended March 31, 2019 and 2018, respectively.

v3.19.1
Consolidated Condensed Statements of Comprehensive Income - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2019
Mar. 31, 2018
Statement of Comprehensive Income [Abstract]    
Net income (loss) $ 180 $ (594)
Cash flow hedging activities:    
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income (loss) (23) 48
Reclassification adjustment for (gain) loss on cash flow hedges realized in net income (loss) [1],[2] (2) 7
Foreign currency translation gain (loss) 2 (6)
Income tax expense 0 (11)
Other comprehensive income (loss) (23) 38
Comprehensive income (loss) 157 (556)
Comprehensive (income) attributable to the noncontrolling interest (5) (6)
Comprehensive income (loss) attributable to Calpine $ 152 $ (562)
[1] Cumulative cash flow hedge gains (losses) attributable to Calpine, net of tax, remaining in AOCI were $59 million and $34 million at March 31, 2019 and December 31, 2018, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $3 million and $3 million at March 31, 2019 and December 31, 2018, respectively.
[2] Includes losses of $1 million and nil that were reclassified from AOCI to interest expense for the three months ended March 31, 2019 and 2018, respectively, where the hedged transactions became probable of not occurring.

v3.19.1
Consolidated Condensed Balance Sheets - USD ($)
$ in Millions
Mar. 31, 2019
Dec. 31, 2018
Current assets:    
Cash and cash equivalents ($35 and $43 attributable to VIEs) $ 184 $ 205
Accounts receivable, net of allowance of $6 and $9 794 1,022
Inventories 515 525
Margin deposits and other prepaid expense 380 315
Restricted cash, current ($187 and $90 attributable to VIEs) 265 167
Derivative assets, current [1] 136 [2] 142 [3]
Current assets held for sale 372 0
Other current assets 51 43
Total current assets 2,697 2,419
Property, plant and equipment, net ($3,902 and $3,919 attributable to VIEs) 12,048 12,442
Restricted cash, net of current portion ($37 and $33 attributable to VIEs) 69 34
Investments in unconsolidated subsidiaries 67 76
Derivative Asset, Noncurrent [1] 165 [2] 160 [3]
Goodwill 242 242
Intangible assets, net 391 412
Other assets ($98 and $30 attributable to VIEs) 472 277
Total assets 16,151 16,062
Current liabilities:    
Accounts payable 720 958
Accrued interest payable 120 96
Debt, current portion ($211 and $201 attributable to VIEs) 258 637
Derivative Liability, Current [1] 224 [2] 303 [3]
Current liabilitites held for sale 25 0
Other current liabilities ($126 and $36 attributable to VIEs) 518 489
Total current liabilities 1,865 2,483
Debt, net of current portion ($1,925 and $1,978 attributable to VIEs) 10,533 10,148
Long-term derivative liabilities [1] 113 [2] 140 [3]
Other long-term liabilities ($74 and $36 attributable to VIEs) 427 235
Total liabilities 12,938 13,006
Commitments and contingencies (see Note 11)
Stockholder’s equity:    
Common stock, $0.001 par value per share; authorized 5,000 shares, 105.2 shares issued and outstanding 0 0
Additional paid-in capital 9,584 9,582
Accumulated deficit (6,367) (6,542)
Accumulated other comprehensive loss (100) (77)
Total Calpine stockholder’s equity 3,117 2,963
Noncontrolling interest 96 93
Total stockholder’s equity 3,213 3,056
Total liabilities and stockholder’s equity $ 16,151 $ 16,062
[1] At March 31, 2019 and December 31, 2018, we had $187 million and $244 million, respectively, of collateral under master netting arrangements that were not offset against our derivative instruments on the Consolidated Condensed Balance Sheets primarily related to initial margin requirements.
[2] At March 31, 2019, current and long-term derivative assets are shown net of collateral of $(17) million and $(3) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $76 million and $69 million, respectively.
[3] At December 31, 2018, current and long-term derivative assets are shown net of collateral of $(58) million and $(8) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $49 million and $64 million, respectively.

v3.19.1
Consolidated Condensed Balance Sheets (Parenthetical) - USD ($)
$ in Millions
Mar. 31, 2019
Dec. 31, 2018
Cash and cash equivalents ($35 and $43 attributable to VIEs) $ 184 $ 205
Accounts receivable, net of allowance of $6 and $9 6 9
Restricted cash, current ($187 and $90 attributable to VIEs) 265 167
Property, plant and equipment, net ($3,902 and $3,919 attributable to VIEs) 12,048 12,442
Restricted cash, net of current portion ($37 and $33 attributable to VIEs) 69 34
Other assets ($98 and $30 attributable to VIEs) 472 277
Debt, current portion ($211 and $201 attributable to VIEs) 258 637
Other current liabilities ($126 and $36 attributable to VIEs) 518 489
Debt, net of current portion ($1,925 and $1,978 attributable to VIEs) 10,533 10,148
Other long-term liabilities ($74 and $36 attributable to VIEs) $ 427 $ 235
Common Stock, Par or Stated Value Per Share $ 0.001 $ 0.001
Common Stock, Shares Authorized 5,000 5,000
Common Stock, Shares, Issued 105.2 105.2
Common Stock, Shares, Outstanding 105.2 105.2
Variable Interest Entity, Primary Beneficiary [Member]    
Cash and cash equivalents ($35 and $43 attributable to VIEs) $ 35 $ 43
Restricted cash, current ($187 and $90 attributable to VIEs) 187 90
Property, plant and equipment, net ($3,902 and $3,919 attributable to VIEs) 3,902 3,919
Restricted cash, net of current portion ($37 and $33 attributable to VIEs) 37 33
Other assets ($98 and $30 attributable to VIEs) 98 30
Debt, current portion ($211 and $201 attributable to VIEs) 211 201
Other current liabilities ($126 and $36 attributable to VIEs) 126 36
Debt, net of current portion ($1,925 and $1,978 attributable to VIEs) 1,925 1,978
Other long-term liabilities ($74 and $36 attributable to VIEs) $ 74 $ 36

v3.19.1
Consolidated Statements of Stockholders' Equity Statement - USD ($)
$ in Millions
Total
Common Stock [Member]
Treasury Stock [Member]
Additional Paid-in Capital [Member]
Retained Earnings [Member]
AOCI Attributable to Parent [Member]
Noncontrolling Interest [Member]
Beginning Balance at Dec. 31, 2017 $ 3,067 $ 0 $ (15) $ 9,661 $ (6,552) $ (106) $ 79
Treasury Stock, Value, Acquired, Cost Method 7 0 7 0 0 0 0
Stock-based compensation expense 41 0 0 41 0 0 0
Other (78) 0 22 (100) 0 0 0
Dividends paid (20) [1] 0 0 (20) 0 0 0
Contribution from the noncontrolling interest 2 0 0 0 0 0 2
Distribution to the noncontrolling interest (2) 0 0 0 0 0 (2)
Net income (loss) (594) 0 0 0 (598) 0 4
Other comprehensive loss 38 0 0 0 0 36 2
Ending Balance at Mar. 31, 2018 2,447 0 0 9,582 (7,150) (70) 85
Beginning Balance at Dec. 31, 2018 3,056 0 0 9,582 (6,542) (77) 93
Other 0 0 0 2 0 0 (2)
Dividends paid [1] 0            
Distribution to the noncontrolling interest 0            
Net income (loss) 180 0 0 0 175 0 5
Other comprehensive loss (23) 0 0 0 0 (23) 0
Ending Balance at Mar. 31, 2019 $ 3,213 $ 0 $ 0 $ 9,584 $ (6,367) $ (100) $ 96
[1] Subsequent to the consummation of the Merger on March 8, 2018, we paid certain Merger-related costs incurred by CPN Management, our direct parent.

v3.19.1
Consolidated Condensed Statements of Cash Flows - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2019
Mar. 31, 2018
Cash flows from operating activities:    
Net income (loss) $ 180 $ (594)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:    
Depreciation and amortization(1) [1] 199 223
Gain on extinguishment of debt (4) 0
Deferred income taxes 7 69
Mark-to-market activity, net [2] (45) 369
(Income) from unconsolidated subsidiaries (6) (6)
Return on investments from unconsolidated subsidiaries 11 3
Stock-based compensation expense 0 57
Other 19 6
Change in operating assets and liabilities:    
Accounts receivable 228 164
Accounts payable (229) (77)
Margin deposits and other prepaid expense (65) (72)
Other assets and liabilities, net 27 (107)
Derivative instruments, net (81) (150)
Net cash provided by (used in) operating activities 241 (115)
Cash flows from investing activities:    
Purchases of property, plant and equipment (143) (114)
Other (9) (1)
Net cash used in investing activities (152) (115)
Cash flows from financing activities:    
Repayment of CCFC Term Loan and First Lien Term Loans (10) (10)
Repurchases of Senior Unsecured Notes (44) 0
Borrowings under Corporate Revolving Facility 170 325
Repayments of Corporate Revolving Facility (50) 0
Repayments of project financing, notes payable and other (43) (43)
Distribution to noncontrolling interest holder 0 (2)
Financing costs 0 (6)
Stock repurchases 0 (79)
Shares repurchased for tax withholding on stock-based awards 0 (7)
Dividends paid(2) [3] 0 (20)
Net cash provided by financing activities 23 158
Net increase (decrease) in cash, cash equivalents and restricted cash 112 (72)
Cash, cash equivalents and restricted cash, beginning of period 406 443
Cash, cash equivalents and restricted cash, end of period(3) [4] 518 371
Cash paid during the period for:    
Interest, net of amounts capitalized 115 110
Income taxes 0 4
Supplemental disclosure of non-cash investing and financing activities:    
Change in capital expenditures included in account payable 13 (6)
Plant tax settlement offset in prepaid assets (4) 0
Asset retirement obligation adjustment offset in operating activities (13) 0
Other Current Assets [Member]    
Supplemental disclosure of non-cash investing and financing activities:    
Garrison Energy Center and RockGen Energy Center property, plant and equipment, net, classified as current assets held for sale (363) 0
Other Current Liabilities [Member]    
Supplemental disclosure of non-cash investing and financing activities:    
Garrison Energy Center and RockGen Energy Center property, plant and equipment, net, classified as current assets held for sale $ 22 $ 0
[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] 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.
[3] Subsequent to the consummation of the Merger on March 8, 2018, we paid certain Merger-related costs incurred by CPN Management, our direct parent.
[4] Our cash and cash equivalents, restricted cash, current and restricted cash, net of current portion are stated as separate line items on our Consolidated Condensed Balance Sheets.

v3.19.1
Basis of Presentation and Summary of Significant Accounting Policies
 3 Months Ended
Mar. 31, 2019
Accounting Policies [Abstract]  
Summary of significant accounting policies
Basis of Presentation and Summary of Significant Accounting Policies
We are a power generation company engaged in the ownership and operation of primarily natural gas-fired and geothermal power plants in North America. We have a significant presence in major competitive wholesale and retail power markets in California, Texas and the Northeast and Mid-Atlantic regions of the U.S. We sell power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. We continue to focus on providing products and services that are beneficial to our wholesale and retail customers. We purchase primarily natural gas and some fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We also purchase power for sale to our customers and purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas, power, environmental product, fuel oil and other physical and financial commodity contracts to hedge certain business risks and optimize our portfolio of power plants.
Basis of Interim Presentation — The accompanying unaudited, interim Consolidated Condensed Financial Statements of Calpine Corporation, a Delaware corporation, and consolidated subsidiaries have been prepared pursuant to the rules and regulations of the SEC. In the opinion of management, the Consolidated Condensed Financial Statements include the normal, recurring adjustments necessary for a fair statement of the information required to be set forth therein. Certain information and note disclosures, normally included in financial statements prepared in accordance with U.S. GAAP, have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, these financial statements should be read in conjunction with our audited Consolidated Financial Statements for the year ended December 31, 2018, included in our 2018 Form 10-K. The results for interim periods are not indicative of the results for the entire year primarily due to acquisitions and disposals of assets, seasonal fluctuations in our revenues and expenses, timing of major maintenance expense, variations resulting from the application of the method to calculate the provision for income tax for interim periods, volatility of commodity prices and mark-to-market gains and losses from commodity and interest rate derivative contracts.
Use of Estimates in Preparation of Financial Statements — The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures included in our Consolidated Condensed Financial Statements. Actual results could differ from those estimates.
Reclassifications — We have reclassified certain prior period amounts for comparative purposes. These reclassifications did not have a material effect on our financial condition, results of operations or cash flows.
Cash and Cash Equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have cash and cash equivalents held in non-corporate accounts relating to certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts. These accounts have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects.
Restricted Cash — Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted, making these cash funds unavailable for general use. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent and major maintenance or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Condensed Balance Sheets.
The table below represents the components of our restricted cash as of March 31, 2019 and December 31, 2018 (in millions):
 
March 31, 2019
 
December 31, 2018
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service
$
17

 
$
7

 
$
24

 
$
13

 
$
8

 
$
21

Construction/major maintenance
24

 
29

 
53

 
23

 
24

 
47

Security/project/insurance
203

 
31

 
234

 
120

 
—

 
120

Other
21

 
2

 
23

 
11

 
2

 
13

Total
$
265

 
$
69

 
$
334

 
$
167

 
$
34

 
$
201


Property, Plant and Equipment, Net — At March 31, 2019 and December 31, 2018, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
 
March 31, 2019
 
December 31, 2018
 
Depreciable Lives
Buildings, machinery and equipment
$
16,538

 
$
16,400

 
1.5
–
50
 Years
Geothermal properties
1,503

 
1,501

 
13
–
58
 Years
Other
264

 
286

 
3
–
50
 Years
 
18,305

 
18,187

 
 
 
 
 
Less: Accumulated depreciation
6,764

 
6,832

 
 
 
 
 
 
11,541

 
11,355

 
 
 
 
 
Land
121

 
121

 
 
 
 
 
Construction in progress
386

 
966

 
 
 
 
 
Property, plant and equipment, net
$
12,048

 
$
12,442

 
 
 
 
 
Capitalized Interest — The total amount of interest capitalized was $7 million and $7 million during the three months ended March 31, 2019 and 2018, respectively.
Goodwill — We have not recorded any impairment losses or changes in the carrying amount of our goodwill during the three months ended March 31, 2019 and 2018.
New Accounting Standards and Disclosure Requirements
Leases — On January 1, 2019, we adopted Accounting Standards Update 2016-02, “Leases” (“Topic 842”). The comprehensive new lease standard superseded all existing lease guidance. The standard requires that a lessee should recognize a right-of-use asset and a lease liability for substantially all operating leases based on the present value of the minimum rental payments. For lessors, the accounting for leases under Topic 842 remained substantially unchanged. The standard also requires expanded disclosures surrounding leases. We adopted the standards under Topic 842 using the modified retrospective method and elected a number of the practical expedients in our implementation of Topic 842. The key change that affected us relates to our accounting for operating leases for which we are the lessee that were historically off-balance sheet. The impact of adopting the standards resulted in the recognition of a right-of-use asset and lease obligation liability of $191 million on our Consolidated Condensed Balance Sheet on January 1, 2019, exclusive of previously recognized lease balances. The implementation of Topic 842 did not have a material effect on our Consolidated Condensed Statement of Operations or Consolidated Condensed Statement of Cash Flows for the three months ended March 31, 2019. See Note 3 for a discussion of the practical expedients we elected and additional disclosures required by Topic 842.
Derivatives and Hedging — In August 2017, the FASB issued Accounting Standards Update 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” The standard better aligns an entity’s hedging activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results in the financial statements. The standard will prospectively make hedge accounting easier to apply to hedging activities and also enhances disclosure requirements for how hedge transactions are reflected in the financial statements when hedge accounting is elected. We adopted Accounting Standards Update 2017-12 in the first quarter of 2019 which did not have a material effect on our financial condition, results of operations or cash flows.
Fair Value Measurements — In August 2018, the FASB issued Accounting Standards Update 2018-13, “Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement.” The standard removes, modifies and adds disclosures about fair value measurements and is effective for fiscal years beginning after December 15, 2019. The changes required by this standard to remove or modify disclosures may be early adopted with adoption of the additional disclosures required by this standard delayed until their effective date. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.

v3.19.1
Revenue From Contracts with Customers (Notes)
 3 Months Ended
Mar. 31, 2019
Revenue from Contract with Customer [Abstract]  
Revenue from Contract with Customer [Text Block]
Revenue from Contracts with Customers
Disaggregation of Revenues with Customers

The following tables represent a disaggregation of our revenue for the three months ended March 31, 2019 and 2018 by reportable segment (in millions). See Note 13 for a description of our segments.
 
Three Months Ended March 31, 2019
 
Wholesale
 
 
 
 
 
 
 
West
 
Texas
 
East
 
Retail
 
Elimination
 
Total
Third Party:
 
 
 
 
 
 
 
 
 
 
 
Energy & other products
$
292

 
$
302

 
$
203

 
$
412

 
$
—

 
$
1,209

Capacity
35

 
32

 
177

 
—

 
—

 
244

Revenues relating to physical or executory contracts – third party
$
327

 
$
334

 
$
380

 
$
412

 
$
—

 
$
1,453

 
 
 
 
 
 
 
 
 
 
 
 
Affiliate(1):
$
11

 
$
14

 
$
27

 
$
3

 
$
(55
)
 
$
—

 
 
 
 
 
 
 
 
 
 
 
 
Revenues relating to leases and derivative instruments(2)
 
 
 
 
 
 
 
 
 
 
$
1,146

Total operating revenues
 
 
 
 
 
 
 
 
 
 
$
2,599



 
Three Months Ended March 31, 2018
 
Wholesale
 
 
 
 
 
 
 
West
 
Texas
 
East
 
Retail
 
Elimination
 
Total
Third Party:
 
 
 
 
 
 
 
 
 
 
 
Energy & other products
$
199

 
$
304

 
$
132

 
$
443

 
$
—

 
$
1,078

Capacity
19

 
26

 
149

 
—

 
—

 
194

Revenues relating to physical or executory contracts – third party
$
218

 
$
330

 
$
281

 
$
443

 
$
—

 
$
1,272

 
 
 
 
 
 
 
 
 
 
 
 
Affiliate(1):
$
8

 
$
4

 
$
21

 
$
1

 
$
(34
)
 
$
—

 
 
 
 
 
 
 
 
 
 
 
 
Revenues relating to leases and derivative instruments(2)
 
 
 
 
 
 
 
 
 
 
$
737

Total operating revenues
 
 
 
 
 
 
 
 
 
 
$
2,009

___________
(1)
Affiliate energy, other and capacity revenues reflect revenues on transactions between wholesale and retail affiliates excluding affiliate activity related to leases and derivative instruments. All such activity supports retail supply needs from the wholesale business and/or allows for collateral margin netting efficiencies at Calpine.
(2)
Revenues relating to contracts accounted for as leases and derivatives include energy and capacity revenues relating to PPAs that we are required to account for as operating leases and physical and financial commodity derivative contracts, primarily relating to power, natural gas and environmental products. Revenue related to derivative instruments includes revenue recorded in Commodity revenue and mark-to-market gain (loss) within our operating revenues on our Consolidated Condensed Statements of Operations.
Performance Obligations and Contract Balances
At March 31, 2019 and December 31, 2018, deferred revenue balances relating to contracts with our customers were included in other current liabilities on our Consolidated Condensed Balance Sheets and primarily relate to sales of environmental products and capacity. We classify deferred revenue as current or long-term based on the timing of when we expect to recognize revenue. The balance outstanding at March 31, 2019 and December 31, 2018 was $19 million and $14 million, respectively. The revenue recognized during the three months ended March 31, 2019 and 2018, relating to the deferred revenue balance at the beginning of each period was $2 million and $5 million, respectively, and resulted from our performance under the customer contracts. The change in the deferred revenue balance during the three months ended March 31, 2019 and 2018 was primarily due to the timing difference of when consideration was received and when the related good or service was transferred.
Performance Obligations not yet Satisfied
As of March 31, 2019, we have entered into certain contracts for fixed and determinable amounts with customers under which we have not yet completed our performance obligations which primarily includes agreements for which we are providing capacity from our generating facilities. We have revenues related to the sale of capacity through participation in various ISO capacity auctions estimated based upon cleared volumes and the sale of capacity to our customers of $430 million, $492 million, $441 million, $223 million and $47 million that will be recognized during the years ending December 31, 2019, 2020, 2021, 2022 and 2023, respectively, and $25 million thereafter. Revenues under these contracts will be recognized as we transfer control of the commodities to our customers.

v3.19.1
Leases (Notes)
 3 Months Ended
Mar. 31, 2019
Leases [Abstract]  
LesseeandLessorLeases [Text Block]
Leases
Accounting for Leases – Lessee
We evaluate contracts for lease accounting at contract inception and assess lease classification at the lease commencement date. For our leases, we recognize a right-of-use asset and corresponding lease obligation liability at the lease commencement date where the lease obligation liability is measured at the present value of the minimum lease payments. For our operating leases, the amortization of the right-of-use asset and the accretion of our lease obligation liability result in a single straight-line expense recognized over the lease term.
We determine the discount rate associated with our operating and finance leases using our incremental borrowing rate at lease commencement. For our operating leases, we use an interest rate commensurate with the interest rate to borrow on a collateralized basis over a similar term with an amount equal to the lease payments. Factors management considers in the calculation of the discount rate include the amount of the borrowing, the lease term including options that are reasonably certain of exercise, the current interest rate environment and the credit rating of the entity. For our finance leases, we use the interest rate commensurate with the interest rate for a project finance borrowing arrangement with a similar collateral package, repayment terms, restrictive covenants and guarantees.
Our operating leases are primarily related to office space for our corporate and regional offices as well as land and operating related leases for our power plants. Additionally, one of our power plants is accounted for as a long-term operating lease. Payments made by Calpine on this lease are recognized on a straight-line basis with capital improvements associated with our leased power plant deemed leasehold improvements that are amortized over the shorter of the term of the lease or the economic life of the capital improvement. Several of our leases contain renewal options held by us to extend the lease term. The inclusion of these renewal periods in the lease term and in the minimum lease payments included in our lease liabilities is dependent on specific facts and circumstances for each lease and whether it is determined to be reasonably certain that we will exercise our option to extend the term. Our office, land and other operating leases do not contain any material restrictive covenants or residual value guarantees.
We have entered into finance leases for certain power plants and related equipment with terms that range up to 37 years (including lease renewal options). The finance leases generally provide for the lessee to pay taxes, maintenance, insurance, and certain other operating costs of the leased property.
In connection with our adoption of Topic 842 on January 1, 2019, we elected certain practical expedients that were available under the new lease standards including:
•
we elected not to separate lease and nonlease components for our current classes of underlying leased assets as the lessee;
•
we did not evaluate existing and expired land easements that were not previously accounted for as leases prior to January 1, 2019; and
•
we did not reassess the classification of leases, the accounting for initial direct costs or whether contractual arrangements contained a lease for all contracts that expired or commenced prior to January 1, 2019.
Further, upon the adoption of Topic 842, we made an accounting policy election to not recognize lease assets and liabilities for leases with a term of 12 months or less. We do not have any material subleases associated with our operating and finance leases.
The components of our operating and finance lease expense are as follows for the period presented (in millions):
 
Three Months Ended March 31,
 
2019
Operating Leases
 
Operating lease expense
$
11

 
 
Finance Leases
 
Amortization of the right-of-use assets
$
3

Interest expense
2

Finance lease expense
$
5

 
 
Variable lease expense
$
1

 
 
Total lease expense
$
17


The following is a schedule by year of future minimum lease payments associated with our operating and finance leases together with the present value of the net minimum lease payments as of March 31, 2019 (in millions):
 
Operating Leases(1)
 
Finance Leases(2)
2019
$
44

 
$
12

2020
19

 
18

2021
19

 
18

2022
18

 
18

2023
17

 
21

Thereafter
191

 
72

Total minimum lease payments
308

 
159

Less: Amount representing interest
105

 
58

Total lease obligation
203

 
101

Less: current lease obligation
40

 
11

Long-term lease obligation
$
163

 
$
90

____________
(1)
The lease liabilities associated with our operating leases as of March 31, 2019 are included in other current liabilities and other long-term liabilities on our Consolidated Condensed Balance Sheet.
(2)
The lease liabilities associated with our finance leases as of March 31, 2019 are included in debt, current portion, current liabilities held for sale and debt, net of current portion on our Consolidated Condensed Balance Sheet.
Supplemental balance sheet information related to our operating and finance leases is as follows as of March 31, 2019 (in millions, except lease term and discount rate):
 
 
March 31, 2019
Operating leases(1)
 
 
Right-of-use assets associated with operating leases
 
$
182

 
 
 
Finance leases(2)
 
 
Property, plant and equipment, gross
 
$
390

Accumulated amortization
 
(177
)
Property, plant and equipment, net
 
$
213

 
 
 
Weighted average remaining lease term (in years)
 
 
Operating leases
 
15.7

Finance leases
 
12.1

 
 
 
Weighted average discount rate
 
 
Operating leases
 
5.3
%
Finance leases
 
7.5
%
____________
(1)
The right-of-use assets associated with our operating leases as of March 31, 2019 are included in other assets on our Consolidated Condensed Balance Sheet.
(2)
The right-of-use assets associated with our finance leases as of March 31, 2019 are included in current assets held for sale and property, plant and equipment, net on our Consolidated Condensed Balance Sheet.
We did not obtain any right-of-use assets in exchange for lease liabilities associated with operating or finance leases during the three months ended March 31, 2019. Supplemental cash flow information related to our operating and finance leases is as follows for the period presented (in millions):
 
Three Months Ended March 31,
 
2019
Cash paid for amounts included in the measurement of lease liabilities
 
Operating cash flows from operating leases
$
8

Operating cash flows from finance leases
$
2

Financing cash flows from finance leases
$
5


As of March 31, 2019, we have executed agreements that contain a lease with a future lease commencement date and future lease commitments of $1 million primarily related to an office lease which commences in September 2019.
Accounting for Leases – Lessor
We apply lease accounting to PPAs that meet the definition of a lease and determine lease classification treatment at commencement of the agreement. We currently do not have any contracts which are accounted for as sales-type leases or direct financing leases and all of our leases as the lessor are classified as operating leases. As part of the implementation of Topic 842, we elected the practical expedient to not reassess leases that have commenced prior to January 1, 2019.
Revenue from contracts accounted for as operating leases, such as certain tolling agreements, with minimum lease rentals (capacity payments) which vary over time must be levelized. Generally, we levelize these contract revenues on a straight-line basis over the term of the contract. Our operating leases that have commenced contain terms extending through December 2034. These contracts also generally contain variable payment components based on generation volumes or operating efficiency over a period of time. Revenues associated with the variable payments are recognized over time as the goods or services are provided to the lessee. Our operating leases generally do not contain renewal or purchase options or residual value guarantees. We have elected to not separate our lease and non-lease components as the lease components reflect the predominant characteristics of these agreements.
Revenue recognized related to fixed lease payments on our operating leases for the period presented is as follows (in millions):
 
Three Months Ended March 31,
 
2019
Operating Leases(1)
 
Fixed lease payments
$
69

____________
(1)
Revenues associated with our operating leases are included in Commodity revenue and other revenue on our Consolidated Condensed Statement of Operations.
The total contractual future minimum lease rentals for our contracts that have commenced and are accounted for as operating leases at March 31, 2019, are as follows (in millions):
2019
$
276

2020
265

2021
261

2022
226

2023
144

Thereafter
277

Total
$
1,449


We do not recognize lease receivables associated with our operating leases as the long-lived assets related to the power plants subject to the tolling contracts are recorded on our Consolidated Condensed Balance Sheets and are being depreciated over their estimated useful lives. Amounts recorded on our Consolidated Condensed Balance Sheet associated with the long-lived assets subject to our operating leases as of March 31, 2019 are as follows (in millions):
 
March 31, 2019
Power plants subject to tolling contracts accounted for as operating leases
 
Property, plant and equipment, gross
$
3,055

Accumulated depreciation
(880
)
Property, plant and equipment, net
$
2,175


We also record lease levelization assets and liabilities for any difference between the timing of the contractual payments made related to our tolling contracts and revenue recognized on a straight-line basis. These balances are included in current and long-term assets and liabilities on our Consolidated Condensed Balance Sheet.
Disclosures for periods prior to the adoption of Topic 842
Lessee    
The following is a schedule by year of future minimum lease payments under operating and capital leases as of December 31, 2018 (in millions):
 
Operating Leases
 
Capital Leases(1)
2019
$
50

 
$
40

2020
19

 
40

2021
20

 
38

2022
18

 
33

2023
17

 
27

Thereafter
192

 
92

Total minimum lease payments
$
316

 
270

Less: Amount representing interest
 
 
89

Present value of net minimum lease payments
 
 
$
181

____________
(1)
Includes a failed sale-leaseback transaction related to our Pasadena Power Plant.
At December 31, 2018, the asset balance for our assets under capital leases totaled approximately $715 million with accumulated amortization of $353 million.
Lessor
The total contractual future minimum lease rentals for our contracts accounted for as operating leases at December 31, 2018, are as follows (in millions):
2019
$
342

2020
261

2021
257

2022
224

2023
141

Thereafter
239

Total
$
1,464

v3.19.1
Divestitures (Notes)
 3 Months Ended
Mar. 31, 2019
Business Combinations [Abstract]  
Mergers, Acquisitions and Dispositions Disclosures [Text Block]
Sale of Garrison Energy Center and RockGen Energy Center
On April 8, 2019, we, through our indirect, wholly-owned subsidiaries Calpine Holdings, LLC and Calpine Northbrook Project Holdings, LLC, entered into an agreement with Cobalt Power, L.L.C. to sell 100% of our ownership interests in Garrison Energy Center LLC (“Garrison”) and RockGen Energy LLC (“RockGen”) for approximately $360 million, subject to certain working capital adjustments and the execution of contracts. Garrison is an indirect, wholly-owned subsidiary that owns the Garrison Energy Center, a 309 MW natural gas-fired, combined-cycle power plant located in Dover, Delaware and RockGen is an indirect, wholly-owned subsidiary that owns the RockGen Energy Center, a 503 MW natural gas-fired, simple-cycle power plant located in Christiana, Wisconsin. We expect the sale, which is subject to regulatory approvals, to close in the third quarter of 2019 and we will use the sale proceeds for our capital allocation activities and general corporate purposes.
At March 31, 2019, we have reclassified the assets and liabilities of Garrison Energy Center and RockGen Energy Center, which are part of our East segment, to current assets and liabilities held for sale on our Consolidated Condensed Balance Sheet consisting primarily of property, plant and equipment, net, and finance leases, respectively, and recorded an immaterial adjustment to the carrying value to reflect fair value less cost to sell.

v3.19.1
Variable Interest Entities and Unconsolidated Investments in Power Plants
 3 Months Ended
Mar. 31, 2019
Variable Interest Entities and Unconsolidated Investments [Abstract]  
Variable interest entities and unconsolidated investments in power plants
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 three months ended March 31, 2019. See Note 7 in our 2018 Form 10-K for further information regarding our VIEs.
VIE Disclosures
Our consolidated VIEs include natural gas-fired power plants with an aggregate capacity of 7,880 MW and 7,880 MW at March 31, 2019 and December 31, 2018, respectively. For these VIEs, we may provide other operational and administrative support through various affiliate contractual arrangements among the VIEs, Calpine Corporation and its other wholly-owned subsidiaries whereby we support the VIE through the reimbursement of costs and/or the purchase and sale of energy. Other than amounts contractually required, we provided support to these VIEs in the form of cash and other contributions of nil during each of the three months ended March 31, 2019 and 2018.
OMEC — OMEC has a ten-year tolling agreement with SDG&E which commenced on October 3, 2009. Under a ground lease agreement, OMEC held a put option to sell the Otay Mesa Energy Center for $280 million to SDG&E, pursuant to the terms and conditions of the agreement, which was exercisable until April 1, 2019 and SDG&E held a call option to purchase the Otay Mesa Energy Center for $377 million, which was exercisable through October 3, 2018. The call option held by SDG&E expired unexercised.
OMEC has executed a new 59-month Resource Adequacy (“RA”) contract with SDG&E which would commence on October 3, 2019. The RA contract received initial regulatory approval by the California Public Utilities Commission (“CPUC”) on February 21, 2019. This approval was subject to a 30 day appeal period from the date of the issuance of the CPUC decision. On March 27, 2019, an appeal of the CPUC decision was filed with the CPUC. We continue to work to commence the RA contract. However, in the event that we are not successful and another alternative is not reached with SDG&E prior to October 3, 2019, OMEC expects to close on the put and transfer the Otay Mesa Energy Center to SDG&E for $280 million on or about October 3, 2019, which transaction could result in a write down of the carrying value of the asset.
On December 19, 2018, we refinanced the project debt associated with OMEC which lowered the aggregate debt balance to $220 million and extended the maturity to August 2024. In the event that the exercise of the OMEC put option is not rescinded, the OMEC project debt will become payable on November 3, 2019.
We have concluded that we are the primary beneficiary of OMEC as we believe the activity that has the most effect on the financial performance of OMEC is operations and maintenance which is controlled by us. As a result, we consolidate OMEC.
Unconsolidated VIEs and Investments in Unconsolidated Subsidiaries
We have a 50% partnership interest in Greenfield LP and in Whitby. Greenfield LP and Whitby are VIEs; however, we do not have the power to direct the most significant activities of these entities and therefore do not consolidate them. Greenfield LP is a limited partnership between certain subsidiaries of ours and of Mitsui & Co., Ltd., which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant located in Ontario, Canada. We and Mitsui & Co., Ltd. each hold a 50% interest in Greenfield LP. Whitby is a limited partnership between certain of our subsidiaries and Atlantic Packaging Ltd., which operates the Whitby facility, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada. We and Atlantic Packaging Ltd. each hold a 50% partnership interest in Whitby.
Calpine Receivables is a VIE and a bankruptcy remote entity created for the special purpose of purchasing trade accounts receivable from Calpine Solutions under the Accounts Receivable Sales Program. We have determined that we do not have the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance nor the obligation to absorb losses or receive benefits from the VIE. Accordingly, we have determined that we are not the primary beneficiary of Calpine Receivables because we do not have the power to affect its financial performance as the unaffiliated financial institutions that purchase the receivables from Calpine Receivables control the selection criteria of the receivables sold and appoint the servicer of the receivables which controls management of default. Thus, we do not consolidate Calpine Receivables in our Consolidated Condensed Financial Statements and use the equity method of accounting to record our net interest in Calpine Receivables.
We account for these entities under the equity method of accounting and include our net equity interest in investments in unconsolidated subsidiaries on our Consolidated Condensed Balance Sheets. At March 31, 2019 and December 31, 2018, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):
 
Ownership Interest as of
March 31, 2019
 
March 31, 2019
 
December 31, 2018
Greenfield LP
50%
 
$
54

 
$
55

Whitby
50%
 
8

 
15

Calpine Receivables
100%
 
5

 
6

Total investments in unconsolidated subsidiaries
 
 
$
67

 
$
76


Our risk of loss related to our investments in Greenfield LP and Whitby is limited to our investment balance. Our risk of loss related to our investment in Calpine Receivables is $60 million which consists of our notes receivable from Calpine Receivables at March 31, 2019 and our initial investment associated with Calpine Receivables. See Note 12 for further information associated with our related party activity with Calpine Receivables.
Holders of the debt of our unconsolidated investments do not have recourse to Calpine Corporation and its other subsidiaries; therefore, the debt of our unconsolidated investments is not reflected on our Consolidated Condensed Balance Sheets. At March 31, 2019 and December 31, 2018, Greenfield LP’s debt was approximately $302 million and $301 million, respectively, and based on our pro rata share of our investment in Greenfield LP, our share of such debt would be approximately $151 million and $151 million at March 31, 2019 and December 31, 2018, respectively.
Our equity interest in the net income from our investments in unconsolidated subsidiaries for the three months ended March 31, 2019 and 2018, is recorded in (income) from unconsolidated subsidiaries. We did not have material income or receive any distributions from our investment in Calpine Receivables for the three months ended March 31, 2019 and 2018. The following table sets forth details of our (income) from unconsolidated subsidiaries for the periods indicated (in millions):
 
Three Months Ended March 31,
 
2019
 
2018
Greenfield LP
$
(2
)
 
$
(2
)
Whitby
(4
)
 
(4
)
Total
$
(6
)
 
$
(6
)
Distributions from Greenfield LP were nil during each of the three months ended March 31, 2019 and 2018. Distributions from Whitby were $11 million and $3 million during the three months ended March 31, 2019 and 2018, respectively.
Inland Empire Energy Center Put and Call Options — We held a call option to purchase the Inland Empire Energy Center (a 775 MW natural gas-fired power plant located in California) at predetermined prices from GE that could be exercised between years 2017 and 2024. GE held a put option whereby they could require us to purchase the power plant, if certain plant performance criteria were met by 2025. On February 1, 2019, we entered into an agreement with GE which, among other things, terminated our call option and GE’s put option related to the Inland Empire Energy Center. As per this agreement, we will take ownership of the facility site and certain remaining site infrastructure and equipment after closure and decommissioning of the facility at a future date, until such time GE continues to own, operate and maintain the power plant, including directing any closure activities. As GE continues to direct all such significant activities of the power plant, we have determined that we no longer hold any variable interests in the Inland Empire Energy Center and it is not a VIE to Calpine.

v3.19.1
Debt
 3 Months Ended
Mar. 31, 2019
Debt Disclosure [Abstract]  
Debt
Debt
Our debt at March 31, 2019 and December 31, 2018, was as follows (in millions):
 
March 31, 2019

December 31, 2018
Senior Unsecured Notes
$
2,989

 
$
3,036

First Lien Term Loans
2,972

 
2,976

First Lien Notes
2,401

 
2,400

Project financing, notes payable and other
1,228

 
1,264

CCFC Term Loan
972

 
974

Finance lease obligations
79

 
105

Corporate Revolving Facility
150

 
30

Subtotal
10,791

 
10,785

Less: Current maturities
258

 
637

Total long-term debt
$
10,533

 
$
10,148


Our effective interest rate on our consolidated debt, excluding the effects of capitalized interest and mark-to-market gains (losses) on interest rate hedging instruments, increased to 5.9% for the three months ended March 31, 2019, from 5.6% for the same period in 2018. Since the fourth quarter of 2018, we have cumulatively repurchased $438 million in aggregate principal of our Senior Unsecured Notes for $399 million.
Senior Unsecured Notes
The amounts outstanding under our Senior Unsecured Notes are summarized in the table below (in millions):
 
March 31, 2019
 
December 31, 2018
2023 Senior Unsecured Notes
$
1,228

 
$
1,227

2024 Senior Unsecured Notes
589

 
599

2025 Senior Unsecured Notes
1,172

 
1,210

Total Senior Unsecured Notes
$
2,989

 
$
3,036


During the three months ended March 31, 2019, we repurchased $48 million in aggregate principal of our Senior Unsecured Notes for $44 million. In connection with the repurchases, we recorded approximately $4 million in gain on extinguishment of debt.
First Lien Term Loans
The amounts outstanding under our senior secured First Lien Term Loans are summarized in the table below (in millions):
 
March 31, 2019
 
December 31, 2018
2019 First Lien Term Loan
$
389

 
$
389

2023 First Lien Term Loans
1,057

 
1,059

2024 First Lien Term Loan
1,526

 
1,528

Total First Lien Term Loans
$
2,972

 
$
2,976


On April 5, 2019, we entered into a $950 million first lien senior secured term loan which bears interest, at our option, at either (i) the Base Rate, equal to the highest of (a) the Federal Funds Effective Rate plus 0.50% per annum, (b) the Prime Rate or (c) the Eurodollar Rate for a one month interest period plus 1.0% (in each case, as such terms are defined in the credit agreement), plus an applicable margin of 1.75%, or (ii) LIBOR plus 2.75% per annum (with a 0% LIBOR floor) and matures on April 5, 2026. An aggregate amount equal to 0.25% of the aggregate principal amount of the 2026 First Lien Term Loan is payable at the end of each quarter with the remaining balance payable on the maturity date. We paid an upfront fee of an amount equal to 1.0% of the aggregate principal amount of the 2026 First Lien Term Loan, which is structured as original issue discount and expect to record approximately $7 million in debt issuance costs during the second quarter of 2019 related to the issuance of our 2026 First Lien Term Loan. The 2026 First Lien Term Loan contains substantially similar covenants, qualifications, exceptions and limitations as our First Lien Term Loans and First Lien Notes. We used the proceeds from our 2026 First Lien Term Loan to repay our 2019 First Lien Term Loan and a portion of our 2023 First Lien Term Loans with a maturity date in January 2023 and expect to record approximately $3 million in loss on extinguishment of debt during the second quarter of 2019 associated with the repayment.
First Lien Notes
The amounts outstanding under our senior secured First Lien Notes are summarized in the table below (in millions):
 
March 31, 2019
 
December 31, 2018
2022 First Lien Notes
$
744

 
$
743

2024 First Lien Notes
486

 
486

2026 First Lien Notes
1,171

 
1,171

Total First Lien Notes
$
2,401

 
$
2,400

Project Financing, Notes Payable and Other
On January 29, 2019, Pacific Gas and Electric Company (“PG&E”) and PG&E Corporation each filed voluntary petitions for relief under Chapter 11. Our power plants that sell energy and energy-related products to PG&E through PPAs, include Russell City Energy Center and Los Esteros Critical Energy Facility. As a result of PG&E’s bankruptcy, we are currently unable to make distributions from our Russell City and Los Esteros projects in accordance with the terms of the project debt agreements associated with each related project. If PG&E does not seek to assume our PPAs through their bankruptcy proceedings, unless otherwise modified, we will incur an event of default under the Russell City and Los Esteros project debt agreements 180 days after the date of PG&E’s bankruptcy filing. We continue to monitor the bankruptcy proceedings and are assessing our options. We plan to work with the lenders to determine a path forward. 
In the event that the exercise of the OMEC put option is not rescinded, the OMEC project debt will become payable on November 3, 2019. See Note 5 for further information related to the OMEC put option.
Corporate Revolving Facility and Other Letter of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at March 31, 2019 and December 31, 2018 (in millions):
 
March 31, 2019
 
December 31, 2018
Corporate Revolving Facility(1)
$
537

 
$
693

CDHI(2)
225

 
251

Various project financing facilities
243

 
228

Other corporate facilities(3)
196

 
193

Total
$
1,201

 
$
1,365

____________
(1)
The Corporate Revolving Facility represents our primary revolving facility. On April 5, 2019, we amended our Corporate Revolving Facility to increase the capacity by approximately $330 million from $1.69 billion to approximately $2.02 billion.
(2)
Pursuant to the terms and conditions of the CDHI credit agreement, the capacity under the CDHI letter of credit facility will be reduced to $125 million on June 30, 2019. The decrease in capacity will not have a material effect on our liquidity as alternative sources of liquidity are available.
(3)
We have two unsecured letter of credit facilities with third party financial institutions totaling $200 million at March 31, 2019. On May 6, 2019, we entered into a new unsecured letter of credit facility which increased the total capacity available to us by approximately $100 million.
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 March 31, 2019 and December 31, 2018 (in millions):
 
March 31, 2019
 
December 31, 2018
 
Fair Value
 
Carrying Value
 
Fair Value
 
Carrying Value
Senior Unsecured Notes
$
2,996

 
$
2,989

 
$
2,803

 
$
3,036

First Lien Term Loans
2,990

 
2,972

 
2,877

 
2,976

First Lien Notes
2,439

 
2,401

 
2,299

 
2,400

Project financing, notes payable and other(1)
1,132

 
1,152

 
1,209

 
1,188

CCFC Term Loan
975

 
972

 
938

 
974

Corporate Revolving Facility
150

 
150

 
30

 
30

Total
$
10,682

 
$
10,636

 
$
10,156

 
$
10,604

____________
(1)
Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.
Our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes, CCFC Term Loan and Corporate Revolving Facility are categorized as level 2 within the fair value hierarchy. Our project financing, notes payable and other debt instruments are categorized as level 3 within the fair value hierarchy. We do not have any debt instruments with fair value measurements categorized as level 1 within the fair value hierarchy.

v3.19.1
Assets and Liabilities with Recurring Fair Value Measurements
 3 Months Ended
Mar. 31, 2019
Fair Value Disclosures [Abstract]  
Assets and Liabilities with Recurring Fair Value Measurements
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, including the Black-Scholes option-pricing model, that incorporate various assumptions, including quoted interest rates, correlation, volatility, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Our level 3 fair value derivative instruments may consist of OTC power and natural gas forwards and options where pricing inputs are unobservable, as well as other complex and structured transactions primarily for the sale and purchase of power and natural gas to both wholesale counterparties and retail customers. Complex or structured transactions are tailored to our customers’ needs and can introduce the need for internally-developed model inputs which might not be observable in or corroborated by the market. When such inputs have a significant effect on the measurement of fair value, the instrument is categorized in level 3. Our valuation models may incorporate historical correlation information and extrapolate available broker and other information to future periods.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement at period end. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect our estimate of the fair value of our assets and liabilities and their placement within the fair value hierarchy levels. The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2019 and December 31, 2018, by level within the fair value hierarchy:
 
Assets and Liabilities with Recurring Fair Value Measures as of March 31, 2019
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
175

 
$
—

 
$
—

 
$
175

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded derivatives contracts
612

 
—

 
—

 
612

Commodity forward contracts(2)
—

 
343

 
218

 
561

Interest rate hedging instruments
—

 
23

 
—

 
23

Effect of netting and allocation of collateral(3)(4)
(612
)
 
(266
)
 
(17
)
 
(895
)
Total assets
$
175

 
$
100

 
$
201

 
$
476

Liabilities:
 
 
 
 
 
 
 
Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded derivatives contracts
$
688

 
$
—

 
$
—

 
$
688

Commodity forward contracts(2)
—

 
537

 
115

 
652

Interest rate hedging instruments
—

 
17

 
—

 
17

Effect of netting and allocation of collateral(3)(4)
(688
)
 
(313
)
 
(19
)
 
(1,020
)
Total liabilities
$
—

 
$
241

 
$
96

 
$
337

 
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2018
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
168

 
$
—

 
$
—

 
$
168

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded derivatives contracts
933

 
—

 
—

 
933

Commodity forward contracts(2)
—

 
338

 
212

 
550

Interest rate hedging instruments
—

 
40

 
—

 
40

Effect of netting and allocation of collateral(3)(4)
(933
)
 
(262
)
 
(26
)
 
(1,221
)
Total assets
$
168

 
$
116

 
$
186

 
$
470

Liabilities:
 
 
 
 
 
 
 
Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded derivatives contracts
$
932

 
$
—

 
$
—

 
$
932

Commodity forward contracts(2)
—

 
549

 
220

 
769

Interest rate hedging instruments
—

 
10

 
—

 
10

Effect of netting and allocation of collateral(3)(4)
(932
)
 
(310
)
 
(26
)
 
(1,268
)
Total liabilities
$
—

 
$
249

 
$
194

 
$
443

___________
(1)
At March 31, 2019 and December 31, 2018, we had cash equivalents of $19 million and $23 million included in cash and cash equivalents and $156 million and $145 million included in restricted cash, respectively.
(2)
Includes OTC swaps and options.
(3)
We offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation; therefore, amounts recognized for the right to reclaim, or the obligation to return, cash collateral are presented net with the corresponding derivative instrument fair values. See Note 8 for further discussion of our derivative instruments subject to master netting arrangements.
(4)
Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $76 million, $47 million and $2 million, respectively, at March 31, 2019. Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $(1) million, $48 million and nil, respectively, at December 31, 2018.
At March 31, 2019 and December 31, 2018, the derivative instruments classified as level 3 primarily included commodity contracts, which are classified as level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net derivative position classified as level 3 is predominantly driven by market commodity prices. The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at March 31, 2019 and December 31, 2018:
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
 
March 31, 2019
 
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
 
 
 
Power Contracts(1)
 
$
83

 
Discounted cash flow
 
Market price (per MWh)
 
$
2.20

—
$208.95
/MWh
Power Congestion Products
 
$
23

 
Discounted cash flow
 
Market price (per MWh)
 
$
(6.48
)
—
$8.24
/MWh
Natural Gas Contracts
 
$
(4
)
 
Discounted cash flow
 
Market price (per MMBtu)
 
$
0.03

—
$10.00
/MMBtu
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2018
 
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
 
 
 
Power Contracts(1)
 
$
36

 
Discounted cash flow
 
Market price (per MWh)
 
$
2.12

—
$227.98
/MWh
Power Congestion Products
 
$
26

 
Discounted cash flow
 
Market price (per MWh)
 
$
(11.71
)
—
$11.88
/MWh
Natural Gas Contracts
 
$
(73
)
 
Discounted cash flow
 
Market price (per MMBtu)
 
$
0.75

—
$8.87
/MMBtu

___________
(1)
Power contracts include power and heat rate instruments classified as level 3 in the fair value hierarchy.
The following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the periods indicated (in millions):
 
 
Three Months Ended March 31,
 
 
2019
 
2018
Balance, beginning of period
 
$
(8
)
 
$
197

Realized and mark-to-market gains (losses):
 
 
 
 
Included in net income (loss):
 
 
 
 
Included in operating revenues(1)
 
50

 
(57
)
Included in fuel and purchased energy expense(2)
 
2

 
(2
)
Change in collateral
 
2

 
(2
)
Purchases and settlements:
 
 
 
 
Purchases
 
2

 
4

Settlements
 
58

 
(14
)
Transfers in and/or out of level 3(3):
 
 
 
 
Transfers into level 3(4)
 
(1
)
 
6

Transfers out of level 3(5)
 
—

 
(3
)
Balance, end of period
 
$
105

 
$
129

Change in unrealized gains (losses) relating to instruments still held at end of period
 
$
52

 
$
(59
)
___________
(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 months ended March 31, 2019 and 2018.
(4)
We had $(1) million in losses and $6 million in gains transferred out of level 2 into level 3 for the three months ended March 31, 2019 and 2018, respectively, due to changes in market liquidity in various power markets.
(5)
We had nil and $3 million in gains transferred out of level 3 into level 2 for the three months ended March 31, 2019 and 2018, respectively, due to changes in market liquidity in various power markets.

v3.19.1
Derivative Instruments
 3 Months Ended
Mar. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Derivative Instruments
Derivative Instruments
Types of Derivative Instruments and Volumetric Information
Commodity Instruments — We are exposed to changes in prices for the purchase and sale of power, natural gas, fuel oil, environmental products and other energy commodities. We use derivatives, which include physical commodity contracts and financial commodity instruments such as OTC and exchange traded swaps, futures, options, forward agreements and instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) or instruments that settle on power or natural gas price relationships between delivery points for the purchase and sale of power and natural gas to attempt to maximize the risk-adjusted returns by economically hedging a portion of the commodity price risk associated with our assets. By entering into these transactions, we are able to economically hedge a portion of our Spark Spread at estimated generation and prevailing price levels.
We also engage in limited trading activities related to our commodity derivative portfolio as authorized by our Board of Directors and monitored by our Chief Risk Officer and Risk Management Committee of senior management. These transactions are executed primarily for the purpose of providing improved price and price volatility discovery, greater market access, and profiting from our market knowledge, all of which benefit our asset hedging activities. Our trading results were not material for each of the three months ended March 31, 2019 and 2018.
Interest Rate Hedging Instruments — A portion of our debt is indexed to base rates, primarily LIBOR. We have historically used interest rate hedging instruments to adjust the mix between fixed and variable rate debt to hedge our interest rate risk for potential adverse changes in interest rates. As of March 31, 2019, the maximum length of time over which we were hedging using interest rate hedging instruments designated as cash flow hedges was 7 years.
As of March 31, 2019 and December 31, 2018, the net forward notional buy (sell) position of our outstanding commodity derivative instruments that did not qualify or were not designated under the normal purchase normal sale exemption and our interest rate hedging instruments were as follows (in millions):
Derivative Instruments
 
Notional Amounts
 
 
March 31, 2019
 
December 31, 2018
 
Power (MWh)
 
(167
)
 
(161
)
 
Natural gas (MMBtu)
 
1,093

 
1,045

 
Environmental credits (Tonnes)
 
12

 
13

 
Interest rate hedging instruments
 
$
4,500

 
$
4,500

 

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 March 31, 2019, was $228 million for which we have posted collateral of $139 million by posting margin deposits, letters of credit or granting additional first priority liens on the assets currently subject to first priority liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. However, if our credit rating were downgraded by one notch from its current level, we estimate that additional collateral of $4 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 currently apply hedge accounting to our interest rate hedging instruments. We report the mark-to-market gain or loss on our interest rate hedging instruments designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Prior to January 1, 2019, gains and losses due to ineffectiveness on interest rate hedging instruments were recognized in earnings as a component of interest expense. Upon the adoption of Accounting Standards Update 2017-12 on January 1, 2019, hedge ineffectiveness is no longer separately measured and recorded in earnings. If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value 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 activity) and fuel and purchased energy expense (for physical and financial natural gas, power, environmental product and fuel oil activity). Changes in fair value of interest rate derivatives not designated as hedging instruments are recognized currently in earnings as interest expense.
Derivatives Included on Our Consolidated Condensed Balance Sheets
We offset fair value amounts associated with our derivative instruments and related cash collateral and margin deposits on our Consolidated Condensed Balance Sheets that are executed with the same counterparty under master netting arrangements. Our netting arrangements include a right to set off or net together purchases and sales of similar products in the margining or settlement process. In some instances, we have also negotiated cross commodity netting rights which allow for the net presentation of activity with a given counterparty regardless of product purchased or sold. We also post and/or receive cash collateral in support of our derivative instruments which may also be subject to a master netting arrangement with the same counterparty.
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 March 31, 2019 and December 31, 2018 (in millions):
 
 
March 31, 2019
 
 
Gross Amounts of Assets and (Liabilities)
 
Gross Amounts Offset on the Consolidated Condensed Balance Sheets
 
Net Amount Presented on the Consolidated Condensed Balance Sheets(1)
Derivative assets:
 
 
 
 
 
 
Commodity exchange traded derivatives contracts
 
$
513

 
$
(513
)
 
$
—

Commodity forward contracts
 
340

 
(223
)
 
117

Interest rate hedging instruments
 
19

 
—

 
19

Total current derivative assets(2)
 
$
872

 
$
(736
)
 
$
136

Commodity exchange traded derivatives contracts
 
99

 
(99
)
 
—

Commodity forward contracts
 
221

 
(58
)
 
163

Interest rate hedging instruments
 
4

 
(2
)
 
2

Total long-term derivative assets(2)
 
$
324

 
$
(159
)
 
$
165

Total derivative assets
 
$
1,196

 
$
(895
)
 
$
301

 
 
 
 
 
 
 
Derivative (liabilities):
 
 
 
 
 
 
Commodity exchange traded derivatives contracts
 
$
(528
)
 
$
528

 
$
—

Commodity forward contracts
 
(487
)
 
267

 
(220
)
Interest rate hedging instruments
 
(4
)
 
—

 
(4
)
Total current derivative (liabilities)(2)
 
$
(1,019
)
 
$
795

 
$
(224
)
Commodity exchange traded derivatives contracts
 
(160
)
 
160

 
—

Commodity forward contracts
 
(165
)
 
63

 
(102
)
Interest rate hedging instruments
 
(13
)
 
2

 
(11
)
Total long-term derivative (liabilities)(2)
 
$
(338
)
 
$
225

 
$
(113
)
Total derivative liabilities
 
$
(1,357
)
 
$
1,020

 
$
(337
)
Net derivative assets (liabilities)
 
$
(161
)
 
$
125

 
$
(36
)
 
 
December 31, 2018
 
 
Gross Amounts of Assets and (Liabilities)
 
Gross Amounts Offset on the Consolidated Condensed Balance Sheets
 
Net Amount Presented on the Consolidated Condensed Balance Sheets(1)
Derivative assets:
 
 
 
 
 
 
Commodity exchange traded derivatives contracts
 
$
820

 
$
(820
)
 
$
—

Commodity forward contracts
 
341

 
(229
)
 
112

Interest rate hedging instruments
 
30

 
—

 
30

Total current derivative assets(3)
 
$
1,191

 
$
(1,049
)
 
$
142

Commodity exchange traded derivatives contracts
 
113

 
(113
)
 
—

Commodity forward contracts
 
209

 
(59
)
 
150

Interest rate hedging instruments
 
10

 
—

 
10

Total long-term derivative assets(3)
 
$
332

 
$
(172
)
 
$
160

Total derivative assets
 
$
1,523

 
$
(1,221
)
 
$
302

 
 
 
 
 
 
 
Derivative (liabilities):
 
 
 
 
 
 
Commodity exchange traded derivatives contracts
 
$
(764
)
 
$
764

 
$
—

Commodity forward contracts
 
(576
)
 
277

 
(299
)
Interest rate hedging instruments
 
(4
)
 
—

 
(4
)
Total current derivative (liabilities)(3)
 
$
(1,344
)
 
$
1,041

 
$
(303
)
Commodity exchange traded derivatives contracts
 
(168
)
 
168

 
—

Commodity forward contracts
 
(193
)
 
59

 
(134
)
Interest rate hedging instruments
 
(6
)
 
—

 
(6
)
Total long-term derivative (liabilities)(3)
 
$
(367
)
 
$
227

 
$
(140
)
Total derivative liabilities
 
$
(1,711
)
 
$
1,268

 
$
(443
)
Net derivative assets (liabilities)
 
$
(188
)
 
$
47

 
$
(141
)
____________
(1)
At March 31, 2019 and December 31, 2018, we had $187 million and $244 million, respectively, of collateral under master netting arrangements that were not offset against our derivative instruments on the Consolidated Condensed Balance Sheets primarily related to initial margin requirements.
(2)
At March 31, 2019, current and long-term derivative assets are shown net of collateral of $(17) million and $(3) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $76 million and $69 million, respectively.
(3)
At December 31, 2018, current and long-term derivative assets are shown net of collateral of $(58) million and $(8) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $49 million and $64 million, respectively.
 
March 31, 2019
 
December 31, 2018
 
Fair Value
of Derivative
Assets
 
Fair Value
of Derivative
Liabilities
 
Fair Value
of Derivative
Assets
 
Fair Value
of Derivative
Liabilities
Derivatives designated as cash flow hedging instruments:
 
 
 
 
 
 
 
Interest rate hedging instruments
$
21

 
$
15

 
$
40

 
$
10

Total derivatives designated as cash flow hedging instruments
$
21

 
$
15

 
$
40

 
$
10

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity instruments
$
280

 
$
322

 
$
262

 
$
433

Total derivatives not designated as hedging instruments
$
280

 
$
322

 
$
262

 
$
433

Total derivatives
$
301

 
$
337

 
$
302

 
$
443


Derivatives Included on Our Consolidated Condensed Statements of Operations
Changes in the fair values of our derivative instruments are reflected either in cash for option premiums paid or collected, in OCI, net of tax, for derivative instruments which qualify for and we have elected cash flow hedge accounting treatment, or on our Consolidated Condensed Statements of Operations as a component of mark-to-market activity within our earnings.
The following tables detail the components of our total activity for both the net realized gain (loss) and the net mark-to-market gain (loss) recognized from our derivative instruments in earnings and where these components were recorded on our Consolidated Condensed Statements of Operations for the periods indicated (in millions):
 
Three Months Ended March 31,
 
2019
 
2018
Realized gain (loss)(1)(2)
 
 
 
Commodity derivative instruments
$
111

 
$
(3
)
Total realized gain (loss)
$
111

 
$
(3
)
 
 
 
 
Mark-to-market gain (loss)(3)
 
 
 
Commodity derivative instruments
$
46

 
$
(371
)
Interest rate hedging instruments
(1
)
 
2

Total mark-to-market gain (loss)
$
45

 
$
(369
)
Total activity, net
$
156

 
$
(372
)

___________
(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 adjustments to reflect changes in credit default risk exposure.
 
Three Months Ended March 31,
 
2019
 
2018
Realized and mark-to-market gain (loss)(1)
 
 
 
Derivatives contracts included in operating revenues(2)(3)
$
37

 
$
(359
)
Derivatives contracts included in fuel and purchased energy expense(2)(3)
120

 
(15
)
Interest rate hedging instruments included in interest expense
(1
)
 
2

Total activity, net
$
156

 
$
(372
)

___________
(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.
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 March 31,
 
Three Months Ended March 31,
 
Gain (Loss) Recognized in OCI
 
Gain (Loss) Reclassified from AOCI into Income(3)(4)
 
2019
 
2018
 
2019
 
2018
 
Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate hedging instruments(1)(2)
$
(25
)
 
$
54

 
$
2

 
$
(6
)
 
Interest expense
Interest rate hedging instruments(1)(2)
—

 
1

 
—

 
(1
)
 
Depreciation and amortization expense
Total
$
(25
)
 
$
55

 
$
2

 
$
(7
)
 
 
____________
(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 months ended March 31, 2018. Upon the adoption of Accounting Standards Update 2017-12 on January 1, 2019, hedge ineffectiveness is no longer separately measured and recorded in earnings.
(2)
We recorded an income tax expense of nil and $11 million for the three months ended March 31, 2019 and 2018, respectively, in AOCI related to our cash flow hedging activities.
(3)
Cumulative cash flow hedge gains (losses) attributable to Calpine, net of tax, remaining in AOCI were $59 million and $34 million at March 31, 2019 and December 31, 2018, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $3 million and $3 million at March 31, 2019 and December 31, 2018, respectively.
(4)
Includes losses of $1 million and nil that were reclassified from AOCI to interest expense for the three months ended March 31, 2019 and 2018, respectively, where the hedged transactions became probable of not occurring.
We estimate that pre-tax net losses of an immaterial amount 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.

v3.19.1
Use of Collateral
 3 Months Ended
Mar. 31, 2019
Use of Collateral [Abstract]  
Use of Collateral [Text Block]
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.
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 March 31, 2019 and December 31, 2018 (in millions):
 
March 31, 2019
 
December 31, 2018
Margin deposits(1)
$
448

 
$
343

Natural gas and power prepayments
32

 
31

Total margin deposits and natural gas and power prepayments with our counterparties(2)
$
480

 
$
374

 
 
 
 
Letters of credit issued
$
1,001

 
$
1,166

First priority liens under power and natural gas agreements
49

 
92

First priority liens under interest rate hedging instruments
11

 
10

Total letters of credit and first priority liens with our counterparties
$
1,061

 
$
1,268

 
 
 
 
Margin deposits posted with us by our counterparties(1)(3)
$
136

 
$
52

Letters of credit posted with us by our counterparties
36

 
27

Total margin deposits and letters of credit posted with us by our counterparties
$
172

 
$
79

___________
(1)
We offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation; therefore, amounts recognized for the right to reclaim, or the obligation to return, cash collateral are presented net with the corresponding derivative instrument fair values. See Note 8 for further discussion of our derivative instruments subject to master netting arrangements.
(2)
At March 31, 2019 and December 31, 2018, $135 million and $79 million, respectively, were included in current and long-term derivative assets and liabilities, $337 million and $286 million, respectively, were included in margin deposits and other prepaid expense and $8 million and $9 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.
(3)
At March 31, 2019 and December 31, 2018, $10 million and $32 million, respectively, were included in current and long-term derivative assets and liabilities, $85 million and $20 million, respectively, were included in other current liabilities and $41 million and nil, respectively, were included in other long-term liabilities on our Consolidated Condensed Balance Sheets.
Future collateral requirements for cash, first priority liens and letters of credit may increase or decrease based on the extent of our involvement in hedging and optimization contracts, movements in commodity prices, and also based on our credit ratings and general perception of creditworthiness in our market.

v3.19.1
Income Taxes
 3 Months Ended
Mar. 31, 2019
Income Tax Disclosure [Abstract]  
Income Taxes
Income Taxes
Income Tax Expense

The table below shows our consolidated income tax expense and our effective tax rates for the periods indicated (in millions):
 
Three Months Ended March 31,
 
2019
 
2018
Income tax expense
$
10

 
$
108

Effective tax rate
5
%
 
(22
)%

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 months ended March 31, 2019 and 2018, our income tax expense is largely comprised of discrete tax items and estimated state and foreign income taxes in jurisdictions where we do not have NOLs or valuation allowances.
Income Tax Audits — We remain subject to periodic audits and reviews by taxing authorities; however, we do not expect these audits will have a material effect on our tax provision. Any NOLs we claim in future years to reduce taxable income could be subject to IRS examination regardless of when the NOLs were generated. Any adjustment of state or federal returns could result in a reduction of deferred tax assets rather than a cash payment of income taxes in tax jurisdictions where we have NOLs. We are currently under various state income tax audits for various periods. Our Canadian subsidiaries are currently under examination by the Canada Revenue Agency for the years ended December 31, 2013 through 2016.
Valuation Allowance — U.S. GAAP requires that we consider all available evidence, both positive and negative, and tax planning strategies to determine whether, based on the weight of that evidence, a valuation allowance is needed to reduce the value of deferred tax assets. Future realization of the tax benefit of an existing deductible temporary difference or carryforward ultimately depends on the existence of sufficient taxable income of the appropriate character within the carryback or carryforward periods available under the tax law. Due to our history of losses, we were unable to assume future profits; however, we are able to consider available tax planning strategies.
Unrecognized Tax Benefits — At March 31, 2019, we had unrecognized tax benefits of $28 million. If recognized, $16 million of our unrecognized tax benefits could affect the annual effective tax rate and $12 million, related to deferred tax assets, could be offset against the recorded valuation allowance resulting in no effect on our effective tax rate. We had accrued interest and penalties of $2 million for income tax matters at March 31, 2019. We recognize interest and penalties related to unrecognized tax benefits in income tax expense on our Consolidated Condensed Statements of Operations. We believe that it is reasonably possible that a decrease within the range of nil and $8 million in unrecognized tax benefits could occur within the next twelve months primarily related to state tax issues.

v3.19.1
Commitments and Contingencies
 3 Months Ended
Mar. 31, 2019
Commitments and Contingencies Disclosure [Abstract]  
Commitments and Contingencies
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 March 31, 2019, there are no material outstanding claims related to our guarantee and indemnification obligations and we do not anticipate that we will be required to make any material payments under our guarantee and indemnification obligations. There have been no material changes to our guarantees and indemnifications from those disclosed in Note 16 of our 2018 Form 10-K.

v3.19.1
Related Party Transactions
 3 Months Ended
Mar. 31, 2019
Related Party Transactions [Abstract]  
Related Party Transactions Disclosure [Text Block]
Related Party Transactions
We have entered into various agreements with related parties associated with the operation of our business. A description of these related party transactions is provided below:
Calpine Receivables — Under the Accounts Receivable Sales Program, at March 31, 2019 and December 31, 2018, we had $256 million and $238 million, respectively, in trade accounts receivable outstanding that were sold to Calpine Receivables and $50 million and $34 million, respectively, in notes receivable from Calpine Receivables which were recorded on our Consolidated Condensed Balance Sheets. During the three months ended March 31, 2019 and 2018, we sold an aggregate of $597 million and $579 million, respectively, in trade accounts receivable and recorded $579 million and $573 million, respectively, in proceeds. For a further discussion of the Accounts Receivable Sales Program and Calpine Receivables, see Notes 7 and 17 in our 2018 Form 10-K.
Lyondell — We have a ground lease agreement with Houston Refining LP (“Houston Refining”), a subsidiary of Lyondell, for our Channel Energy Center site from which we sell power, capacity and steam to Houston Refining under a PPA. We purchase refinery gas and raw water from Houston Refining under a facilities services agreement. One of the entities which obtained an ownership interest in Calpine through the Merger which closed on March 8, 2018, also has an ownership interest in Lyondell whereby they may significantly influence the management and operating policies of Lyondell. The terms of the PPA with Lyondell were negotiated prior to the Merger closing. We recorded $20 million and $19 million in Commodity revenue during the three months ended March 31, 2019 and 2018, respectively, and $3 million and $2 million in Commodity expense during the three months ended March 31, 2019 and 2018, respectively, associated with this contract with Lyondell. At March 31, 2019 and December 31, 2018, the related party receivable and payable associated with this contract with Lyondell were immaterial.
Other — Following the Merger, we have identified other related party contracts for the sale of power, capacity and RECs which are entered into in the ordinary course of our business. Most of these contracts relate to the sale of commodities and capacity for varying tenors. The terms of most of these contracts were negotiated prior to the Merger. As of March 31, 2019 and December 31, 2018, the related party receivables and payables associated with these transactions were immaterial.

v3.19.1
Segment Information
 3 Months Ended
Mar. 31, 2019
Segment Reporting [Abstract]  
Segment Information
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 March 31, 2019, our geographic reportable segments for our wholesale business are West (including geothermal), Texas and East (including Canada) and we have a separate reportable segment for our retail business. We continue to evaluate the optimal manner in which we assess our performance including our segments and future changes may result in changes to the composition of our geographic segments.
Commodity Margin is a key operational measure of profit reviewed by our chief operating decision maker to assess the performance of our segments. The tables below show financial data for our segments (including a reconciliation of our Commodity Margin to income (loss) from operations by segment) for the periods indicated (in millions):
 
Three Months Ended March 31, 2019
 
Wholesale
 
 
 
Consolidation
 
 
 
West
 
Texas
 
East
 
Retail
 
Elimination
 
Total
Total operating revenues(1)
$
682

 
$
743

 
$
689

 
$
998

 
$
(513
)
 
$
2,599

 
 
 
 
 
 
 
 
 
 
 
 
Commodity Margin
$
264

 
$
162

 
$
265

 
$
88

 
$
—

 
$
779

Add: Mark-to-market commodity activity, net and other(2)
56

 
44

 
13

 
(53
)
 
(8
)
 
52

Less:
 
 
 
 
 
 
 
 
 
 


Operating and maintenance expense
81

 
65

 
67

 
34

 
(8
)
 
239

Depreciation and amortization expense
73

 
45

 
43

 
13

 
—

 
174

General and other administrative expense
7

 
12

 
9

 
4

 
—

 
32

Other operating expenses
9

 
2

 
23

 
—

 
—

 
34

(Income) from unconsolidated subsidiaries
—

 
—

 
(6
)
 
—

 
—

 
(6
)
Income (loss) from operations
150

 
82

 
142

 
(16
)
 
—

 
358

Interest expense
 
 
 
 
 
 
 
 
 
 
149

Gain on extinguishment of debt and other (income) expense, net
 
 
 
 
 
 
 
 
 
 
19

Income before income taxes
 
 
 
 
 
 
 
 
 
 
$
190

 
Three Months Ended March 31, 2018
 
Wholesale
 
 
 
Consolidation
 
 
 
West
 
Texas
 
East
 
Retail
 
Elimination
 
Total
Total operating revenues(1)
$
480

 
$
140

 
$
614

 
$
938

 
$
(163
)
 
$
2,009

 
 
 
 
 
 
 
 
 
 
 
 
Commodity Margin
$
185

 
$
166

 
$
184

 
$
77

 
$
—

 
$
612

Add: Mark-to-market commodity activity, net and other(2)
13

 
(547
)
 
40

 
128

 
(7
)
 
(373
)
Less:
 
 
 
 
 
 
 
 
 
 
 
Operating and maintenance expense
90

 
80

 
71

 
40

 
(6
)
 
275

Depreciation and amortization expense
67

 
76

 
45

 
13

 
—

 
201

General and other administrative expense
16

 
25

 
15

 
4

 
—

 
60

Other operating expenses
14

 
16

 
7

 
—

 
—

 
37

(Income) from unconsolidated subsidiaries
—

 
—

 
(6
)
 
—

 
—

 
(6
)
Income (loss) from operations
11


(578
)
 
92

 
148

 
(1
)
 
(328
)
Interest expense
 
 
 
 
 
 
 
 
 
 
151

Other (income) expense, net
 
 
 
 
 
 
 
 
 
 
7

Loss before income taxes
 
 
 
 
 
 
 
 
 
 
$
(486
)
_________
(1)
Includes intersegment revenues of $162 million and $114 million in the West, $211 million and $(67) million in Texas, $137 million and $115 million in the East and $3 million and $1 million in Retail for the three months ended March 31, 2019 and 2018, respectively.
(2)
Includes $(16) million and $(16) million of lease levelization and $21 million and $28 million of amortization expense for the three months ended March 31, 2019 and 2018, respectively.

v3.19.1
Basis of Presentation and Summary of Significant Accounting Policies (Policies)
 3 Months Ended
Mar. 31, 2019
Accounting Policies [Abstract]  
Basis of interim presentation
Basis of Interim Presentation — The accompanying unaudited, interim Consolidated Condensed Financial Statements of Calpine Corporation, a Delaware corporation, and consolidated subsidiaries have been prepared pursuant to the rules and regulations of the SEC. In the opinion of management, the Consolidated Condensed Financial Statements include the normal, recurring adjustments necessary for a fair statement of the information required to be set forth therein. Certain information and note disclosures, normally included in financial statements prepared in accordance with U.S. GAAP, have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, these financial statements should be read in conjunction with our audited Consolidated Financial Statements for the year ended December 31, 2018, included in our 2018 Form 10-K. The results for interim periods are not indicative of the results for the entire year primarily due to acquisitions and disposals of assets, seasonal fluctuations in our revenues and expenses, timing of major maintenance expense, variations resulting from the application of the method to calculate the provision for income tax for interim periods, volatility of commodity prices and mark-to-market gains and losses from commodity and interest rate derivative contracts.
Use of estimates in preparation of financial statements
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.
Reclassification, Policy [Policy Text Block]
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
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
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.
New accounting pronouncements, policy
Leases — On January 1, 2019, we adopted Accounting Standards Update 2016-02, “Leases” (“Topic 842”). The comprehensive new lease standard superseded all existing lease guidance. The standard requires that a lessee should recognize a right-of-use asset and a lease liability for substantially all operating leases based on the present value of the minimum rental payments. For lessors, the accounting for leases under Topic 842 remained substantially unchanged. The standard also requires expanded disclosures surrounding leases. We adopted the standards under Topic 842 using the modified retrospective method and elected a number of the practical expedients in our implementation of Topic 842. The key change that affected us relates to our accounting for operating leases for which we are the lessee that were historically off-balance sheet. The impact of adopting the standards resulted in the recognition of a right-of-use asset and lease obligation liability of $191 million on our Consolidated Condensed Balance Sheet on January 1, 2019, exclusive of previously recognized lease balances. The implementation of Topic 842 did not have a material effect on our Consolidated Condensed Statement of Operations or Consolidated Condensed Statement of Cash Flows for the three months ended March 31, 2019. See Note 3 for a discussion of the practical expedients we elected and additional disclosures required by Topic 842.
Derivatives and Hedging — In August 2017, the FASB issued Accounting Standards Update 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” The standard better aligns an entity’s hedging activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results in the financial statements. The standard will prospectively make hedge accounting easier to apply to hedging activities and also enhances disclosure requirements for how hedge transactions are reflected in the financial statements when hedge accounting is elected. We adopted Accounting Standards Update 2017-12 in the first quarter of 2019 which did not have a material effect on our financial condition, results of operations or cash flows.
Fair Value Measurements — In August 2018, the FASB issued Accounting Standards Update 2018-13, “Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement.” The standard removes, modifies and adds disclosures about fair value measurements and is effective for fiscal years beginning after December 15, 2019. The changes required by this standard to remove or modify disclosures may be early adopted with adoption of the additional disclosures required by this standard delayed until their effective date. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.
Lessee, Leases [Policy Text Block]
Accounting for Leases – Lessee
We evaluate contracts for lease accounting at contract inception and assess lease classification at the lease commencement date. For our leases, we recognize a right-of-use asset and corresponding lease obligation liability at the lease commencement date where the lease obligation liability is measured at the present value of the minimum lease payments. For our operating leases, the amortization of the right-of-use asset and the accretion of our lease obligation liability result in a single straight-line expense recognized over the lease term.
We determine the discount rate associated with our operating and finance leases using our incremental borrowing rate at lease commencement. For our operating leases, we use an interest rate commensurate with the interest rate to borrow on a collateralized basis over a similar term with an amount equal to the lease payments. Factors management considers in the calculation of the discount rate include the amount of the borrowing, the lease term including options that are reasonably certain of exercise, the current interest rate environment and the credit rating of the entity. For our finance leases, we use the interest rate commensurate with the interest rate for a project finance borrowing arrangement with a similar collateral package, repayment terms, restrictive covenants and guarantees.
Our operating leases are primarily related to office space for our corporate and regional offices as well as land and operating related leases for our power plants. Additionally, one of our power plants is accounted for as a long-term operating lease. Payments made by Calpine on this lease are recognized on a straight-line basis with capital improvements associated with our leased power plant deemed leasehold improvements that are amortized over the shorter of the term of the lease or the economic life of the capital improvement. Several of our leases contain renewal options held by us to extend the lease term. The inclusion of these renewal periods in the lease term and in the minimum lease payments included in our lease liabilities is dependent on specific facts and circumstances for each lease and whether it is determined to be reasonably certain that we will exercise our option to extend the term. Our office, land and other operating leases do not contain any material restrictive covenants or residual value guarantees.
We have entered into finance leases for certain power plants and related equipment with terms that range up to 37 years (including lease renewal options). The finance leases generally provide for the lessee to pay taxes, maintenance, insurance, and certain other operating costs of the leased property.
In connection with our adoption of Topic 842 on January 1, 2019, we elected certain practical expedients that were available under the new lease standards including:
•
we elected not to separate lease and nonlease components for our current classes of underlying leased assets as the lessee;
•
we did not evaluate existing and expired land easements that were not previously accounted for as leases prior to January 1, 2019; and
•
we did not reassess the classification of leases, the accounting for initial direct costs or whether contractual arrangements contained a lease for all contracts that expired or commenced prior to January 1, 2019.
Further, upon the adoption of Topic 842, we made an accounting policy election to not recognize lease assets and liabilities for leases with a term of 12 months or less. We do not have any material subleases associated with our operating and finance leases.
Lessor, Leases [Policy Text Block]
Accounting for Leases – Lessor
We apply lease accounting to PPAs that meet the definition of a lease and determine lease classification treatment at commencement of the agreement. We currently do not have any contracts which are accounted for as sales-type leases or direct financing leases and all of our leases as the lessor are classified as operating leases. As part of the implementation of Topic 842, we elected the practical expedient to not reassess leases that have commenced prior to January 1, 2019.
Revenue from contracts accounted for as operating leases, such as certain tolling agreements, with minimum lease rentals (capacity payments) which vary over time must be levelized. Generally, we levelize these contract revenues on a straight-line basis over the term of the contract. Our operating leases that have commenced contain terms extending through December 2034. These contracts also generally contain variable payment components based on generation volumes or operating efficiency over a period of time. Revenues associated with the variable payments are recognized over time as the goods or services are provided to the lessee. Our operating leases generally do not contain renewal or purchase options or residual value guarantees. We have elected to not separate our lease and non-lease components as the lease components reflect the predominant characteristics of these agreements.
Consolidation, Variable Interest Entity, Policy [Policy Text Block]
We have a 50% partnership interest in Greenfield LP and in Whitby. Greenfield LP and Whitby are VIEs; however, we do not have the power to direct the most significant activities of these entities and therefore do not consolidate them. Greenfield LP is a limited partnership between certain subsidiaries of ours and of Mitsui & Co., Ltd., which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant located in Ontario, Canada. We and Mitsui & Co., Ltd. each hold a 50% interest in Greenfield LP. Whitby is a limited partnership between certain of our subsidiaries and Atlantic Packaging Ltd., which operates the Whitby facility, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada. We and Atlantic Packaging Ltd. each hold a 50% partnership interest in Whitby.
Calpine Receivables is a VIE and a bankruptcy remote entity created for the special purpose of purchasing trade accounts receivable from Calpine Solutions under the Accounts Receivable Sales Program. We have determined that we do not have the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance nor the obligation to absorb losses or receive benefits from the VIE. Accordingly, we have determined that we are not the primary beneficiary of Calpine Receivables because we do not have the power to affect its financial performance as the unaffiliated financial institutions that purchase the receivables from Calpine Receivables control the selection criteria of the receivables sold and appoint the servicer of the receivables which controls management of default. Thus, we do not consolidate Calpine Receivables in our Consolidated Condensed Financial Statements and use the equity method of accounting to record our net interest in Calpine Receivables.
We account for these entities under the equity method of accounting and include our net equity interest in investments in unconsolidated subsidiaries on our Consolidated Condensed Balance Sheets.
We consolidate all of our VIEs where we have determined that we are the primary beneficiary.
Fair Value of Financial Instruments, Policy [Policy Text Block]
Our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes, CCFC Term Loan and Corporate Revolving Facility are categorized as level 2 within the fair value hierarchy. Our project financing, notes payable and other debt instruments are categorized as level 3 within the fair value hierarchy. We do not have any debt instruments with fair value measurements categorized as level 1 within the fair value hierarchy.
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, including the Black-Scholes option-pricing model, that incorporate various assumptions, including quoted interest rates, correlation, volatility, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Our level 3 fair value derivative instruments may consist of OTC power and natural gas forwards and options where pricing inputs are unobservable, as well as other complex and structured transactions primarily for the sale and purchase of power and natural gas to both wholesale counterparties and retail customers. Complex or structured transactions are tailored to our customers’ needs and can introduce the need for internally-developed model inputs which might not be observable in or corroborated by the market. When such inputs have a significant effect on the measurement of fair value, the instrument is categorized in level 3. Our valuation models may incorporate historical correlation information and extrapolate available broker and other information to future periods.
Derivatives, Policy [Policy Text Block]
We offset fair value amounts associated with our derivative instruments and related cash collateral and margin deposits on our Consolidated Condensed Balance Sheets that are executed with the same counterparty under master netting arrangements. Our netting arrangements include a right to set off or net together purchases and sales of similar products in the margining or settlement process. In some instances, we have also negotiated cross commodity netting rights which allow for the net presentation of activity with a given counterparty regardless of product purchased or sold. We also post and/or receive cash collateral in support of our derivative instruments which may also be subject to a master netting arrangement with the same counterparty.
We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Condensed Statements of Operations until the period of delivery. Revenues and expenses derived from instruments that qualified for hedge accounting or represent an economic hedge are recorded in the same financial statement line item as the item being hedged. Hedge accounting requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We present the cash flows from our derivatives in the same category as the item being hedged (or economically hedged) within operating activities on our Consolidated Condensed Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows are classified within financing activities.
Cash Flow Hedges — We currently apply hedge accounting to our interest rate hedging instruments. We report the mark-to-market gain or loss on our interest rate hedging instruments designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Prior to January 1, 2019, gains and losses due to ineffectiveness on interest rate hedging instruments were recognized in earnings as a component of interest expense. Upon the adoption of Accounting Standards Update 2017-12 on January 1, 2019, hedge ineffectiveness is no longer separately measured and recorded in earnings. If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value 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 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.
Commitments and Contingencies, Policy [Policy Text Block]
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.

v3.19.1
Basis of Presentation and Summary of Significant Accounting Policies (Tables)
 3 Months Ended
Mar. 31, 2019
Accounting Policies [Abstract]  
Schedule of components of restricted cash
The table below represents the components of our restricted cash as of March 31, 2019 and December 31, 2018 (in millions):
 
March 31, 2019
 
December 31, 2018
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service
$
17

 
$
7

 
$
24

 
$
13

 
$
8

 
$
21

Construction/major maintenance
24

 
29

 
53

 
23

 
24

 
47

Security/project/insurance
203

 
31

 
234

 
120

 
—

 
120

Other
21

 
2

 
23

 
11

 
2

 
13

Total
$
265

 
$
69

 
$
334

 
$
167

 
$
34

 
$
201
Schedule of property, plant and equipment
Property, Plant and Equipment, Net — At March 31, 2019 and December 31, 2018, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
 
March 31, 2019
 
December 31, 2018
 
Depreciable Lives
Buildings, machinery and equipment
$
16,538

 
$
16,400

 
1.5
–
50
 Years
Geothermal properties
1,503

 
1,501

 
13
–
58
 Years
Other
264

 
286

 
3
–
50
 Years
 
18,305

 
18,187

 
 
 
 
 
Less: Accumulated depreciation
6,764

 
6,832

 
 
 
 
 
 
11,541

 
11,355

 
 
 
 
 
Land
121

 
121

 
 
 
 
 
Construction in progress
386

 
966

 
 
 
 
 
Property, plant and equipment, net
$
12,048

 
$
12,442

 
 
 
 
 

v3.19.1
Revenue From Contracts with Customers (Tables)
 3 Months Ended
Mar. 31, 2019
Revenue from Contract with Customer [Abstract]  
Disaggregation of Revenue [Table Text Block]
The following tables represent a disaggregation of our revenue for the three months ended March 31, 2019 and 2018 by reportable segment (in millions). See Note 13 for a description of our segments.
 
Three Months Ended March 31, 2019
 
Wholesale
 
 
 
 
 
 
 
West
 
Texas
 
East
 
Retail
 
Elimination
 
Total
Third Party:
 
 
 
 
 
 
 
 
 
 
 
Energy & other products
$
292

 
$
302

 
$
203

 
$
412

 
$
—

 
$
1,209

Capacity
35

 
32

 
177

 
—

 
—

 
244

Revenues relating to physical or executory contracts – third party
$
327

 
$
334

 
$
380

 
$
412

 
$
—

 
$
1,453

 
 
 
 
 
 
 
 
 
 
 
 
Affiliate(1):
$
11

 
$
14

 
$
27

 
$
3

 
$
(55
)
 
$
—

 
 
 
 
 
 
 
 
 
 
 
 
Revenues relating to leases and derivative instruments(2)
 
 
 
 
 
 
 
 
 
 
$
1,146

Total operating revenues
 
 
 
 
 
 
 
 
 
 
$
2,599



 
Three Months Ended March 31, 2018
 
Wholesale
 
 
 
 
 
 
 
West
 
Texas
 
East
 
Retail
 
Elimination
 
Total
Third Party:
 
 
 
 
 
 
 
 
 
 
 
Energy & other products
$
199

 
$
304

 
$
132

 
$
443

 
$
—

 
$
1,078

Capacity
19

 
26

 
149

 
—

 
—

 
194

Revenues relating to physical or executory contracts – third party
$
218

 
$
330

 
$
281

 
$
443

 
$
—

 
$
1,272

 
 
 
 
 
 
 
 
 
 
 
 
Affiliate(1):
$
8

 
$
4

 
$
21

 
$
1

 
$
(34
)
 
$
—

 
 
 
 
 
 
 
 
 
 
 
 
Revenues relating to leases and derivative instruments(2)
 
 
 
 
 
 
 
 
 
 
$
737

Total operating revenues
 
 
 
 
 
 
 
 
 
 
$
2,009

___________
(1)
Affiliate energy, other and capacity revenues reflect revenues on transactions between wholesale and retail affiliates excluding affiliate activity related to leases and derivative instruments. All such activity supports retail supply needs from the wholesale business and/or allows for collateral margin netting efficiencies at Calpine.
(2)
Revenues relating to contracts accounted for as leases and derivatives include energy and capacity revenues relating to PPAs that we are required to account for as operating leases and physical and financial commodity derivative contracts, primarily relating to power, natural gas and environmental products. Revenue related to derivative instruments includes revenue recorded in Commodity revenue and mark-to-market gain (loss) within our operating revenues on our Consolidated Condensed Statements of Operations.

v3.19.1
Leases (Tables)
 3 Months Ended
Mar. 31, 2019
Leases [Abstract]  
Lease, Cost [Table Text Block]
The components of our operating and finance lease expense are as follows for the period presented (in millions):
 
Three Months Ended March 31,
 
2019
Operating Leases
 
Operating lease expense
$
11

 
 
Finance Leases
 
Amortization of the right-of-use assets
$
3

Interest expense
2

Finance lease expense
$
5

 
 
Variable lease expense
$
1

 
 
Total lease expense
$
17
Lessee, Operating Lease, Liability, Maturity [Table Text Block]
The following is a schedule by year of future minimum lease payments associated with our operating and finance leases together with the present value of the net minimum lease payments as of March 31, 2019 (in millions):
 
Operating Leases(1)
 
Finance Leases(2)
2019
$
44

 
$
12

2020
19

 
18

2021
19

 
18

2022
18

 
18

2023
17

 
21

Thereafter
191

 
72

Total minimum lease payments
308

 
159

Less: Amount representing interest
105

 
58

Total lease obligation
203

 
101

Less: current lease obligation
40

 
11

Long-term lease obligation
$
163

 
$
90

____________
(1)
The lease liabilities associated with our operating leases as of March 31, 2019 are included in other current liabilities and other long-term liabilities on our Consolidated Condensed Balance Sheet.
(2)
The lease liabilities associated with our finance leases as of March 31, 2019 are included in debt, current portion, current liabilities held for sale and debt, net of current portion on our Consolidated Condensed Balance Sheet.
Finance Lease, Liability, Maturity [Table Text Block]
The following is a schedule by year of future minimum lease payments associated with our operating and finance leases together with the present value of the net minimum lease payments as of March 31, 2019 (in millions):
 
Operating Leases(1)
 
Finance Leases(2)
2019
$
44

 
$
12

2020
19

 
18

2021
19

 
18

2022
18

 
18

2023
17

 
21

Thereafter
191

 
72

Total minimum lease payments
308

 
159

Less: Amount representing interest
105

 
58

Total lease obligation
203

 
101

Less: current lease obligation
40

 
11

Long-term lease obligation
$
163

 
$
90

____________
(1)
The lease liabilities associated with our operating leases as of March 31, 2019 are included in other current liabilities and other long-term liabilities on our Consolidated Condensed Balance Sheet.
(2)
The lease liabilities associated with our finance leases as of March 31, 2019 are included in debt, current portion, current liabilities held for sale and debt, net of current portion on our Consolidated Condensed Balance Sheet.
Supplemental Balance Sheet Info Lessee [Table Text Block]
Supplemental balance sheet information related to our operating and finance leases is as follows as of March 31, 2019 (in millions, except lease term and discount rate):
 
 
March 31, 2019
Operating leases(1)
 
 
Right-of-use assets associated with operating leases
 
$
182

 
 
 
Finance leases(2)
 
 
Property, plant and equipment, gross
 
$
390

Accumulated amortization
 
(177
)
Property, plant and equipment, net
 
$
213

 
 
 
Weighted average remaining lease term (in years)
 
 
Operating leases
 
15.7

Finance leases
 
12.1

 
 
 
Weighted average discount rate
 
 
Operating leases
 
5.3
%
Finance leases
 
7.5
%
____________
(1)
The right-of-use assets associated with our operating leases as of March 31, 2019 are included in other assets on our Consolidated Condensed Balance Sheet.
(2)
The right-of-use assets associated with our finance leases as of March 31, 2019 are included in current assets held for sale and property, plant and equipment, net on our Consolidated Condensed Balance Sheet.
Supplemental Cash Flow Lessee [Table Text Block]
Supplemental cash flow information related to our operating and finance leases is as follows for the period presented (in millions):
 
Three Months Ended March 31,
 
2019
Cash paid for amounts included in the measurement of lease liabilities
 
Operating cash flows from operating leases
$
8

Operating cash flows from finance leases
$
2

Financing cash flows from finance leases
$
5
Lease Cost - Lessor [Table Text Block]
Revenue recognized related to fixed lease payments on our operating leases for the period presented is as follows (in millions):
 
Three Months Ended March 31,
 
2019
Operating Leases(1)
 
Fixed lease payments
$
69

____________
(1)
Revenues associated with our operating leases are included in Commodity revenue and other revenue on our Consolidated Condensed Statement of Operations.
 
March 31, 2019
Power plants subject to tolling contracts accounted for as operating leases
 
Property, plant and equipment, gross
$
3,055

Accumulated depreciation
(880
)
Property, plant and equipment, net
$
2,175
Lessor, Operating Lease, Payments to be Received, Maturity [Table Text Block]
The total contractual future minimum lease rentals for our contracts that have commenced and are accounted for as operating leases at March 31, 2019, are as follows (in millions):
2019
$
276

2020
265

2021
261

2022
226

2023
144

Thereafter
277

Total
$
1,449
Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block]
The following is a schedule by year of future minimum lease payments under operating and capital leases as of December 31, 2018 (in millions):
 
Operating Leases
 
Capital Leases(1)
2019
$
50

 
$
40

2020
19

 
40

2021
20

 
38

2022
18

 
33

2023
17

 
27

Thereafter
192

 
92

Total minimum lease payments
$
316

 
270

Less: Amount representing interest
 
 
89

Present value of net minimum lease payments
 
 
$
181

____________
(1)
Includes a failed sale-leaseback transaction related to our Pasadena Power Plant.
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]
The total contractual future minimum lease rentals for our contracts accounted for as operating leases at December 31, 2018, are as follows (in millions):
2019
$
342

2020
261

2021
257

2022
224

2023
141

Thereafter
239

Total
$
1,464

The following is a schedule by year of future minimum lease payments under operating and capital leases as of December 31, 2018 (in millions):
 
Operating Leases
 
Capital Leases(1)
2019
$
50

 
$
40

2020
19

 
40

2021
20

 
38

2022
18

 
33

2023
17

 
27

Thereafter
192

 
92

Total minimum lease payments
$
316

 
270

Less: Amount representing interest
 
 
89

Present value of net minimum lease payments
 
 
$
181

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

v3.19.1
Variable Interest Entities and Unconsolidated Investments in Power Plants (Tables)
 3 Months Ended
Mar. 31, 2019
Variable Interest Entities and Unconsolidated Investments [Abstract]  
Schedule of equity method investments
At March 31, 2019 and December 31, 2018, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):
 
Ownership Interest as of
March 31, 2019
 
March 31, 2019
 
December 31, 2018
Greenfield LP
50%
 
$
54

 
$
55

Whitby
50%
 
8

 
15

Calpine Receivables
100%
 
5

 
6

Total investments in unconsolidated subsidiaries
 
 
$
67

 
$
76
Income (loss) from unconsolidated investments in power plants
The following table sets forth details of our (income) from unconsolidated subsidiaries for the periods indicated (in millions):
 
Three Months Ended March 31,
 
2019
 
2018
Greenfield LP
$
(2
)
 
$
(2
)
Whitby
(4
)
 
(4
)
Total
$
(6
)
 
$
(6
)

v3.19.1
Debt (Tables)
 3 Months Ended
Mar. 31, 2019
Debt Disclosure [Abstract]  
Schedule of long-term debt instruments
Our debt at March 31, 2019 and December 31, 2018, was as follows (in millions):
 
March 31, 2019

December 31, 2018
Senior Unsecured Notes
$
2,989

 
$
3,036

First Lien Term Loans
2,972

 
2,976

First Lien Notes
2,401

 
2,400

Project financing, notes payable and other
1,228

 
1,264

CCFC Term Loan
972

 
974

Finance lease obligations
79

 
105

Corporate Revolving Facility
150

 
30

Subtotal
10,791

 
10,785

Less: Current maturities
258

 
637

Total long-term debt
$
10,533

 
$
10,148
Senior Unsecured Notes
The amounts outstanding under our Senior Unsecured Notes are summarized in the table below (in millions):
 
March 31, 2019
 
December 31, 2018
2023 Senior Unsecured Notes
$
1,228

 
$
1,227

2024 Senior Unsecured Notes
589

 
599

2025 Senior Unsecured Notes
1,172

 
1,210

Total Senior Unsecured Notes
$
2,989

 
$
3,036
First Lien Term Loans
The amounts outstanding under our senior secured First Lien Term Loans are summarized in the table below (in millions):
 
March 31, 2019
 
December 31, 2018
2019 First Lien Term Loan
$
389

 
$
389

2023 First Lien Term Loans
1,057

 
1,059

2024 First Lien Term Loan
1,526

 
1,528

Total First Lien Term Loans
$
2,972

 
$
2,976
First Lien Notes
The amounts outstanding under our senior secured First Lien Notes are summarized in the table below (in millions):
 
March 31, 2019
 
December 31, 2018
2022 First Lien Notes
$
744

 
$
743

2024 First Lien Notes
486

 
486

2026 First Lien Notes
1,171

 
1,171

Total First Lien Notes
$
2,401

 
$
2,400
Schedule of line of credit facilities
The table below represents amounts issued under our letter of credit facilities at March 31, 2019 and December 31, 2018 (in millions):
 
March 31, 2019
 
December 31, 2018
Corporate Revolving Facility(1)
$
537

 
$
693

CDHI(2)
225

 
251

Various project financing facilities
243

 
228

Other corporate facilities(3)
196

 
193

Total
$
1,201

 
$
1,365

____________
(1)
The Corporate Revolving Facility represents our primary revolving facility. On April 5, 2019, we amended our Corporate Revolving Facility to increase the capacity by approximately $330 million from $1.69 billion to approximately $2.02 billion.
(2)
Pursuant to the terms and conditions of the CDHI credit agreement, the capacity under the CDHI letter of credit facility will be reduced to $125 million on June 30, 2019. The decrease in capacity will not have a material effect on our liquidity as alternative sources of liquidity are available.
(3)
We have two unsecured letter of credit facilities with third party financial institutions totaling $200 million at March 31, 2019. On May 6, 2019, we entered into a new unsecured letter of credit facility which increased the total capacity available to us by approximately $100 million.
Schedule of carrying values and estimated fair values of debt instruments
The following table details the fair values and carrying values of our debt instruments at March 31, 2019 and December 31, 2018 (in millions):
 
March 31, 2019
 
December 31, 2018
 
Fair Value
 
Carrying Value
 
Fair Value
 
Carrying Value
Senior Unsecured Notes
$
2,996

 
$
2,989

 
$
2,803

 
$
3,036

First Lien Term Loans
2,990

 
2,972

 
2,877

 
2,976

First Lien Notes
2,439

 
2,401

 
2,299

 
2,400

Project financing, notes payable and other(1)
1,132

 
1,152

 
1,209

 
1,188

CCFC Term Loan
975

 
972

 
938

 
974

Corporate Revolving Facility
150

 
150

 
30

 
30

Total
$
10,682

 
$
10,636

 
$
10,156

 
$
10,604

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

v3.19.1
Assets and Liabilities with Recurring Fair Value Measurements (Tables)
 3 Months Ended
Mar. 31, 2019
Fair Value Disclosures [Abstract]  
Fair Value, Measurement Inputs, Disclosure
The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2019 and December 31, 2018, by level within the fair value hierarchy:
 
Assets and Liabilities with Recurring Fair Value Measures as of March 31, 2019
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
175

 
$
—

 
$
—

 
$
175

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded derivatives contracts
612

 
—

 
—

 
612

Commodity forward contracts(2)
—

 
343

 
218

 
561

Interest rate hedging instruments
—

 
23

 
—

 
23

Effect of netting and allocation of collateral(3)(4)
(612
)
 
(266
)
 
(17
)
 
(895
)
Total assets
$
175

 
$
100

 
$
201

 
$
476

Liabilities:
 
 
 
 
 
 
 
Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded derivatives contracts
$
688

 
$
—

 
$
—

 
$
688

Commodity forward contracts(2)
—

 
537

 
115

 
652

Interest rate hedging instruments
—

 
17

 
—

 
17

Effect of netting and allocation of collateral(3)(4)
(688
)
 
(313
)
 
(19
)
 
(1,020
)
Total liabilities
$
—

 
$
241

 
$
96

 
$
337

 
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2018
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
168

 
$
—

 
$
—

 
$
168

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded derivatives contracts
933

 
—

 
—

 
933

Commodity forward contracts(2)
—

 
338

 
212

 
550

Interest rate hedging instruments
—

 
40

 
—

 
40

Effect of netting and allocation of collateral(3)(4)
(933
)
 
(262
)
 
(26
)
 
(1,221
)
Total assets
$
168

 
$
116

 
$
186

 
$
470

Liabilities:
 
 
 
 
 
 
 
Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded derivatives contracts
$
932

 
$
—

 
$
—

 
$
932

Commodity forward contracts(2)
—

 
549

 
220

 
769

Interest rate hedging instruments
—

 
10

 
—

 
10

Effect of netting and allocation of collateral(3)(4)
(932
)
 
(310
)
 
(26
)
 
(1,268
)
Total liabilities
$
—

 
$
249

 
$
194

 
$
443

___________
(1)
At March 31, 2019 and December 31, 2018, we had cash equivalents of $19 million and $23 million included in cash and cash equivalents and $156 million and $145 million included in restricted cash, respectively.
(2)
Includes OTC swaps and options.
(3)
We offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation; therefore, amounts recognized for the right to reclaim, or the obligation to return, cash collateral are presented net with the corresponding derivative instrument fair values. See Note 8 for further discussion of our derivative instruments subject to master netting arrangements.
(4)
Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $76 million, $47 million and $2 million, respectively, at March 31, 2019. Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $(1) million, $48 million and nil, respectively, at December 31, 2018.
Fair Value Inputs, Assets, Quantitative Information
The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at March 31, 2019 and December 31, 2018:
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
 
March 31, 2019
 
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
 
 
 
Power Contracts(1)
 
$
83

 
Discounted cash flow
 
Market price (per MWh)
 
$
2.20

—
$208.95
/MWh
Power Congestion Products
 
$
23

 
Discounted cash flow
 
Market price (per MWh)
 
$
(6.48
)
—
$8.24
/MWh
Natural Gas Contracts
 
$
(4
)
 
Discounted cash flow
 
Market price (per MMBtu)
 
$
0.03

—
$10.00
/MMBtu
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2018
 
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
 
 
 
Power Contracts(1)
 
$
36

 
Discounted cash flow
 
Market price (per MWh)
 
$
2.12

—
$227.98
/MWh
Power Congestion Products
 
$
26

 
Discounted cash flow
 
Market price (per MWh)
 
$
(11.71
)
—
$11.88
/MWh
Natural Gas Contracts
 
$
(73
)
 
Discounted cash flow
 
Market price (per MMBtu)
 
$
0.75

—
$8.87
/MMBtu

___________
(1)
Power contracts include power and heat rate instruments classified as level 3 in the fair value hierarchy.
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]
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 March 31,
 
 
2019
 
2018
Balance, beginning of period
 
$
(8
)
 
$
197

Realized and mark-to-market gains (losses):
 
 
 
 
Included in net income (loss):
 
 
 
 
Included in operating revenues(1)
 
50

 
(57
)
Included in fuel and purchased energy expense(2)
 
2

 
(2
)
Change in collateral
 
2

 
(2
)
Purchases and settlements:
 
 
 
 
Purchases
 
2

 
4

Settlements
 
58

 
(14
)
Transfers in and/or out of level 3(3):
 
 
 
 
Transfers into level 3(4)
 
(1
)
 
6

Transfers out of level 3(5)
 
—

 
(3
)
Balance, end of period
 
$
105

 
$
129

Change in unrealized gains (losses) relating to instruments still held at end of period
 
$
52

 
$
(59
)
___________
(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 months ended March 31, 2019 and 2018.
(4)
We had $(1) million in losses and $6 million in gains transferred out of level 2 into level 3 for the three months ended March 31, 2019 and 2018, respectively, due to changes in market liquidity in various power markets.
(5)
We had nil and $3 million in gains transferred out of level 3 into level 2 for the three months ended March 31, 2019 and 2018, respectively, due to changes in market liquidity in various power markets.

v3.19.1
Derivative Instruments (Tables)
 3 Months Ended
Mar. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Schedule of Notional Amounts of Outstanding Derivative Positions
As of March 31, 2019 and December 31, 2018, the net forward notional buy (sell) position of our outstanding commodity derivative instruments that did not qualify or were not designated under the normal purchase normal sale exemption and our interest rate hedging instruments were as follows (in millions):
Derivative Instruments
 
Notional Amounts
 
 
March 31, 2019
 
December 31, 2018
 
Power (MWh)
 
(167
)
 
(161
)
 
Natural gas (MMBtu)
 
1,093

 
1,045

 
Environmental credits (Tonnes)
 
12

 
13

 
Interest rate hedging instruments
 
$
4,500

 
$
4,500

 
Derivative Instruments Subject to Master Netting Arrangements [Table Text Block]
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 March 31, 2019 and December 31, 2018 (in millions):
 
 
March 31, 2019
 
 
Gross Amounts of Assets and (Liabilities)
 
Gross Amounts Offset on the Consolidated Condensed Balance Sheets
 
Net Amount Presented on the Consolidated Condensed Balance Sheets(1)
Derivative assets:
 
 
 
 
 
 
Commodity exchange traded derivatives contracts
 
$
513

 
$
(513
)
 
$
—

Commodity forward contracts
 
340

 
(223
)
 
117

Interest rate hedging instruments
 
19

 
—

 
19

Total current derivative assets(2)
 
$
872

 
$
(736
)
 
$
136

Commodity exchange traded derivatives contracts
 
99

 
(99
)
 
—

Commodity forward contracts
 
221

 
(58
)
 
163

Interest rate hedging instruments
 
4

 
(2
)
 
2

Total long-term derivative assets(2)
 
$
324

 
$
(159
)
 
$
165

Total derivative assets
 
$
1,196

 
$
(895
)
 
$
301

 
 
 
 
 
 
 
Derivative (liabilities):
 
 
 
 
 
 
Commodity exchange traded derivatives contracts
 
$
(528
)
 
$
528

 
$
—

Commodity forward contracts
 
(487
)
 
267

 
(220
)
Interest rate hedging instruments
 
(4
)
 
—

 
(4
)
Total current derivative (liabilities)(2)
 
$
(1,019
)
 
$
795

 
$
(224
)
Commodity exchange traded derivatives contracts
 
(160
)
 
160

 
—

Commodity forward contracts
 
(165
)
 
63

 
(102
)
Interest rate hedging instruments
 
(13
)
 
2

 
(11
)
Total long-term derivative (liabilities)(2)
 
$
(338
)
 
$
225

 
$
(113
)
Total derivative liabilities
 
$
(1,357
)
 
$
1,020

 
$
(337
)
Net derivative assets (liabilities)
 
$
(161
)
 
$
125

 
$
(36
)
 
 
December 31, 2018
 
 
Gross Amounts of Assets and (Liabilities)
 
Gross Amounts Offset on the Consolidated Condensed Balance Sheets
 
Net Amount Presented on the Consolidated Condensed Balance Sheets(1)
Derivative assets:
 
 
 
 
 
 
Commodity exchange traded derivatives contracts
 
$
820

 
$
(820
)
 
$
—

Commodity forward contracts
 
341

 
(229
)
 
112

Interest rate hedging instruments
 
30

 
—

 
30

Total current derivative assets(3)
 
$
1,191

 
$
(1,049
)
 
$
142

Commodity exchange traded derivatives contracts
 
113

 
(113
)
 
—

Commodity forward contracts
 
209

 
(59
)
 
150

Interest rate hedging instruments
 
10

 
—

 
10

Total long-term derivative assets(3)
 
$
332

 
$
(172
)
 
$
160

Total derivative assets
 
$
1,523

 
$
(1,221
)
 
$
302

 
 
 
 
 
 
 
Derivative (liabilities):
 
 
 
 
 
 
Commodity exchange traded derivatives contracts
 
$
(764
)
 
$
764

 
$
—

Commodity forward contracts
 
(576
)
 
277

 
(299
)
Interest rate hedging instruments
 
(4
)
 
—

 
(4
)
Total current derivative (liabilities)(3)
 
$
(1,344
)
 
$
1,041

 
$
(303
)
Commodity exchange traded derivatives contracts
 
(168
)
 
168

 
—

Commodity forward contracts
 
(193
)
 
59

 
(134
)
Interest rate hedging instruments
 
(6
)
 
—

 
(6
)
Total long-term derivative (liabilities)(3)
 
$
(367
)
 
$
227

 
$
(140
)
Total derivative liabilities
 
$
(1,711
)
 
$
1,268

 
$
(443
)
Net derivative assets (liabilities)
 
$
(188
)
 
$
47

 
$
(141
)
____________
(1)
At March 31, 2019 and December 31, 2018, we had $187 million and $244 million, respectively, of collateral under master netting arrangements that were not offset against our derivative instruments on the Consolidated Condensed Balance Sheets primarily related to initial margin requirements.
(2)
At March 31, 2019, current and long-term derivative assets are shown net of collateral of $(17) million and $(3) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $76 million and $69 million, respectively.
(3)
At December 31, 2018, current and long-term derivative assets are shown net of collateral of $(58) million and $(8) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $49 million and $64 million, respectively.
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value
 
March 31, 2019
 
December 31, 2018
 
Fair Value
of Derivative
Assets
 
Fair Value
of Derivative
Liabilities
 
Fair Value
of Derivative
Assets
 
Fair Value
of Derivative
Liabilities
Derivatives designated as cash flow hedging instruments:
 
 
 
 
 
 
 
Interest rate hedging instruments
$
21

 
$
15

 
$
40

 
$
10

Total derivatives designated as cash flow hedging instruments
$
21

 
$
15

 
$
40

 
$
10

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity instruments
$
280

 
$
322

 
$
262

 
$
433

Total derivatives not designated as hedging instruments
$
280

 
$
322

 
$
262

 
$
433

Total derivatives
$
301

 
$
337

 
$
302

 
$
443
Realized Unrealized Gain Loss by Instrument
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 March 31,
 
2019
 
2018
Realized gain (loss)(1)(2)
 
 
 
Commodity derivative instruments
$
111

 
$
(3
)
Total realized gain (loss)
$
111

 
$
(3
)
 
 
 
 
Mark-to-market gain (loss)(3)
 
 
 
Commodity derivative instruments
$
46

 
$
(371
)
Interest rate hedging instruments
(1
)
 
2

Total mark-to-market gain (loss)
$
45

 
$
(369
)
Total activity, net
$
156

 
$
(372
)

___________
(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 adjustments to reflect changes in credit default risk exposure.
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location
 
Three Months Ended March 31,
 
2019
 
2018
Realized and mark-to-market gain (loss)(1)
 
 
 
Derivatives contracts included in operating revenues(2)(3)
$
37

 
$
(359
)
Derivatives contracts included in fuel and purchased energy expense(2)(3)
120

 
(15
)
Interest rate hedging instruments included in interest expense
(1
)
 
2

Total activity, net
$
156

 
$
(372
)

___________
(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.
Derivatives Designated as Hedges
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 March 31,
 
Three Months Ended March 31,
 
Gain (Loss) Recognized in OCI
 
Gain (Loss) Reclassified from AOCI into Income(3)(4)
 
2019
 
2018
 
2019
 
2018
 
Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate hedging instruments(1)(2)
$
(25
)
 
$
54

 
$
2

 
$
(6
)
 
Interest expense
Interest rate hedging instruments(1)(2)
—

 
1

 
—

 
(1
)
 
Depreciation and amortization expense
Total
$
(25
)
 
$
55

 
$
2

 
$
(7
)
 
 
____________
(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 months ended March 31, 2018. Upon the adoption of Accounting Standards Update 2017-12 on January 1, 2019, hedge ineffectiveness is no longer separately measured and recorded in earnings.
(2)
We recorded an income tax expense of nil and $11 million for the three months ended March 31, 2019 and 2018, respectively, in AOCI related to our cash flow hedging activities.
(3)
Cumulative cash flow hedge gains (losses) attributable to Calpine, net of tax, remaining in AOCI were $59 million and $34 million at March 31, 2019 and December 31, 2018, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $3 million and $3 million at March 31, 2019 and December 31, 2018, respectively.
(4)
Includes losses of $1 million and nil that were reclassified from AOCI to interest expense for the three months ended March 31, 2019 and 2018, respectively, where the hedged transactions became probable of not occurring.

v3.19.1
Use of Collateral (Tables)
 3 Months Ended
Mar. 31, 2019
Use of Collateral [Abstract]  
Schedule of Collateral
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 March 31, 2019 and December 31, 2018 (in millions):
 
March 31, 2019
 
December 31, 2018
Margin deposits(1)
$
448

 
$
343

Natural gas and power prepayments
32

 
31

Total margin deposits and natural gas and power prepayments with our counterparties(2)
$
480

 
$
374

 
 
 
 
Letters of credit issued
$
1,001

 
$
1,166

First priority liens under power and natural gas agreements
49

 
92

First priority liens under interest rate hedging instruments
11

 
10

Total letters of credit and first priority liens with our counterparties
$
1,061

 
$
1,268

 
 
 
 
Margin deposits posted with us by our counterparties(1)(3)
$
136

 
$
52

Letters of credit posted with us by our counterparties
36

 
27

Total margin deposits and letters of credit posted with us by our counterparties
$
172

 
$
79

___________
(1)
We offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation; therefore, amounts recognized for the right to reclaim, or the obligation to return, cash collateral are presented net with the corresponding derivative instrument fair values. See Note 8 for further discussion of our derivative instruments subject to master netting arrangements.
(2)
At March 31, 2019 and December 31, 2018, $135 million and $79 million, respectively, were included in current and long-term derivative assets and liabilities, $337 million and $286 million, respectively, were included in margin deposits and other prepaid expense and $8 million and $9 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.
(3)
At March 31, 2019 and December 31, 2018, $10 million and $32 million, respectively, were included in current and long-term derivative assets and liabilities, $85 million and $20 million, respectively, were included in other current liabilities and $41 million and nil, respectively, were included in other long-term liabilities on our Consolidated Condensed Balance Sheets.

v3.19.1
Income Taxes Income Taxes (Tables)
 3 Months Ended
Mar. 31, 2019
Income Tax Disclosure [Abstract]  
Schedule of Components of Income Tax Expense (Benefit)
The table below shows our consolidated income tax expense and our effective tax rates for the periods indicated (in millions):
 
Three Months Ended March 31,
 
2019
 
2018
Income tax expense
$
10

 
$
108

Effective tax rate
5
%
 
(22
)%

v3.19.1
Segment Information (Tables)
 3 Months Ended
Mar. 31, 2019
Segment Reporting [Abstract]  
Schedule of Financial Data for Segments
The tables below show financial data for our segments (including a reconciliation of our Commodity Margin to income (loss) from operations by segment) for the periods indicated (in millions):
 
Three Months Ended March 31, 2019
 
Wholesale
 
 
 
Consolidation
 
 
 
West
 
Texas
 
East
 
Retail
 
Elimination
 
Total
Total operating revenues(1)
$
682

 
$
743

 
$
689

 
$
998

 
$
(513
)
 
$
2,599

 
 
 
 
 
 
 
 
 
 
 
 
Commodity Margin
$
264

 
$
162

 
$
265

 
$
88

 
$
—

 
$
779

Add: Mark-to-market commodity activity, net and other(2)
56

 
44

 
13

 
(53
)
 
(8
)
 
52

Less:
 
 
 
 
 
 
 
 
 
 


Operating and maintenance expense
81

 
65

 
67

 
34

 
(8
)
 
239

Depreciation and amortization expense
73

 
45

 
43

 
13

 
—

 
174

General and other administrative expense
7

 
12

 
9

 
4

 
—

 
32

Other operating expenses
9

 
2

 
23

 
—

 
—

 
34

(Income) from unconsolidated subsidiaries
—

 
—

 
(6
)
 
—

 
—

 
(6
)
Income (loss) from operations
150

 
82

 
142

 
(16
)
 
—

 
358

Interest expense
 
 
 
 
 
 
 
 
 
 
149

Gain on extinguishment of debt and other (income) expense, net
 
 
 
 
 
 
 
 
 
 
19

Income before income taxes
 
 
 
 
 
 
 
 
 
 
$
190

 
Three Months Ended March 31, 2018
 
Wholesale
 
 
 
Consolidation
 
 
 
West
 
Texas
 
East
 
Retail
 
Elimination
 
Total
Total operating revenues(1)
$
480

 
$
140

 
$
614

 
$
938

 
$
(163
)
 
$
2,009

 
 
 
 
 
 
 
 
 
 
 
 
Commodity Margin
$
185

 
$
166

 
$
184

 
$
77

 
$
—

 
$
612

Add: Mark-to-market commodity activity, net and other(2)
13

 
(547
)
 
40

 
128

 
(7
)
 
(373
)
Less:
 
 
 
 
 
 
 
 
 
 
 
Operating and maintenance expense
90

 
80

 
71

 
40

 
(6
)
 
275

Depreciation and amortization expense
67

 
76

 
45

 
13

 
—

 
201

General and other administrative expense
16

 
25

 
15

 
4

 
—

 
60

Other operating expenses
14

 
16

 
7

 
—

 
—

 
37

(Income) from unconsolidated subsidiaries
—

 
—

 
(6
)
 
—

 
—

 
(6
)
Income (loss) from operations
11


(578
)
 
92

 
148

 
(1
)
 
(328
)
Interest expense
 
 
 
 
 
 
 
 
 
 
151

Other (income) expense, net
 
 
 
 
 
 
 
 
 
 
7

Loss before income taxes
 
 
 
 
 
 
 
 
 
 
$
(486
)
_________
(1)
Includes intersegment revenues of $162 million and $114 million in the West, $211 million and $(67) million in Texas, $137 million and $115 million in the East and $3 million and $1 million in Retail for the three months ended March 31, 2019 and 2018, respectively.
(2)
Includes $(16) million and $(16) million of lease levelization and $21 million and $28 million of amortization expense for the three months ended March 31, 2019 and 2018, respectively.

v3.19.1
Basis of Presentation and Summary of Significant Accounting Policies (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2019
Mar. 31, 2018
Jan. 01, 2019
Dec. 31, 2018
Accounting Policies [Line Items]        
Operating Lease, Liability [1] $ 203      
Operating Lease, Right-of-Use Asset [2] 182      
Interest costs capitalized 7 $ 7    
Current 265     $ 167
Non-current 69     34
Total 334     201
Debt service        
Accounting Policies [Line Items]        
Current 17     13
Non-current 7     8
Total 24     21
Construction major maintenance        
Accounting Policies [Line Items]        
Current 24     23
Non-current 29     24
Total 53     47
Security project insurance        
Accounting Policies [Line Items]        
Current 203     120
Non-current 31     0
Total 234     120
Other        
Accounting Policies [Line Items]        
Current 21     11
Non-current 2     2
Total $ 23     $ 13
Accounting Standards Update 2016-02 [Member]        
Accounting Policies [Line Items]        
Operating Lease, Liability     $ 191  
Operating Lease, Right-of-Use Asset     $ 191  
[1] The lease liabilities associated with our operating leases as of March 31, 2019 are included in other current liabilities and other long-term liabilities on our Consolidated Condensed Balance Sheet.
[2] The right-of-use assets associated with our operating leases as of March 31, 2019 are included in other assets on our Consolidated Condensed Balance Sheet.

v3.19.1
Basis of Presentation and Summary of Significant Accounting Policies Property, Plant and Equipment, Net (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2019
Dec. 31, 2018
Property, Plant and Equipment [Line Items]    
Buildings, machinery and equipment $ 16,538 $ 16,400
Geothermal properties 1,503 1,501
Other 264 286
Property, plant and equipment, gross 18,305 18,187
Less: Accumulated depreciation 6,764 6,832
Property, plant and equipment, gross, less accumulated depreciation, depletion and amortization 11,541 11,355
Land 121 121
Construction in progress 386 966
Property, plant and equipment, net $ 12,048 $ 12,442
Minimum [Member] | Building, Machinery and Equipment, Gross [Member]    
Property, Plant and Equipment [Line Items]    
Property, plant and equipment, estimated useful lives 1 year 6 months  
Minimum [Member] | Geothermal Properties, Gross [Member]    
Property, Plant and Equipment [Line Items]    
Property, plant and equipment, estimated useful lives 13 years  
Minimum [Member] | Property, Plant and Equipment, Other Types [Member]    
Property, Plant and Equipment [Line Items]    
Property, plant and equipment, estimated useful lives 3 years  
Maximum [Member] | Building, Machinery and Equipment, Gross [Member]    
Property, Plant and Equipment [Line Items]    
Property, plant and equipment, estimated useful lives 50 years  
Maximum [Member] | Geothermal Properties, Gross [Member]    
Property, Plant and Equipment [Line Items]    
Property, plant and equipment, estimated useful lives 58 years  
Maximum [Member] | Property, Plant and Equipment, Other Types [Member]    
Property, Plant and Equipment [Line Items]    
Property, plant and equipment, estimated useful lives 50 years  

v3.19.1
Revenue From Contracts with Customers Disaggregation of Revenues (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2019
Mar. 31, 2018
Disaggregation of Revenue [Line Items]    
Commodity revenue $ 2,538 $ 2,396
Revenues [1] 2,599 2,009
West [Member]    
Disaggregation of Revenue [Line Items]    
Revenues [1] 682 480
Texas [Member]    
Disaggregation of Revenue [Line Items]    
Revenues [1] 743 140
East [Member]    
Disaggregation of Revenue [Line Items]    
Revenues [1] 689 614
Retail [Member]    
Disaggregation of Revenue [Line Items]    
Revenues [1] 998 938
Energy and Other Products [Member]    
Disaggregation of Revenue [Line Items]    
Commodity revenue 1,209 1,078
Energy and Other Products [Member] | West [Member]    
Disaggregation of Revenue [Line Items]    
Commodity revenue 292 199
Energy and Other Products [Member] | Texas [Member]    
Disaggregation of Revenue [Line Items]    
Commodity revenue 302 304
Energy and Other Products [Member] | East [Member]    
Disaggregation of Revenue [Line Items]    
Commodity revenue 203 132
Energy and Other Products [Member] | Retail [Member]    
Disaggregation of Revenue [Line Items]    
Commodity revenue 412 443
Energy and Other Products [Member] | Intersegment Eliminations [Member]    
Disaggregation of Revenue [Line Items]    
Commodity revenue 0 0
Capacity Revenue [Member]    
Disaggregation of Revenue [Line Items]    
Commodity revenue 244 194
Capacity Revenue [Member] | West [Member]    
Disaggregation of Revenue [Line Items]    
Commodity revenue 35 19
Capacity Revenue [Member] | Texas [Member]    
Disaggregation of Revenue [Line Items]    
Commodity revenue 32 26
Capacity Revenue [Member] | East [Member]    
Disaggregation of Revenue [Line Items]    
Commodity revenue 177 149
Capacity Revenue [Member] | Retail [Member]    
Disaggregation of Revenue [Line Items]    
Commodity revenue 0 0
Capacity Revenue [Member] | Intersegment Eliminations [Member]    
Disaggregation of Revenue [Line Items]    
Commodity revenue 0 0
Revenues Relating to Physical or Executory Contracts - Third Party [Member]    
Disaggregation of Revenue [Line Items]    
Commodity revenue 1,453 1,272
Revenues Relating to Physical or Executory Contracts - Third Party [Member] | West [Member]    
Disaggregation of Revenue [Line Items]    
Commodity revenue 327 218
Revenues Relating to Physical or Executory Contracts - Third Party [Member] | Texas [Member]    
Disaggregation of Revenue [Line Items]    
Commodity revenue 334 330
Revenues Relating to Physical or Executory Contracts - Third Party [Member] | East [Member]    
Disaggregation of Revenue [Line Items]    
Commodity revenue 380 281
Revenues Relating to Physical or Executory Contracts - Third Party [Member] | Retail [Member]    
Disaggregation of Revenue [Line Items]    
Commodity revenue 412 443
Revenues Relating to Physical or Executory Contracts - Third Party [Member] | Intersegment Eliminations [Member]    
Disaggregation of Revenue [Line Items]    
Commodity revenue 0 0
Affiliate Revenue [Member]    
Disaggregation of Revenue [Line Items]    
Commodity revenue [2] 0 0
Affiliate Revenue [Member] | West [Member]    
Disaggregation of Revenue [Line Items]    
Commodity revenue [2] 11 8
Affiliate Revenue [Member] | Texas [Member]    
Disaggregation of Revenue [Line Items]    
Commodity revenue [2] 14 4
Affiliate Revenue [Member] | East [Member]    
Disaggregation of Revenue [Line Items]    
Commodity revenue [2] 27 21
Affiliate Revenue [Member] | Retail [Member]    
Disaggregation of Revenue [Line Items]    
Commodity revenue [2] 3 1
Affiliate Revenue [Member] | Intersegment Eliminations [Member]    
Disaggregation of Revenue [Line Items]    
Commodity revenue [2] (55) (34)
Revenues Relating to Leases and Derivative Instruments [Member]    
Disaggregation of Revenue [Line Items]    
Revenues [3] $ 1,146 $ 737
[1] Includes intersegment revenues of $162 million and $114 million in the West, $211 million and $(67) million in Texas, $137 million and $115 million in the East and $3 million and $1 million in Retail for the three months ended March 31, 2019 and 2018, respectively.
[2] Affiliate energy, other and capacity revenues reflect revenues on transactions between wholesale and retail affiliates excluding affiliate activity related to leases and derivative instruments. All such activity supports retail supply needs from the wholesale business and/or allows for collateral margin netting efficiencies at Calpine.
[3] Revenues relating to contracts accounted for as leases and derivatives include energy and capacity revenues relating to PPAs that we are required to account for as operating leases and physical and financial commodity derivative contracts, primarily relating to power, natural gas and environmental products. Revenue related to derivative instruments includes revenue recorded in Commodity revenue and mark-to-market gain (loss) within our operating revenues on our Consolidated Condensed Statements of Operations.

v3.19.1
Revenue From Contracts with Customers Performance Obligations Not Yet Satisfied (Details) - Capacity Revenue [Member]
$ in Millions
Mar. 31, 2019
USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-04-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, Remaining Performance Obligation, Amount $ 430
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period 9 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, Remaining Performance Obligation, Amount $ 492
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, Remaining Performance Obligation, Amount $ 441
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, Remaining Performance Obligation, Amount $ 223
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, Remaining Performance Obligation, Amount $ 47
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Revenue, Remaining Performance Obligation, Amount $ 25
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period

v3.19.1
Revenue From Contracts with Customers Performance Obligations and Contract Balances (Details) - Environmental Credits [Member] - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2019
Mar. 31, 2018
Dec. 31, 2018
Disaggregation of Revenue [Line Items]      
Deferred Revenue, Current $ 19   $ 14
Deferred Revenue, Revenue Recognized $ 2 $ 5  

v3.19.1
Leases (Details) - USD ($)
$ in Millions
Mar. 31, 2019
Dec. 31, 2018
Capital Leased Assets, Gross   $ 715
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment $ 6,764 6,832
Lesse Operating Lease, Lease Not yet Commenced $ 1  
Lessee, Finance Lease, Renewal Term 37 years  
Assets Held under Capital Leases [Member]    
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment   $ 353

v3.19.1
Leases Future Minimum Lease Payments (Details)
$ in Millions
Mar. 31, 2019
USD ($)
Operating and Finance Leases [Abstract]  
Lessee, Operating Lease, Liability, Payments, Remainder of Fiscal Year $ 44 [1]
Finance Lease, Liability, Payments, Remainder of Fiscal Year 12 [2]
Lessee, Operating Lease, Liability, Payments, Due Year Two 19 [1]
Finance Lease, Liability, Payments, Due Year Two 18 [2]
Lessee, Operating Lease, Liability, Payments, Due Year Three 19 [1]
Finance Lease, Liability, Payments, Due Year Three 18 [2]
Lessee, Operating Lease, Liability, Payments, Due Year Four 18 [1]
Finance Lease, Liability, Payments, Due Year Four 18 [2]
Lessee, Operating Lease, Liability, Payments, Due Year Five 17 [1]
Finance Lease, Liability, Payments, Due Year Five 21 [2]
Lessee, Operating Lease, Liability, Payments, Due after Year Five 191 [1]
Finance Lease, Liability, Payments, Due after Year Five 72 [2]
Lessee, Operating Lease, Liability, Undiscounted Excess Amount 105 [1]
Finance Lease, Liability, Undiscounted Excess Amount 58 [2]
Operating Lease, Liability 203 [1]
Finance Lease, Liability 101 [2]
Operating Lease, Liability, Current 40 [1]
Lessee, Operating Lease, Liability, Payments, Due 308 [1]
Finance Lease, Liability, Current 11 [2]
Finance Lease, Liability, Payments, Due 159 [2]
Operating Lease, Liability, Noncurrent 163 [1]
Finance Lease, Liability, Noncurrent $ 90 [2]
[1] The lease liabilities associated with our operating leases as of March 31, 2019 are included in other current liabilities and other long-term liabilities on our Consolidated Condensed Balance Sheet.
[2] The lease liabilities associated with our finance leases as of March 31, 2019 are included in debt, current portion, current liabilities held for sale and debt, net of current portion on our Consolidated Condensed Balance Sheet.

v3.19.1
Leases Supplemental balance sheet information (Details)
$ in Millions
Mar. 31, 2019
USD ($)
Supplemental balance sheet information [Abstract]  
Operating Lease, Right-of-Use Asset $ 182 [1]
Finance Lease, Right-of-use Asset, Gross 390 [2]
Finance Lease, Right-of-use Asset, Accumulated Amortization (177) [2]
Finance Lease, Right-of-Use Asset $ 213 [2]
Operating Lease, Weighted Average Remaining Lease Term 15 years 7 months 28 days
Finance Lease, Weighted Average Remaining Lease Term 12 years 1 month 6 days
Operating Lease, Weighted Average Discount Rate, Percent 5.30%
Finance Lease, Weighted Average Discount Rate, Percent 7.50%
[1] The right-of-use assets associated with our operating leases as of March 31, 2019 are included in other assets on our Consolidated Condensed Balance Sheet.
[2] The right-of-use assets associated with our finance leases as of March 31, 2019 are included in current assets held for sale and property, plant and equipment, net on our Consolidated Condensed Balance Sheet.

v3.19.1
Leases Supplemental cash flow information (Details)
$ in Millions
 3 Months Ended
Mar. 31, 2019
USD ($)
Supplemental Cash Flow Information [Abstract]  
Operating Lease, Payments $ 8
Finance Lease, Interest Payment on Liability 2
Finance Lease, Principal Payments $ 5

v3.19.1
Leases Power plants subject to tolling contracts (Details)
$ in Millions
Mar. 31, 2019
USD ($)
Power plants subject to tolling contracts [Abstract]  
Property, Plant, and Equipment, Owned, Gross $ 3,055
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment, Excluding Capital Leased Assets (880)
Property, Plant and Equipment, Net, Excluding Capital Leased Assets $ 2,175

v3.19.1
Leases Schedule of Future Minimum Rental Payments for Operating Leases (Details)
$ in Millions
Dec. 31, 2018
USD ($)
Schedule of Future Minimum Rental Payments for Operating Leases [Abstract]  
Operating Leases, Future Minimum Payments Receivable, Current $ 342
Operating Leases, Future Minimum Payments Receivable, in Two Years 261
Operating Leases, Future Minimum Payments Receivable, in Three Years 257
Operating Leases, Future Minimum Payments Receivable, in Four Years 224
Operating Leases, Future Minimum Payments Receivable, in Five Years 141
Operating Leases, Future Minimum Payments Receivable, Thereafter 239
Operating Leases, Future Minimum Payments Receivable $ 1,464

v3.19.1
Leases Maturity of Operating Lease Liabilities (Details) - USD ($)
$ in Millions
Mar. 31, 2019
Dec. 31, 2018
Maturity of Operating Lease Liabilities [Abstract]    
Operating Leases, Future Minimum Payments Due, Next Twelve Months   $ 50
Capital Leases, Future Minimum Payments Due, Next Twelve Months [1]   40
Lessee, Operating Lease, Liability, Payments, Remainder of Fiscal Year [2] $ 44  
Finance Lease, Liability, Payments, Remainder of Fiscal Year [3] 12  
Lessee, Operating Lease, Liability, Payments, Due Year Two   19
Capital Leases, Future Minimum Payments Due in Two Years [1]   40
Finance Lease, Liability, Payments, Due Year Two [3] 18  
Operating Leases, Future Minimum Payments, Due in Three Years   20
Capital Leases, Future Minimum Payments Due in Three Years [1]   38
Lessee, Operating Lease, Liability, Payments, Due Year Three [2] 19  
Finance Lease, Liability, Payments, Due Year Three [3] 18  
Operating Leases, Future Minimum Payments, Due in Four Years   18
Capital Leases, Future Minimum Payments Due in Four Years [1]   33
Lessee, Operating Lease, Liability, Payments, Due Year Four [2] 18  
Finance Lease, Liability, Payments, Due Year Four [3] 18  
Operating Leases, Future Minimum Payments, Due in Five Years   17
Capital Leases, Future Minimum Payments Due in Five Years [1]   27
Lessee, Operating Lease, Liability, Payments, Due Year Five [2] 17  
Finance Lease, Liability, Payments, Due Year Five [3] 21  
Operating Leases, Future Minimum Payments, Due Thereafter   192
Capital Leases, Future Minimum Payments Due Thereafter [1]   92
Lessee, Operating Lease, Liability, Payments, Due after Year Five [2] 191  
Finance Lease, Liability, Payments, Due after Year Five [3] 72  
Operating Leases, Future Minimum Payments Due   316
Lessee, Operating Lease, Liability, Payments, Due [2] 308  
Finance Lease, Liability, Payments, Due [3] 159  
Finance Lease, Liability, Undiscounted Excess Amount [3] 58  
Finance Lease, Liability [3] $ 101  
Capital Leases, Future Minimum Payments Due [1]   270
Capital Leases, Future Minimum Payments, Interest Included in Payments [1]   89
Capital Leases, Future Minimum Payments, Present Value of Net Minimum Payments [1]   $ 181
[1] Includes a failed sale-leaseback transaction related to our Pasadena Power Plant.
[2] The lease liabilities associated with our operating leases as of March 31, 2019 are included in other current liabilities and other long-term liabilities on our Consolidated Condensed Balance Sheet.
[3] The lease liabilities associated with our finance leases as of March 31, 2019 are included in debt, current portion, current liabilities held for sale and debt, net of current portion on our Consolidated Condensed Balance Sheet.

v3.19.1
Leases Operating Leases, Future Minimum Payments Receivable (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2019
Dec. 31, 2018
Operating Leases, Future Minimum Payments Receivable [Abstract]    
Operating Lease, Lease Income [1] $ 69  
Lessor, Operating Lease, Payments to be Received, Next Rolling Twelve Months 276  
Operating Leases, Future Minimum Payments Due, Future Minimum Sublease Rentals   $ 342
Lessor, Operating Lease, Payments to be Received, Two Years 265  
Lessor, Operating Lease, Payments to be Received, Three Years 261  
Lessor, Operating Lease, Payments to be Received, Four Years 226  
Lessor, Operating Lease, Payments to be Received, Five Years 144  
Lessor, Operating Lease, Payments to be Received, Thereafter 277  
Lessor, Operating Lease, Payments to be Received $ 1,449  
[1] Revenues associated with our operating leases are included in Commodity revenue and other revenue on our Consolidated Condensed Statement of Operations.

v3.19.1
Leases Components of operating and finance lease expense (Details)
$ in Millions
 3 Months Ended
Mar. 31, 2019
USD ($)
Components of our operating and finance lease expense [Abstract]  
Operating Lease, Cost $ 11
Finance Lease, Right-of-Use Asset, Amortization 3
Finance Lease, Interest Expense 2
Finance lease, expense, Total 5
Variable Lease, Cost 1
Lease, Cost $ 17

v3.19.1
Divestitures (Details) - Subsequent Event [Member]
$ in Millions
 3 Months Ended
Sep. 30, 2019
USD ($)
Apr. 08, 2019
MW
Garrison Energy Center and RockGen Energy LLC [Member]    
Business Acquisition [Line Items]    
Ownership percentage of acquiree   100.00%
Proceeds from Sale of Productive Assets | $ $ 360  
Garrison Energy Center LLC [Member]    
Business Acquisition [Line Items]    
Power generation capacity   309
RockGen Energy LLC [Member]    
Business Acquisition [Line Items]    
Power generation capacity   503

v3.19.1
Variable Interest Entities and Unconsolidated Investments in Power Plants (Unconsolidated VIEs) (Details) - USD ($)
$ in Millions
Mar. 31, 2019
Dec. 31, 2018
Schedule of Equity Method Investments [Line Items]    
Equity method investments $ 67 $ 76
Equity method investment, ownership percentage 50.00%  
Greenfield [Member]    
Schedule of Equity Method Investments [Line Items]    
Equity method investments $ 54 55
Equity method investment, ownership percentage 50.00%  
Whitby [Member]    
Schedule of Equity Method Investments [Line Items]    
Equity method investments $ 8 15
Equity method investment, ownership percentage 50.00%  
Calpine Receivables [Member]    
Schedule of Equity Method Investments [Line Items]    
Equity method investments $ 5 $ 6
Equity method investment, ownership percentage 100.00%  

v3.19.1
Variable Interest Entities and Unconsolidated Investments in Power Plants (Income from Unconsolidated Investments 10-Q) (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2019
Mar. 31, 2018
(Income) from unconsolidated subsidiaries $ (6) $ (6)
Greenfield [Member]    
(Income) from unconsolidated subsidiaries (2) (2)
Whitby [Member]    
(Income) from unconsolidated subsidiaries $ (4) $ (4)

v3.19.1
Variable Interest Entities and Unconsolidated Investments in Power Plants (VIE Texuals) (Details)
$ in Millions
 3 Months Ended
Mar. 31, 2019
USD ($)
yr
MW
Mar. 31, 2018
USD ($)
Dec. 31, 2018
USD ($)
MW
Variable Interest Entity [Line Items]      
Variable interest entity, financial or other support, amount $ 0 $ 0  
Equity method investment, ownership percentage 50.00%    
Equity method investment, summarized financial information, debt $ 302   $ 301
Prorata share of equity method investment, summarized financial information, debt 151   $ 151
Return on investments from unconsolidated subsidiaries $ 11 3  
Greenfield [Member]      
Variable Interest Entity [Line Items]      
Power generation capacity | MW 1,038    
Equity method investment, ownership percentage 50.00%    
Return on investments from unconsolidated subsidiaries $ 0 0  
Whitby [Member]      
Variable Interest Entity [Line Items]      
Power generation capacity | MW 50    
Equity method investment, ownership percentage 50.00%    
Return on investments from unconsolidated subsidiaries $ 11 $ 3  
Calpine Receivables [Member]      
Variable Interest Entity [Line Items]      
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount $ 60    
Equity method investment, ownership percentage 100.00%    
Variable Interest Entity, Primary Beneficiary [Member]      
Variable Interest Entity [Line Items]      
Power generation capacity | MW 7,880   7,880
Put Option [Member]      
Variable Interest Entity [Line Items]      
Proceeds from sale of property, plant and equipment $ 280    
Call Option [Member]      
Variable Interest Entity [Line Items]      
Proceeds from sale of property, plant and equipment $ 377    
Inland Empire Energy Center [Member]      
Variable Interest Entity [Line Items]      
Power generation capacity | MW 775    
Put Option Exercise Period | yr 2,025    
Inland Empire Energy Center [Member] | Minimum [Member]      
Variable Interest Entity [Line Items]      
Call Option Exercise Period | yr 2,017    
Inland Empire Energy Center [Member] | Maximum [Member]      
Variable Interest Entity [Line Items]      
Call Option Exercise Period | yr 2,024    
OMEC [Member]      
Variable Interest Entity [Line Items]      
Debt Instrument, Face Amount $ 220    

v3.19.1
Debt (Debt) (Details) - USD ($)
$ in Millions
Mar. 31, 2019
Dec. 31, 2018
Debt Instrument [Line Items]    
Debt and Capital Lease Obligations $ 10,791 $ 10,785
Debt, Current 258 637
Long-term Debt, Excluding Current Maturities 10,533 10,148
Unsecured Debt [Member]    
Debt Instrument [Line Items]    
Debt and Capital Lease Obligations 2,989 3,036
Loans Payable [Member]    
Debt Instrument [Line Items]    
Debt and Capital Lease Obligations 2,972 2,976
Corporate Debt Securities [Member]    
Debt Instrument [Line Items]    
Debt and Capital Lease Obligations 2,401 2,400
Notes Payable, Other Payables [Member]    
Debt Instrument [Line Items]    
Debt and Capital Lease Obligations 1,228 1,264
Secured Debt [Member]    
Debt Instrument [Line Items]    
Debt and Capital Lease Obligations 972 974
Capital Lease Obligations [Member]    
Debt Instrument [Line Items]    
Debt and Capital Lease Obligations 79 105
Revolving Credit Facility [Member]    
Debt Instrument [Line Items]    
Debt and Capital Lease Obligations $ 150 $ 30

v3.19.1
Debt Senior Unsecured Notes (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2019
Mar. 31, 2018
Dec. 31, 2018
Debt Instrument [Line Items]      
Long-term Debt $ 10,682   $ 10,156
Gain (Loss) on Extinguishment of Debt 4 $ 0  
Senior Unsecured Notes 2023 [Member]      
Debt Instrument [Line Items]      
Long-term Debt 1,228   1,227
Senior Unsecured Notes 2024 [Member]      
Debt Instrument [Line Items]      
Long-term Debt 589   599
Senior Unsecured Notes 2025 [Member]      
Debt Instrument [Line Items]      
Long-term Debt 1,172   1,210
Unsecured Debt [Member]      
Debt Instrument [Line Items]      
Debt Instrument, Repurchased Face Amount, Cumulative 438    
Debt Instrument, Repurchased Face Amount 48    
Long-term Debt 2,989   $ 3,036
Debt Instrument, Repurchase Amount 44    
Gain (Loss) on Extinguishment of Debt 4    
Debt Instrument, Repurchase Amount, Cumulative $ 399    

v3.19.1
Debt (First Lien Term Loans) (Details) - USD ($)
$ in Millions
Mar. 31, 2019
Dec. 31, 2018
Debt Instrument [Line Items]    
Long-term Debt $ 10,682 $ 10,156
New 2019 First Lien Term Loan [Member]    
Debt Instrument [Line Items]    
Long-term Debt 389 389
2023 First Lien Term Loan [Member]    
Debt Instrument [Line Items]    
Long-term Debt 1,057 1,059
2024 First Lien Term Loan [Member]    
Debt Instrument [Line Items]    
Long-term Debt 1,526 1,528
First Lien Term Loans [Member]    
Debt Instrument [Line Items]    
Long-term Debt $ 2,972 $ 2,976

v3.19.1
Debt (First Lien Notes) (Details) - USD ($)
$ in Millions
Mar. 31, 2019
Dec. 31, 2018
Debt Instrument [Line Items]    
Long-term Debt $ 10,682 $ 10,156
2022 First Lien Notes [Member]    
Debt Instrument [Line Items]    
Long-term Debt 744 743
2024 First Lien Notes [Member]    
Debt Instrument [Line Items]    
Long-term Debt 486 486
2026 First Lien Notes [Member]    
Debt Instrument [Line Items]    
Long-term Debt 1,171 1,171
Corporate Debt Securities [Member]    
Debt Instrument [Line Items]    
Long-term Debt $ 2,401 $ 2,400

v3.19.1
Debt (Letter of Credit) (Details) - USD ($)
$ in Millions
Mar. 31, 2019
Dec. 31, 2018
Line of Credit Facility [Line Items]    
Letters of Credit Outstanding, Amount $ 1,201 $ 1,365
Revolving Credit Facility [Member]    
Line of Credit Facility [Line Items]    
Letters of Credit Outstanding, Amount [1] 537 693
CDH [Member]    
Line of Credit Facility [Line Items]    
Letters of Credit Outstanding, Amount [2] 225 251
Various Project Financing Facilities [Member]    
Line of Credit Facility [Line Items]    
Letters of Credit Outstanding, Amount 243 228
Other Corporate Facilities [Member]    
Line of Credit Facility [Line Items]    
Letters of Credit Outstanding, Amount [3] $ 196 $ 193
[1] The Corporate Revolving Facility represents our primary revolving facility. On April 5, 2019, we amended our Corporate Revolving Facility to increase the capacity by approximately $330 million from $1.69 billion to approximately $2.02 billion.
[2] Pursuant to the terms and conditions of the CDHI credit agreement, the capacity under the CDHI letter of credit facility will be reduced to $125 million on June 30, 2019. The decrease in capacity will not have a material effect on our liquidity as alternative sources of liquidity are available.
[3] We have two unsecured letter of credit facilities with third party financial institutions totaling $200 million at March 31, 2019. On May 6, 2019, we entered into a new unsecured letter of credit facility which increased the total capacity available to us by approximately $100 million.

v3.19.1
Debt (Fair Value of Debt) (Details) - USD ($)
$ in Millions
Mar. 31, 2019
Dec. 31, 2018
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Long-term Debt $ 10,682 $ 10,156
Unsecured Debt [Member]    
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Long-term Debt 2,989 3,036
Loans Payable [Member]    
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Long-term Debt 2,972 2,976
Corporate Debt Securities [Member]    
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Long-term Debt 2,401 2,400
Reported Value Measurement [Member]    
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Long-term Debt 10,636 10,604
Reported Value Measurement [Member] | Unsecured Debt [Member]    
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Long-term Debt 2,989 3,036
Reported Value Measurement [Member] | Loans Payable [Member]    
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Long-term Debt 2,972 2,976
Reported Value Measurement [Member] | Corporate Debt Securities [Member]    
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Long-term Debt 2,401 2,400
Reported Value Measurement [Member] | Notes Payable, Other Payable excluding Capital Leases [Member]    
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Long-term Debt [1] 1,152 1,188
Reported Value Measurement [Member] | Secured Debt [Member]    
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Long-term Debt 972 974
Reported Value Measurement [Member] | Revolving Credit Facility [Member]    
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Long-term Debt 150 30
Fair Value, Inputs, Level 2 [Member] | Unsecured Debt [Member]    
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Long-term Debt 2,996 2,803
Fair Value, Inputs, Level 2 [Member] | Loans Payable [Member]    
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Long-term Debt 2,990 2,877
Fair Value, Inputs, Level 2 [Member] | Corporate Debt Securities [Member]    
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Long-term Debt 2,439 2,299
Fair Value, Inputs, Level 2 [Member] | Secured Debt [Member]    
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Long-term Debt 975 938
Fair Value, Inputs, Level 2 [Member] | Revolving Credit Facility [Member]    
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Long-term Debt 150 30
Fair Value, Inputs, Level 3 [Member] | Notes Payable, Other Payable excluding Capital Leases [Member]    
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Long-term Debt [1] $ 1,132 $ 1,209
[1] Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.

v3.19.1
Debt (Debt Textuals) (Details) - USD ($)
$ in Millions
 3 Months Ended
Jun. 30, 2019
Mar. 31, 2019
Mar. 31, 2018
Apr. 05, 2019
Line of Credit Facility [Line Items]        
Gain (Loss) on Extinguishment of Debt   $ 4 $ 0  
Debt Instruments [Abstract]        
Debt Instrument, Interest Rate, Effective Percentage   5.90% 5.60%  
CDHI [Member]        
Line of Credit Facility [Line Items]        
Future Line of Credit Facility Maximum Borrowing Capacity   $ 125    
Other Corporate Facilities [Member]        
Line of Credit Facility [Line Items]        
Line of Credit Facility, Maximum Borrowing Capacity   200    
2026 First Lien Term Loan [Member] | Subsequent Event [Member]        
Line of Credit Facility [Line Items]        
Debt Instrument, Face Amount       $ 950
Percentage of principal amount of Term Loan to be paid quarterly 0.25%      
Debt Instrument Unamortized Discount Percent       1.00%
Debt Issuance Costs, Net       $ 7
Gain (Loss) on Extinguishment of Debt $ (3)      
Amendment No. 6 [Member] | Subsequent Event [Member] | Revolving Credit Facility [Member]        
Line of Credit Facility [Line Items]        
Line of Credit Facility, Increase (Decrease), Net 330      
Line of Credit Facility, Maximum Borrowing Capacity       $ 2,020
Amendment No. 8 [Member] | Revolving Credit Facility [Member]        
Line of Credit Facility [Line Items]        
Line of Credit Facility, Maximum Borrowing Capacity   $ 1,690    
Goldman Sachs - Amendment No 3 [Member] | Subsequent Event [Member] | Other Corporate Facilities [Member]        
Line of Credit Facility [Line Items]        
Line of Credit Facility, Increase (Decrease), Net $ 100      
Federal Funds Effective Rate [Member] | 2026 First Lien Notes [Member] | Subsequent Event [Member]        
Line of Credit Facility [Line Items]        
Debt Instrument, Basis Spread on Variable Rate 0.50%      
Eurodollar Rate For A One-Month Interest Period [Member] | 2026 First Lien Term Loan [Member] | Subsequent Event [Member]        
Line of Credit Facility [Line Items]        
Debt Instrument, Basis Spread on Variable Rate 1.00%      
Prime Rate or The Eurodollar Rate For A One-Month Interest Period [Member] | 2026 First Lien Term Loan [Member] | Subsequent Event [Member]        
Line of Credit Facility [Line Items]        
Debt Instrument, Basis Spread on Variable Rate 1.75%      
London Interbank Offered Rate (LIBOR) [Member] | 2026 First Lien Term Loan [Member] | Subsequent Event [Member]        
Line of Credit Facility [Line Items]        
Debt Instrument, Basis Spread on Variable Rate 2.75%      
Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member] | 2026 First Lien Term Loan [Member] | Subsequent Event [Member]        
Line of Credit Facility [Line Items]        
Debt Instrument, Interest Rate, Stated Percentage       0.00%

v3.19.1
Assets and Liabilities with Recurring Fair Value Measurements Fair Value Hierarchy (Details) - USD ($)
$ in Millions
Mar. 31, 2019
Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Cash equivalents [1] $ 175 $ 168
Derivative Asset [2] 301 302
Effect of Netting and Allocation of Collateral [3],[4] (895) (1,221)
Total assets 476 470
Derivative Liability [2] 337 443
Effect of Netting and Allocation of Collateral, Liability [3],[4] (1,020) (1,268)
Total Liabilities 337 443
Fair Value, Inputs, Level 1 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Cash equivalents [1] 175 168
Effect of Netting and Allocation of Collateral [3],[4] (612) (933)
Total assets 175 168
Effect of Netting and Allocation of Collateral, Liability [3],[4] (688) (932)
Total Liabilities 0 0
Fair Value, Inputs, Level 2 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Cash equivalents [1] 0 0
Effect of Netting and Allocation of Collateral [3],[4] (266) (262)
Total assets 100 116
Effect of Netting and Allocation of Collateral, Liability [3],[4] (313) (310)
Total Liabilities 241 249
Fair Value, Inputs, Level 3 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Cash equivalents [1] 0 0
Effect of Netting and Allocation of Collateral [3],[4] (17) (26)
Total assets 201 186
Effect of Netting and Allocation of Collateral, Liability [3],[4] (19) (26)
Total Liabilities 96 194
Future [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative Asset 612 933
Derivative Liability 688 932
Future [Member] | Fair Value, Inputs, Level 1 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative Asset 612 933
Derivative Liability 688 932
Future [Member] | Fair Value, Inputs, Level 2 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative Asset 0 0
Derivative Liability 0 0
Future [Member] | Fair Value, Inputs, Level 3 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative Asset 0 0
Derivative Liability 0 0
Forward Contracts [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative Asset [5] 561 550
Derivative Liability [5] 652 769
Forward Contracts [Member] | Fair Value, Inputs, Level 1 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative Asset [5] 0 0
Derivative Liability [5] 0 0
Forward Contracts [Member] | Fair Value, Inputs, Level 2 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative Asset [5] 343 338
Derivative Liability [5] 537 549
Forward Contracts [Member] | Fair Value, Inputs, Level 3 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative Asset [5] 218 212
Derivative Liability [5] 115 220
Interest Rate Hedging Instruments    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative Asset 23 40
Derivative Liability 17 10
Interest Rate Hedging Instruments | Fair Value, Inputs, Level 1 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative Asset 0 0
Derivative Liability 0 0
Interest Rate Hedging Instruments | Fair Value, Inputs, Level 2 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative Asset 23 40
Derivative Liability 17 10
Interest Rate Hedging Instruments | Fair Value, Inputs, Level 3 [Member]    
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]    
Derivative Asset 0 0
Derivative Liability $ 0 $ 0
[1] At March 31, 2019 and December 31, 2018, we had cash equivalents of $19 million and $23 million included in cash and cash equivalents and $156 million and $145 million included in restricted cash, respectively.
[2] At March 31, 2019 and December 31, 2018, we had $187 million and $244 million, respectively, of collateral under master netting arrangements that were not offset against our derivative instruments on the Consolidated Condensed Balance Sheets primarily related to initial margin requirements.
[3] Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $76 million, $47 million and $2 million, respectively, at March 31, 2019. Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $(1) million, $48 million and nil, respectively, at December 31, 2018.
[4] We offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation; therefore, amounts recognized for the right to reclaim, or the obligation to return, cash collateral are presented net with the corresponding derivative instrument fair values. See Note 8 for further discussion of our derivative instruments subject to master netting arrangements.
[5] Includes OTC swaps and options.

v3.19.1
Assets and Liabilities with Recurring Fair Value Measurements Quantitative Info on Level 3 (Details) - USD ($)
Mar. 31, 2019
Dec. 31, 2018
Fair Value Measurements Inputs and Valuation Techniques    
Derivative, Fair Value, Net [1] $ (36,000,000) $ (141,000,000)
Power Contracts [Member]    
Fair Value Measurements Inputs and Valuation Techniques    
Derivative, Fair Value, Net [2] 83,000,000 36,000,000
Power Contracts [Member] | Minimum [Member]    
Fair Value Measurements Inputs and Valuation Techniques    
Fair Value Inputs Quantitative Information 2.20 2.12
Power Contracts [Member] | Maximum [Member]    
Fair Value Measurements Inputs and Valuation Techniques    
Fair Value Inputs Quantitative Information 208.95 227.98
Natural Gas [Member]    
Fair Value Measurements Inputs and Valuation Techniques    
Derivative, Fair Value, Net (4,000,000) (73,000,000)
Natural Gas [Member] | Minimum [Member]    
Fair Value Measurements Inputs and Valuation Techniques    
Fair Value Inputs Quantitative Information 0.03 0.75
Natural Gas [Member] | Maximum [Member]    
Fair Value Measurements Inputs and Valuation Techniques    
Fair Value Inputs Quantitative Information 10.00 8.87
Power Congestion Products [Member]    
Fair Value Measurements Inputs and Valuation Techniques    
Derivative, Fair Value, Net 23,000,000 26,000,000
Power Congestion Products [Member] | Minimum [Member]    
Fair Value Measurements Inputs and Valuation Techniques    
Fair Value Inputs Quantitative Information (6.48) (11.71)
Power Congestion Products [Member] | Maximum [Member]    
Fair Value Measurements Inputs and Valuation Techniques    
Fair Value Inputs Quantitative Information $ 8.24 $ 11.88
[1] At March 31, 2019 and December 31, 2018, we had $187 million and $244 million, respectively, of collateral under master netting arrangements that were not offset against our derivative instruments on the Consolidated Condensed Balance Sheets primarily related to initial margin requirements.
[2] (1)Power contracts include power and heat rate instruments classified as level 3 in the fair value hierarchy.

v3.19.1
Assets and Liabilities with Recurring Fair Value Measurements (Textuals) (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2019
Mar. 31, 2018
Dec. 31, 2018
Fair Value Measurement [Domain]      
Fair Value Disclosures [Abstract]      
Cash and Cash Equivalents, at Carrying Value $ 19   $ 23
Restricted Cash and Cash Equivalents 156   145
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs (8) $ 197  
Included in operating revenues [1] 50 (57)  
Fair Value, Assets Measured with Unobservable Inputs on Recurring Basis, Gain (Loss) Included In Fuel And Purchased Energy Expense [2] 2 (2)  
Amount of Change in Collateral of Financial Instruments Classified as Derivative Asset (Liability) 2 (2)  
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Purchases 2 4  
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements 58 (14)  
Fair Value, Liabilities, Level 1 to Level 2 Transfers, Amount 0 0  
Fair Value, Liabilities, Level 2 to Level 1 Transfers, Amount 0 0  
Transfers into level 3 [3],[4] (1) 6  
Transfers out of Level 3 [4],[5] 0 (3)  
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs 105 129  
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss) 52 $ (59)  
Cash and Cash Equivalents, at Carrying Value 184   205
Restricted Cash and Cash Equivalents 334   201
Fair Value, Inputs, Level 1 [Member]      
Fair Value Disclosures [Abstract]      
Derivative, Collateral, Right to Reclaim Cash, Net 76   (1)
Fair Value, Inputs, Level 2 [Member]      
Fair Value Disclosures [Abstract]      
Derivative, Collateral, Right to Reclaim Cash, Net 47   48
Fair Value, Inputs, Level 3 [Member]      
Fair Value Disclosures [Abstract]      
Derivative, Collateral, Right to Reclaim Cash, Net $ 2   $ 0
[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 had $(1) million in losses and $6 million in gains transferred out of level 2 into level 3 for the three months ended March 31, 2019 and 2018, respectively, due to changes in market liquidity in various power markets.
[4] 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 months ended March 31, 2019 and 2018.
[5] We had nil and $3 million in gains transferred out of level 3 into level 2 for the three months ended March 31, 2019 and 2018, respectively, due to changes in market liquidity in various power markets.

v3.19.1
Derivative Instruments (Details)
$ in Millions
 3 Months Ended 12 Months Ended
Mar. 31, 2019
USD ($)
MMBTU
MWh
t
Dec. 31, 2018
USD ($)
MMBTU
MWh
t
Natural Gas [Member]    
Derivative [Line Items]    
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU 1,093 1,045
Environmental Credits [Member]    
Derivative [Line Items]    
Derivative, Nonmonetary Notional Amount, Mass | t 12 13
Interest Rate Hedging Instruments    
Derivative [Line Items]    
Derivative, Notional Amount | $ $ 4,500 $ 4,500
Short [Member] | Power [Member]    
Derivative [Line Items]    
Derivative, Nonmonetary Notional Amount, Energy Measure | MWh 167 161

v3.19.1
Derivative Instruments (Details 2) (Details) - USD ($)
$ in Millions
Mar. 31, 2019
Dec. 31, 2018
Derivatives, Fair Value [Line Items]    
Derivative Asset [1] $ 301 $ 302
Derivative Liability [1] 337 443
Designated as Hedging Instrument [Member]    
Derivatives, Fair Value [Line Items]    
Derivative Asset 21 40
Derivative Liability 15 10
Not Designated as Hedging Instrument [Member]    
Derivatives, Fair Value [Line Items]    
Derivative Asset 280 262
Derivative Liability 322 433
Interest Rate Hedging Instruments    
Derivatives, Fair Value [Line Items]    
Derivative Asset 23 40
Derivative Liability 17 10
Interest Rate Hedging Instruments | Designated as Hedging Instrument [Member]    
Derivatives, Fair Value [Line Items]    
Derivative Asset 21 40
Derivative Liability 15 10
Energy Related Derivative [Member] | Not Designated as Hedging Instrument [Member]    
Derivatives, Fair Value [Line Items]    
Derivative Asset 280 262
Derivative Liability $ 322 $ 433
[1] At March 31, 2019 and December 31, 2018, we had $187 million and $244 million, respectively, of collateral under master netting arrangements that were not offset against our derivative instruments on the Consolidated Condensed Balance Sheets primarily related to initial margin requirements.

v3.19.1
Derivative Instruments (Detail 3) (Details) - USD ($)
$ in Millions
Mar. 31, 2019
Dec. 31, 2018
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative assets, current [1] $ 136 [2] $ 142 [3]
Derivative Asset, Noncurrent [1] 165 [2] 160 [3]
Long-term derivative liabilities [1] (113) [2] (140) [3]
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement (161) 188
Derivative Liability, Collateral, Right to Reclaim Cash, Offset 125 47
Derivative Liability, Current [1] (224) [2] (303) [3]
Derivative Liability [1] (337) (443)
Derivative, Collateral, Right to Reclaim Cash 187 244
Derivative, Fair Value, Net [1] (36) (141)
Derivative Asset [1] 301 302
Derivative Financial Instruments, Assets [Member]    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement 1,196 1,523
Derivative Asset, Collateral, Obligation to Return Cash, Offset (895) (1,221)
Future [Member]    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative assets, current [1] 0 0
Derivative Asset, Noncurrent [1] 0 0
Long-term derivative liabilities [1] 0 0
Derivative Liability, Current [1] 0 0
Derivative Liability (688) (932)
Derivative Asset 612 933
Forward Contracts [Member]    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative assets, current [1] 117 112
Derivative Asset, Noncurrent [1] 163 150
Long-term derivative liabilities [1] (102) (134)
Derivative Liability, Current [1] (220) (299)
Derivative Liability [4] (652) (769)
Derivative Asset [4] 561 550
Interest Rate Hedging Instruments    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative assets, current [1] 19 30
Derivative Asset, Noncurrent [1] 2 10
Long-term derivative liabilities [1] (11) (6)
Derivative Liability, Current [1] (4) (4)
Derivative Liability (17) (10)
Derivative Asset 23 40
Fair Value, Inputs, Level 3 [Member]    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Margin/Cash (Received) Posted Subject to Master Netting Arrangement 2 0
Fair Value, Inputs, Level 3 [Member] | Future [Member]    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative Liability 0 0
Derivative Asset 0 0
Fair Value, Inputs, Level 3 [Member] | Forward Contracts [Member]    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative Liability [4] (115) (220)
Derivative Asset [4] 218 212
Fair Value, Inputs, Level 3 [Member] | Interest Rate Hedging Instruments    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative Liability 0 0
Derivative Asset 0 0
Derivative Assets, Current [Member]    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement 872 [2] 1,191 [3]
Derivative Asset, Collateral, Obligation to Return Cash, Offset (736) [2] (1,049) [3]
Derivative Assets, Current [Member] | Future [Member]    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement 513 820
Derivative Asset, Collateral, Obligation to Return Cash, Offset (513) (820)
Derivative Assets, Current [Member] | Forward Contracts [Member]    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement 340 341
Derivative Asset, Collateral, Obligation to Return Cash, Offset (223) (229)
Derivative Assets, Current [Member] | Interest Rate Hedging Instruments    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement 19 30
Derivative Asset, Collateral, Obligation to Return Cash, Offset 0 0
Derivative Assets, Non-current [Member]    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement 324 [2] 332 [3]
Derivative Asset, Collateral, Obligation to Return Cash, Offset (159) [2] (172) [3]
Derivative Assets, Non-current [Member] | Future [Member]    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement 99 113
Derivative Asset, Collateral, Obligation to Return Cash, Offset (99) (113)
Derivative Assets, Non-current [Member] | Forward Contracts [Member]    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement 221 209
Derivative Asset, Collateral, Obligation to Return Cash, Offset (58) (59)
Derivative Assets, Non-current [Member] | Interest Rate Hedging Instruments    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative Asset, Fair Value, Gross Asset Including Not Subject to Master Netting Arrangement 4 10
Derivative Asset, Collateral, Obligation to Return Cash, Offset (2) 0
Derivative Liabilities, Current [Member]    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement (1,019) [2] (1,344) [3]
Derivative Liability, Collateral, Right to Reclaim Cash, Offset 795 [2] 1,041 [3]
Derivative Liabilities, Current [Member] | Future [Member]    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement (528) (764)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset 528 764
Derivative Liabilities, Current [Member] | Forward Contracts [Member]    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement (487) (576)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset 267 277
Derivative Liabilities, Current [Member] | Interest Rate Hedging Instruments    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement (4) (4)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset 0 0
Derivative Liabilities, Non-current [Member]    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement (338) [2] (367) [3]
Derivative Liability, Collateral, Right to Reclaim Cash, Offset 225 [2] 227 [3]
Derivative Liabilities, Non-current [Member] | Future [Member]    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement (160) (168)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset 160 168
Derivative Liabilities, Non-current [Member] | Forward Contracts [Member]    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement (165) (193)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset 63 59
Derivative Liabilities, Non-current [Member] | Interest Rate Hedging Instruments    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement (13) (6)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset 2 0
Derivative Financial Instruments, Liabilities [Member]    
Derivative Instruments Subject to Master Netting Arrangement [Line Items]    
Derivative Liability, Fair Value, Gross Liability Including Not Subject to Master Netting Arrangement (1,357) (1,711)
Derivative Liability, Collateral, Right to Reclaim Cash, Offset $ 1,020 $ 1,268
[1] At March 31, 2019 and December 31, 2018, we had $187 million and $244 million, respectively, of collateral under master netting arrangements that were not offset against our derivative instruments on the Consolidated Condensed Balance Sheets primarily related to initial margin requirements.
[2] At March 31, 2019, current and long-term derivative assets are shown net of collateral of $(17) million and $(3) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $76 million and $69 million, respectively.
[3] At December 31, 2018, current and long-term derivative assets are shown net of collateral of $(58) million and $(8) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $49 million and $64 million, respectively.
[4] Includes OTC swaps and options.

v3.19.1
Derivative Instruments (Details 4) (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2019
Mar. 31, 2018
Summary of Derivative Instruments by Risk Exposure [Abstract]    
Gain (Loss) on Derivative Instruments, Net, Pretax [1] $ 156 $ (372)
Gain (Loss) on Sale of Derivatives [2],[3] 111 (3)
Mark-to-market gain (loss) [4] 45 (369)
Sales [Member]    
Summary of Derivative Instruments by Risk Exposure [Abstract]    
Gain (Loss) on Derivative Instruments, Net, Pretax [1],[5],[6] 37 (359)
Cost of Sales [Member]    
Summary of Derivative Instruments by Risk Exposure [Abstract]    
Gain (Loss) on Derivative Instruments, Net, Pretax [1],[5],[6] 120 (15)
Interest Expense [Member]    
Summary of Derivative Instruments by Risk Exposure [Abstract]    
Gain (Loss) on Derivative Instruments, Net, Pretax [1] (1) 2
Interest Rate Hedging Instruments    
Summary of Derivative Instruments by Risk Exposure [Abstract]    
Mark-to-market gain (loss) [4] (1) 2
Energy Related Derivative [Member]    
Summary of Derivative Instruments by Risk Exposure [Abstract]    
Gain (Loss) on Sale of Derivatives [2],[3] 111 (3)
Mark-to-market gain (loss) [4] $ 46 $ (371)
[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 derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes adjustments to reflect changes in credit default risk exposure.
[5] Does not include the realized value associated with derivative instruments that settle through physical delivery.
[6] Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of Champion Energy, Calpine Solutions and North American Power.

v3.19.1
Derivative Instruments (Details 5) (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2019
Mar. 31, 2018
Derivative Instruments, Gain (Loss) [Line Items]    
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax $ (25) $ 55
Reclassification adjustment for loss on cash flow hedges realized in net income (loss) [1],[2] 2 (7)
Depreciation expense [Member]    
Derivative Instruments, Gain (Loss) [Line Items]    
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax [3],[4] 0 1
Reclassification adjustment for loss on cash flow hedges realized in net income (loss) [1],[2],[3],[4] 0 (1)
Interest Rate Hedging Instruments    
Derivative Instruments, Gain (Loss) [Line Items]    
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax [3],[4] (25) 54
Reclassification adjustment for loss on cash flow hedges realized in net income (loss) [1],[2],[3],[4] $ 2 $ (6)
[1] Cumulative cash flow hedge gains (losses) attributable to Calpine, net of tax, remaining in AOCI were $59 million and $34 million at March 31, 2019 and December 31, 2018, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $3 million and $3 million at March 31, 2019 and December 31, 2018, respectively.
[2] Includes losses of $1 million and nil that were reclassified from AOCI to interest expense for the three months ended March 31, 2019 and 2018, respectively, where the hedged transactions became probable of not occurring.
[3] 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 months ended March 31, 2018. Upon the adoption of Accounting Standards Update 2017-12 on January 1, 2019, hedge ineffectiveness is no longer separately measured and recorded in earnings.
[4] We recorded an income tax expense of nil and $11 million for the three months ended March 31, 2019 and 2018, respectively, in AOCI related to our cash flow hedging activities.

v3.19.1
Derivative Instruments (Textuals) (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2019
Mar. 31, 2018
Dec. 31, 2018
Derivatives, Fair Value [Line Items]      
Current Derivatives Assets, net of Collateral $ (17)   $ (58)
Long-Term Derivative Assets, net of Collateral (3)   (8)
Current Derivative Liabilities, net of Collateral 76   49
Derivative, Collateral, Right to Reclaim Cash 187   244
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Tax $ 0 $ (11)  
Summary of Derivative Instruments [Abstract]      
Maximum length of time hedging using interest rate derivative instruments 7 years    
Derivative, Net Liability Position, Aggregate Fair Value $ 228    
Collateral Already Posted, Aggregate Fair Value 139    
Additional Collateral, Aggregate Fair Value 4    
Long-term Derivative Liabilities, net of Collateral 69   64
Gain (Loss) on Discontinuation of Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring, Net (1) $ 0  
Parent [Member]      
Derivatives, Fair Value [Line Items]      
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax 59   34
Noncontrolling Interest [Member]      
Derivatives, Fair Value [Line Items]      
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax $ 3   $ 3

v3.19.1
Use of Collateral (Details) - USD ($)
$ in Millions
Mar. 31, 2019
Dec. 31, 2018
Financial Instruments Owned and Pledged as Collateral [Line Items]    
Margin deposits [1] $ 448 $ 343
Natural gas and power prepayments 32 31
Total margin deposits and natural gas and power prepayments with our counterparties [2] 480 374
Letters of credit issued 1,001 1,166
First priority liens under power and natural gas agreements 49 92
First priority liens under interest rate hedging instruments 11 10
Total letters of credit and first priority liens with our counterparties 1,061 1,268
Margin deposits held by us posted by our counterparties [1],[3] 136 52
Letters of credit posted with us by our counterparties 36 27
Total margin deposits and letters of credit posted with us by our counterparties 172 79
Current and Non-current Derivative Assets and Liabilities [Member]    
Financial Instruments Owned and Pledged as Collateral [Line Items]    
Total margin deposits and natural gas and power prepayments with our counterparties [2] 135 79
Margin deposits held by us posted by our counterparties 10 32
Other Current Liabilities [Member]    
Financial Instruments Owned and Pledged as Collateral [Line Items]    
Margin deposits held by us posted by our counterparties 85 20
Prepaid Expenses and Other Current Assets [Member]    
Financial Instruments Owned and Pledged as Collateral [Line Items]    
Total margin deposits and natural gas and power prepayments with our counterparties [2] 337 286
Other Assets [Member]    
Financial Instruments Owned and Pledged as Collateral [Line Items]    
Total margin deposits and natural gas and power prepayments with our counterparties [2] 8 9
Other Noncurrent Liabilities [Member]    
Financial Instruments Owned and Pledged as Collateral [Line Items]    
Margin deposits held by us posted by our counterparties $ 41 $ 0
[1] We offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation; therefore, amounts recognized for the right to reclaim, or the obligation to return, cash collateral are presented net with the corresponding derivative instrument fair values. See Note 8 for further discussion of our derivative instruments subject to master netting arrangements.
[2] At March 31, 2019 and December 31, 2018, $135 million and $79 million, respectively, were included in current and long-term derivative assets and liabilities, $337 million and $286 million, respectively, were included in margin deposits and other prepaid expense and $8 million and $9 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.
[3] At March 31, 2019 and December 31, 2018, $10 million and $32 million, respectively, were included in current and long-term derivative assets and liabilities, $85 million and $20 million, respectively, were included in other current liabilities and $41 million and nil, respectively, were included in other long-term liabilities on our Consolidated Condensed Balance Sheets.

v3.19.1
Income Taxes (Income Tax Expense (Benefit)) (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2019
Mar. 31, 2018
Income Tax Contingency [Line Items]    
Income tax (expense) benefit $ (10) $ (108)
Effective Income Tax Rate, Continuing Operations 5.00% (22.00%)
Income Tax Uncertainties [Abstract]    
Unrecognized Tax Benefits $ 28  
Unrecognized Tax Benefits that Would Impact Effective Tax Rate 16  
Unrecognized Tax Benefit Related to Deferred Tax Asset 12  
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued 2  
Minimum [Member]    
Income Tax Contingency [Line Items]    
Decrease in Unrecognized Tax Benefits is Reasonably Possible 0  
Maximum [Member]    
Income Tax Contingency [Line Items]    
Decrease in Unrecognized Tax Benefits is Reasonably Possible $ 8  

v3.19.1
Commitments and Contingencies Commitments and Contingencies (Details)
$ in Millions
Mar. 31, 2019
USD ($)
Other Commitments [Line Items]  
Guarantor Obligations, Current Carrying Value $ 0

v3.19.1
Related Party Transactions (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2019
Mar. 31, 2018
Dec. 31, 2018
Related Party Transactions [Abstract]      
Continuing Involvement with Derecognized Transferred Financial Assets, Amount Outstanding $ 256   $ 238
Notes Receivable, Related Parties, Current 50   $ 34
Trade Receivables Sold 597 $ 579  
Cash Flows Between Transferor and Transferee, Proceeds from New Transfers 579 573  
Revenue from Related Parties 20 19  
Related Party Transaction, Purchases from Related Party $ 3 $ 2  

v3.19.1
Segment Information (Details) - USD ($)
$ in Millions
 3 Months Ended
Mar. 31, 2019
Mar. 31, 2018
Revenues from External Customers and Long-Lived Assets [Line Items]    
Total operating revenues(1) [1] $ 2,599 $ 2,009
Commodity Margin 779 612
Add: Mark-to-market commodity activity, net and other(2) [2] 52 (373)
Operating and maintenance expense 239 275
Depreciation and amortization expense 174 201
General and other administrative expense 32 60
Other operating expenses 34 37
(Income) loss from unconsolidated investments in power plants (6) (6)
Income (loss) from operations 358 (328)
Interest expense 149 151
Debt Extinguishment Costs and Other (Income) Expense, Net 19 7
Income (loss) before income taxes 190 (486)
Lease levelization (16) (16)
West [Member]    
Revenues from External Customers and Long-Lived Assets [Line Items]    
Total operating revenues(1) [1] 682 480
Commodity Margin 264 185
Add: Mark-to-market commodity activity, net and other(2) [2] 56 13
Operating and maintenance expense 81 90
Depreciation and amortization expense 73 67
General and other administrative expense 7 16
Other operating expenses 9 14
(Income) loss from unconsolidated investments in power plants 0 0
Income (loss) from operations 150 11
Texas [Member]    
Revenues from External Customers and Long-Lived Assets [Line Items]    
Total operating revenues(1) [1] 743 140
Commodity Margin 162 166
Add: Mark-to-market commodity activity, net and other(2) [2] 44 (547)
Operating and maintenance expense 65 80
Depreciation and amortization expense 45 76
General and other administrative expense 12 25
Other operating expenses 2 16
(Income) loss from unconsolidated investments in power plants 0 0
Income (loss) from operations 82 (578)
East [Member]    
Revenues from External Customers and Long-Lived Assets [Line Items]    
Total operating revenues(1) [1] 689 614
Commodity Margin 265 184
Add: Mark-to-market commodity activity, net and other(2) [2] 13 40
Operating and maintenance expense 67 71
Depreciation and amortization expense 43 45
General and other administrative expense 9 15
Other operating expenses 23 7
(Income) loss from unconsolidated investments in power plants (6) (6)
Income (loss) from operations 142 92
Retail [Member]    
Revenues from External Customers and Long-Lived Assets [Line Items]    
Total operating revenues(1) [1] 998 938
Commodity Margin 88 77
Add: Mark-to-market commodity activity, net and other(2) [2] (53) 128
Operating and maintenance expense 34 40
Depreciation and amortization expense 13 13
General and other administrative expense 4 4
Other operating expenses 0 0
(Income) loss from unconsolidated investments in power plants 0 0
Income (loss) from operations (16) 148
Consolidation, Eliminations [Member]    
Revenues from External Customers and Long-Lived Assets [Line Items]    
Total operating revenues(1) [1] (513) (163)
Commodity Margin 0 0
Add: Mark-to-market commodity activity, net and other(2) [2] (8) (7)
Operating and maintenance expense (8) (6)
Depreciation and amortization expense 0 0
General and other administrative expense 0 0
Other operating expenses 0 0
(Income) loss from unconsolidated investments in power plants 0 0
Income (loss) from operations 0 (1)
Intersegment Eliminations [Member] | West [Member]    
Revenues from External Customers and Long-Lived Assets [Line Items]    
Total operating revenues(1) 162 114
Intersegment Eliminations [Member] | Texas [Member]    
Revenues from External Customers and Long-Lived Assets [Line Items]    
Total operating revenues(1) 211 (67)
Intersegment Eliminations [Member] | East [Member]    
Revenues from External Customers and Long-Lived Assets [Line Items]    
Total operating revenues(1) 137 115
Intersegment Eliminations [Member] | Retail [Member]    
Revenues from External Customers and Long-Lived Assets [Line Items]    
Total operating revenues(1) 3 1
Other Assets [Member]    
Revenues from External Customers and Long-Lived Assets [Line Items]    
Amortization of Intangible Assets $ 21 $ 28
[1] Includes intersegment revenues of $162 million and $114 million in the West, $211 million and $(67) million in Texas, $137 million and $115 million in the East and $3 million and $1 million in Retail for the three months ended March 31, 2019 and 2018, respectively.
[2] Includes $(16) million and $(16) million of lease levelization and $21 million and $28 million of amortization expense for the three months ended March 31, 2019 and 2018, respectively.