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EX-32.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER - CALPINE CORPcpn_exhibit321x09302016.htm
EX-31.2 - SECTION 302 CERTIFICATION OF CHIEF FINANCIAL OFFICER - CALPINE CORPcpn_exhibit312x09302016.htm
EX-31.1 - SECTION 302 CERTIFICATION OF CHIEF EXECUTIVE OFFICER - CALPINE CORPcpn_exhibit311x09302016.htm


 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549 
____________________
Form 10-Q
(Mark One)
[X]
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
 
 
OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
 
For the quarterly period ended September 30, 2016
 
 
 
 
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
______________________
cpnimage1a03.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 [X]    No [    ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes [X]    No [    ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
[X]
 
Accelerated filer            
[    ]
Non-accelerated filer
[   ]
(Do not check if a smaller reporting company)
Smaller reporting company 
[    ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes [    ]    No [X]
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: 359,087,745 shares of common stock, par value $0.001, were outstanding as of October 26, 2016.


 




CALPINE CORPORATION AND SUBSIDIARIES
REPORT ON FORM 10-Q
For the Quarter Ended September 30, 2016
INDEX
 
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

i



DEFINITIONS
As used in this report for the quarter ended September 30, 2016 (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
2015 Form 10-K
 
Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2015, filed with the SEC on February 12, 2016
 
 
 
2019 First Lien Term Loan
 
The $835 million first lien senior secured term loan, dated October 9, 2012, 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 May 31, 2016
 
 
 
2020 First Lien Term Loan
 
The $390 million first lien senior secured term loan, dated October 23, 2013, among Calpine Corporation, as borrower, the lenders party thereto, Citibank, N.A., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent, repaid on May 31, 2016
 
 
 
2022 First Lien Notes
 
The $750 million aggregate principal amount of 6.0% senior secured notes due 2022, issued October 31, 2013
 
 
 
2022 First Lien Term Loan
 
The $1.6 billion first lien senior secured term loan, dated May 28, 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
 
 
 
2023 First Lien Term Loan
 
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
 
 
 
2023 First Lien Term Loans
 
Collectively, the 2023 First Lien Term Loan and the New 2023 First Lien Term Loan
 
 
 
2023 First Lien Notes
 
The $1.2 billion aggregate principal amount of 7.875% senior secured notes due 2023, issued January 14, 2011, and partially repaid in a series of transactions on November 7, 2012, December 2, 2013, December 4, 2014, February 3, 2015 and December 7, 2015
 
 
 
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 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
 
The $625 million aggregate principal amount of 5.25% senior unsecured notes due 2026, issued May 31, 2016
 
 
 
AB 32
 
California Assembly Bill 32
 
 
 

ii



ABBREVIATION
 
DEFINITION
Adjusted EBITDA
 
EBITDA as adjusted for the effects of (a) impairment charges, (b) major maintenance expense, (c) operating lease expense, (d) gains or losses on commodity derivative mark-to-market activity, (e) adjustments to reflect only the Adjusted EBITDA from our unconsolidated investments, (f) adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, (g) stock-based compensation expense, (h) gains or losses on sales, dispositions or retirements of assets, (i) non-cash gains and losses from foreign currency translations, (j) gains or losses on the repurchase, modification or extinguishment of debt, (k) non-cash GAAP-related adjustments to levelize revenues from tolling agreements and (l) other unusual or non-recurring items
 
 
 
AOCI
 
Accumulated Other Comprehensive Income
 
 
 
Average availability
 
Represents the total hours during the period that our plants were in-service or available for service as a percentage of the total hours in the period
 
 
 
Average capacity factor, excluding peakers
 
A measure of total actual power generation as a percent of total potential power generation. It is calculated by dividing (a) total MWh generated by our power plants, excluding peakers, by (b) the product of multiplying (i) the average total MW in operation, excluding peakers, during the period by (ii) the total hours in the period
 
 
 
Btu
 
British thermal unit(s), a measure of heat content
 
 
 
CAISO
 
California Independent System Operator
 
 
 
Calpine Equity Incentive Plans
 
Collectively, the Director Plan and the Equity Plan, which provide for grants of equity awards to Calpine non-union employees and non-employee members of Calpine’s Board of Directors
 
 
 
Cap-and-Trade
 
A government imposed emissions reduction program that would place a cap on the amount of emissions that can be emitted from certain sources, such as power plants. In its simplest form, the cap amount is set as a reduction from the total emissions during a base year and for each year over a period of years the cap amount would be reduced to achieve the targeted overall reduction by the end of the period. Allowances or credits for emissions in an amount equal to the cap would be issued or auctioned to companies with facilities, permitting them to emit up to a certain amount of emissions during each applicable period. After allowances have been distributed or auctioned, they can be transferred or traded
 
 
 
CCFC
 
Calpine Construction Finance Company, L.P., an indirect, wholly-owned subsidiary of Calpine
 
 
 
CCFC Term Loans
 
Collectively, the $900 million first lien senior secured term loan and the $300 million first lien senior secured term loan entered into on May 3, 2013, and the $425 million first lien senior secured term loan entered into on February 26, 2014, between CCFC, as borrower, and Goldman Sachs Lending Partners, LLC, as administrative agent and as collateral agent, and the lenders party thereto
 
 
 
CDHI
 
Calpine Development Holdings, Inc., an indirect, wholly-owned subsidiary of Calpine
 
 
 
CFTC
 
Commodities Futures Trading Commission
 
 
 
Champion Energy
 
Champion Energy Marketing, LLC, which owns a retail electric provider that serves residential, governmental, commercial and industrial customers in deregulated electricity markets in Texas, Illinois, Pennsylvania, Ohio, New Jersey, Maryland, Massachusetts, New York, Delaware, Maine, Connecticut, California and the District of Columbia
 
 
 
CO2
 
Carbon dioxide
 
 
 
COD
 
Commercial operations date
 
 
 
Cogeneration
 
Using a portion or all of the steam generated in the power generating process to supply a customer with steam for use in the customer’s operations
 
 
 

iii



ABBREVIATION
 
DEFINITION
Commodity expense
 
The sum of our expenses from fuel and purchased energy expense, fuel transportation expense, transmission expense, environmental compliance expense and realized settlements from our marketing, hedging and optimization activities including natural gas and fuel oil transactions hedging future power sales, but excludes our mark-to-market activity
 
 
 
Commodity Margin
 
Non-GAAP financial measure that includes power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, environmental compliance expense, and realized settlements from our marketing, hedging, optimization and trading activities, but excludes our mark-to-market activity and other revenues
 
 
 
Commodity revenue
 
The sum of our revenues from power and steam sales, sales of purchased power and physical natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and realized settlements from our marketing, hedging, optimization and trading activities, but excludes our mark-to-market activity
 
 
 
Company
 
Calpine Corporation, a Delaware corporation, and its subsidiaries
 
 
 
Corporate Revolving Facility
 
The $1.7 billion aggregate amount revolving credit facility credit agreement, dated as of December 10, 2010, as amended on June 27, 2013, July 30, 2014 and February 8, 2016, 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
 
 
 
CPUC
 
California Public Utilities Commission
 
 
 
Director Plan
 
The Amended and Restated Calpine Corporation 2008 Director Incentive Plan
 
 
 
EBITDA
 
Net income (loss) attributable to Calpine before net (income) loss attributable to the noncontrolling interest, interest, taxes, depreciation and amortization
 
 
 
Equity Plan
 
The Amended and Restated Calpine Corporation 2008 Equity Incentive Plan
 
 
 
ERCOT
 
Electric Reliability Council of Texas
 
 
 
Exchange Act
 
U.S. Securities Exchange Act of 1934, as amended
 
 
 
FASB
 
Financial Accounting Standards Board
 
 
 
FDIC
 
U.S. Federal Deposit Insurance Corporation
 
 
 
FERC
 
U.S. Federal Energy Regulatory Commission
 
 
 
First Lien Notes
 
Collectively, the 2022 First Lien Notes, the 2023 First Lien Notes, the 2024 First Lien Notes and the 2026 First Lien Notes
 
 
 
First Lien Term Loans
 
Collectively, the 2019 First Lien Term Loan, the 2020 First Lien Term Loan, the 2022 First Lien Term Loan and the 2023 First Lien Term Loans
 
 
 
Geysers Assets
 
Our geothermal power plant assets, including our steam extraction and gathering assets, located in northern California consisting of 13 operating power plants
 
 
 
GHG(s)
 
Greenhouse gas(es), primarily carbon dioxide (CO2), and including methane (CH4), nitrous oxide (N2O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs)
 
 
 
Greenfield LP
 
Greenfield Energy Centre LP, a 50% partnership interest between certain of our subsidiaries and a third party which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant in Ontario, Canada
 
 
 
Heat Rate(s)
 
A measure of the amount of fuel required to produce a unit of power
 
 
 

iv



ABBREVIATION
 
DEFINITION
IPP(s)
 
Independent Power Producers
 
 
 
IPP Peers
 
Dynegy Inc., NRG Energy, Inc. and Talen Energy Corporation
 
 
 
IRS
 
U.S. Internal Revenue Service
 
 
 
ISO(s)
 
Independent System Operator(s)
 
 
 
ISO-NE
 
ISO New England Inc., an independent nonprofit RTO serving states in the New England area, including Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont
 
 
 
KWh
 
Kilowatt hour(s), a measure of power produced, purchased or sold
 
 
 
LIBOR
 
London Inter-Bank Offered Rate
 
 
 
Market Heat Rate(s)
 
The regional power price divided by the corresponding regional natural gas price
 
 
 
MMBtu
 
Million Btu
 
 
 
MW
 
Megawatt(s), a measure of plant capacity
 
 
 
MWh
 
Megawatt hour(s), a measure of power produced, purchased or sold
 
 
 
NAES
 
Noble Americas Energy Solutions, LLC, the largest independent supplier of power to commercial and industrial retail customers in the United States with customers in 18 states including California, Texas, the Mid-Atlantic and the Northeast
 
 
 
New 2023 First Lien Term Loan
 
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
 
 
 
NOL(s)
 
Net operating loss(es)
 
 
 
NYISO
 
New York ISO
 
 
 
NYMEX
 
New York Mercantile Exchange
 
 
 
OCI
 
Other Comprehensive Income
 
 
 
OTC
 
Over-the-Counter
 
 
 
PJM
 
PJM Interconnection is a RTO that coordinates the movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia
 
 
 
PPA(s)
 
Any term power purchase agreement or other contract for a physically settled sale (as distinguished from a financially settled future, option or other derivative or hedge transaction) of any power product, including power, capacity and/or ancillary services, in the form of a bilateral agreement or a written or oral confirmation of a transaction between two parties to a master agreement, including sales related to a tolling transaction in which the purchaser provides the fuel required by us to generate such power and we receive a variable payment to convert the fuel into power and steam
 
 
 
PUCT
 
Public Utility Commission of Texas
 
 
 
REC(s)
 
Renewable energy credit(s)
 
 
 
Risk Management Policy
 
Calpine’s policy applicable to all employees, contractors, representatives and agents, which defines the risk management framework and corporate governance structure for commodity risk, interest rate risk, currency risk and other risks
 
 
 
RTO(s)
 
Regional Transmission Organization(s)
 
 
 

v



ABBREVIATION
 
DEFINITION
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
 
 
 
SO2
 
Sulfur dioxide
 
 
 
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
 
 
 
TSR
 
Total shareholder return
 
 
 
U.S. GAAP
 
Generally accepted accounting principles in the U.S.
 
 
 
VAR
 
Value-at-risk
 
 
 
VIE(s)
 
Variable interest entity(ies)
 
 
 
Whitby
 
Whitby Cogeneration Limited Partnership, a 50% partnership interest between certain of our subsidiaries and a third party, which operates Whitby, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada

vi



Forward-Looking Statements

This Report contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this Report, including without limitation, the “Management’s Discussion and Analysis” section. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will,” “should,” “estimate,” “potential,” “project” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. 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 markets in which we participate and our ability to effectively respond to changes in laws, regulations or market rules or the interpretation thereof including those related to the environment, derivative transactions and market design in the regions in which we operate;
Our ability to manage our liquidity needs, access the capital markets when necessary and comply with covenants under our Senior Unsecured Notes, First Lien Notes, First Lien Term Loans, Corporate Revolving Facility, CCFC Term Loans and other existing financing obligations;
Risks associated with the operation, construction and development of power plants, including unscheduled outages or delays and plant efficiencies;
Risks related to our geothermal resources, including the adequacy of our steam reserves, unusual or unexpected steam field well and pipeline maintenance requirements, variables associated with the injection of water to the steam reservoir and potential regulations or other requirements related to seismicity concerns that may delay or increase the cost of developing or operating geothermal resources;
Competition, including from renewable sources of power, interference by states in competitive power markets through subsidies or similar support for new or existing power plants, and other risks associated with marketing and selling power in the evolving energy markets;
Structural changes in the supply and demand of power, resulting from the development of new fuels or technologies and demand-side management tools (such as distributed generation, power storage and other technologies);
The expiration or early termination of our PPAs and the related results on revenues;
Future capacity revenue may not occur at expected levels;
Natural disasters, such as hurricanes, earthquakes, droughts, wildfires and floods, acts of terrorism or cyber attacks that may affect our power plants or the markets our power plants or retail operations serve and our corporate headquarters;
Disruptions in or limitations on the transportation of natural gas or fuel oil and the transmission of power;
Our ability to manage our customer and counterparty exposure and credit risk, including our commodity positions;
Our ability to attract, motivate and retain key employees;
Present and possible future claims, litigation and enforcement actions that may arise from noncompliance with market rules promulgated by the SEC, CFTC, FERC and other regulatory bodies; and
Other risks identified in this Report, in our 2015 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.

vii



Where You Can Find Other Information
Our website is www.calpine.com. Information contained on our website is not part of this Report. Information that we furnish or file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to, or exhibits included in, these reports are available for download, free of charge, on our website as soon as reasonably practicable after such materials are filed with or furnished to the SEC. Our SEC filings, including exhibits filed therewith, are also available on the SEC’s website at www.sec.gov. You may obtain and copy any document we furnish or file with the SEC at the SEC’s public reference room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the SEC’s public reference facilities by calling the SEC at 1-800-SEC-0330. You may request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at its principal office at 100 F Street, NE, Room 1580, Washington, D.C. 20549.

viii



PART I — FINANCIAL INFORMATION
Item 1.
Financial Statements

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
(Unaudited)
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
 
(in millions, except share and per share amounts)
Operating revenues:
 
 
 
 
 
 
 
Commodity revenue
$
2,063

 
$
1,888

 
$
5,199

 
$
4,933

Mark-to-market gain (loss)
287

 
55

 
(79
)
 
89

Other revenue
5

 
5

 
14

 
14

Operating revenues
2,355

 
1,948

 
5,134

 
5,036

Operating expenses:
 
 
 
 
 
 
 
Fuel and purchased energy expense:
 
 
 
 
 
 
 
Commodity expense
1,294

 
943

 
3,197

 
2,754

Mark-to-market (gain) loss
178

 
130

 
(57
)
 
95

Fuel and purchased energy expense
1,472

 
1,073

 
3,140

 
2,849

Plant operating expense
215

 
200

 
741

 
732

Depreciation and amortization expense
161

 
166

 
503

 
484

Sales, general and other administrative expense
33

 
33

 
106

 
100

Other operating expenses
18

 
16

 
55

 
56

Total operating expenses
1,899

 
1,488

 
4,545

 
4,221

(Income) from unconsolidated investments in power plants
(6
)
 
(6
)
 
(16
)
 
(18
)
Income from operations
462

 
466

 
605

 
833

Interest expense
158

 
159

 
472

 
471

Interest (income)
(1
)
 
(1
)
 
(3
)
 
(3
)
Debt modification and extinguishment costs

 

 
15

 
32

Other (income) expense, net
8

 
1

 
21

 
8

Income before income taxes
297

 
307

 
100

 
325

Income tax expense (benefit)
(4
)
 
28

 
17

 
32

Net income
301

 
279

 
83

 
293

Net income attributable to the noncontrolling interest
(6
)
 
(6
)
 
(15
)
 
(11
)
Net income attributable to Calpine
$
295

 
$
273

 
$
68

 
$
282

 
 
 
 
 
 
 
 
Basic earnings per common share attributable to Calpine:
 
 
 
 
 
 
 
Weighted average shares of common stock outstanding (in thousands)
354,215

 
355,443

 
353,929

 
365,053

Net income per common share attributable to Calpine — basic
$
0.83

 
$
0.77

 
$
0.19

 
$
0.77

 
 
 
 
 
 
 
 
Diluted earnings per common share attributable to Calpine:
 
 
 
 
 
 
 
Weighted average shares of common stock outstanding (in thousands)
356,352

 
357,676

 
355,980

 
368,219

Net income per common share attributable to Calpine — diluted
$
0.83

 
$
0.76

 
$
0.19

 
$
0.77


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

1



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

 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
 
(in millions)
Net income
$
301

 
$
279

 
$
83

 
$
293

Cash flow hedging activities:
 
 
 
 
 
 
 
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income
7

 
(16
)
 
(33
)
 
(32
)
Reclassification adjustment for loss on cash flow hedges realized in net income
11

 
12

 
33

 
36

Foreign currency translation gain (loss)
(3
)
 
(11
)
 
9

 
(19
)
Income tax expense

 

 

 

Other comprehensive income (loss)
15

 
(15
)
 
9

 
(15
)
Comprehensive income
316

 
264

 
92

 
278

Comprehensive (income) attributable to the noncontrolling interest
(8
)
 
(5
)
 
(15
)
 
(11
)
Comprehensive income attributable to Calpine
$
308

 
$
259

 
$
77

 
$
267


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


2



CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited)

 
 
September 30,
 
December 31,
 
 
2016
 
2015
 
 
(in millions, except share and per share amounts)
ASSETS
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents ($135 and $118 attributable to VIEs)
 
$
561

 
$
906

Accounts receivable, net of allowance of $5 and $2
 
801

 
644

Inventories
 
518

 
475

Margin deposits and other prepaid expense
 
178

 
137

Restricted cash, current ($141 and $132 attributable to VIEs)
 
210

 
216

Derivative assets, current
 
959

 
1,698

Current assets held for sale
 
452

 

Other current assets
 
36

 
19

Total current assets
 
3,715

 
4,095

Property, plant and equipment, net ($3,758 and $4,062 attributable to VIEs)
 
13,069

 
13,012

Restricted cash, net of current portion ($14 and $11 attributable to VIEs)
 
15

 
12

Investments in power plants
 
80

 
79

Long-term derivative assets
 
323

 
313

Long-term assets held for sale
 

 
130

Other assets ($63 and $119 attributable to VIEs)
 
786

 
1,040

Total assets
 
$
17,988

 
$
18,681

LIABILITIES & STOCKHOLDERS’ EQUITY
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable
 
$
590

 
$
552

Accrued interest payable
 
144

 
129

Debt, current portion ($164 and $166 attributable to VIEs)
 
197

 
221

Derivative liabilities, current
 
991

 
1,734

Other current liabilities
 
392

 
412

Total current liabilities
 
2,314

 
3,048

Debt, net of current portion ($3,013 and $3,096 attributable to VIEs)
 
11,623

 
11,716

Long-term derivative liabilities
 
436

 
473

Other long-term liabilities
 
344

 
277

Total liabilities
 
14,717

 
15,514

 
 
 
 
 
Commitments and contingencies (see Note 11)
 

 

Stockholders’ equity:
 
 
 
 
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding
 

 

Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 359,609,997 and 356,755,747 shares issued, respectively, and 359,080,056 and 356,662,004 shares outstanding, respectively
 

 

Treasury stock, at cost, 529,941 and 93,743 shares, respectively
 
(7
)
 
(1
)
Additional paid-in capital
 
9,618

 
9,594

Accumulated deficit
 
(6,237
)
 
(6,305
)
Accumulated other comprehensive loss
 
(170
)
 
(179
)
Total Calpine stockholders’ equity
 
3,204

 
3,109

Noncontrolling interest
 
67

 
58

Total stockholders’ equity
 
3,271

 
3,167

Total liabilities and stockholders’ equity
 
$
17,988

 
$
18,681


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

3



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

 
 
Nine Months Ended September 30,
 
 
2016
 
2015
 
 
(in millions)
Cash flows from operating activities:
 
 
 
 
Net income
 
$
83

 
$
293

Adjustments to reconcile net income to net cash provided by operating activities:
 

 

Depreciation and amortization(1)
 
672

 
519

Debt extinguishment costs
 
15

 
1

Deferred income taxes
 
15

 
12

Mark-to-market activity, net
 
21

 
4

(Income) from unconsolidated investments in power plants
 
(16
)
 
(18
)
Return on unconsolidated investments in power plants
 
19

 
23

Stock-based compensation expense
 
23

 
19

Other
 
1

 
(1
)
Change in operating assets and liabilities, net of effect of acquisition:
 

 

Accounts receivable
 
(168
)
 
42

Derivative instruments, net
 
(71
)
 
(44
)
Other assets
 
(75
)
 
(199
)
Accounts payable and accrued expenses
 
46

 
(200
)
Other liabilities
 
102

 
108

Net cash provided by operating activities
 
667

 
559

Cash flows from investing activities:
 
 
 
 
Purchases of property, plant and equipment
 
(337
)
 
(411
)
Purchase of Granite Ridge Energy Center
 
(526
)
 

Decrease (increase) in restricted cash
 
2

 
(31
)
Other
 
20

 
(8
)
Net cash used in investing activities
 
(841
)
 
(450
)
Cash flows from financing activities:
 
 
 
 
Borrowings under First Lien Term Loans
 
556

 
1,592

Repayment of CCFC Term Loans and First Lien Term Loans
 
(1,220
)
 
(1,622
)
Borrowings under Senior Unsecured Notes
 

 
650

Borrowings under First Lien Notes
 
625

 

Repurchase of First Lien Notes
 

 
(147
)
Repayments of project financing, notes payable and other
 
(98
)
 
(102
)
Financing costs
 
(27
)
 
(17
)
Stock repurchases
 

 
(510
)
Shares withheld for tax obligations on share-based awards
 
(5
)
 
(11
)
Other
 
(2
)
 

Net cash used in financing activities
 
(171
)
 
(167
)
Net decrease in cash and cash equivalents
 
(345
)
 
(58
)
Cash and cash equivalents, beginning of period
 
906

 
717

Cash and cash equivalents, end of period
 
$
561

 
$
659


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


4



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

 
 
Nine Months Ended September 30,
 
 
2016
 
2015
 
 
(in millions)
Cash paid during the period for:
 
 
 
 
Interest, net of amounts capitalized
 
$
421

 
$
465

Income taxes
 
$
10

 
$
19

 
 
 
 
 
Supplemental disclosure of non-cash investing and financing activities:
 
 
 
 
Change in capital expenditures included in accounts payable
 
$
(4
)
 
$
(17
)
Additions to property, plant and equipment through capital lease
 
$

 
$
9

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


5



CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
September 30, 2016
(Unaudited)
1.
Basis of Presentation and Summary of Significant Accounting Policies
We are a power generation company engaged in the ownership and operation of primarily natural gas-fired and geothermal power plants in North America. We have a significant presence in major competitive wholesale power markets in California (included in our West segment), Texas (included in our Texas segment) and the Northeast and Mid-Atlantic regions (included in our East segment) of the U.S. We sell power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. We 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 retail 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, 2015, included in our 2015 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.
Cash and Cash Equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have cash and cash equivalents held in non-corporate accounts relating to certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts. These accounts have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects.
Restricted Cash — Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted, making these cash funds unavailable for general use. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent and major maintenance or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Condensed Balance Sheets and Statements of Cash Flows.

6



The table below represents the components of our restricted cash as of September 30, 2016 and December 31, 2015 (in millions):

 
September 30, 2016
 
December 31, 2015
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service
$
39

 
$
7

 
$
46

 
$
28

 
$
8

 
$
36

Construction/major maintenance
34

 
4

 
38

 
50

 
2

 
52

Security/project/insurance
134

 
2

 
136

 
136

 

 
136

Other
3

 
2

 
5

 
2

 
2

 
4

Total
$
210

 
$
15

 
$
225

 
$
216

 
$
12

 
$
228

Business Interruption Proceeds — We record business interruption insurance proceeds when they are realizable and recorded approximately $9 million and $17 million of business interruption proceeds in operating revenues during the three and nine months ended September 30, 2016, respectively. We did not record any business interruption proceeds during the three and nine months ended September 30, 2015.
Property, Plant and Equipment, Net — At September 30, 2016 and December 31, 2015, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
 
September 30, 2016
 
December 31, 2015
 
Depreciable Lives
Buildings, machinery and equipment
$
16,478

 
$
16,294

 
3 – 46 Years
Geothermal properties
1,376

 
1,319

 
13 – 58 Years
Other
228

 
208

 
3 – 46 Years
 
18,082

 
17,821

 
 
Less: Accumulated depreciation
5,719

 
5,377

 
 
 
12,363

 
12,444

 
 
Land
119

 
120

 
 
Construction in progress
587

 
448

 
 
Property, plant and equipment, net
$
13,069

 
$
13,012

 
 
Capitalized Interest — The total amount of interest capitalized was $5 million and $3 million for the three months ended September 30, 2016 and 2015 and $14 million and $12 million for the nine months ended September 30, 2016 and 2015, respectively.
Impairment Evaluation of Long-Lived Assets (Including Intangibles and Investments)
We evaluate our long-lived assets, such as property, plant and equipment, equity method investments and definite-lived intangible assets for impairment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Equipment assigned to each power plant is not evaluated for impairment separately; instead, we evaluate our operating power plants and related equipment as a whole unit. When we believe an impairment condition may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities for long-lived assets that are expected to be held and used. We use a fundamental long-term view of the power market which is based on long-term production volumes, price curves and operating costs together with the regulatory and environmental requirements within each individual market to prepare our multi-year forecast. Since we manage and market our power sales as a portfolio rather than at the individual power plant level or customer level within each designated market, pool or segment, we group our power plants based upon the corresponding market for valuation purposes. If we determine that the undiscounted cash flows from an asset or group of assets to be held and used are less than the associated carrying amount, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment loss. All construction and development projects are reviewed for impairment whenever there is an indication of potential reduction in fair value. If it is determined that a construction or development project is no longer probable of completion and the capitalized costs will not be recovered through future operations, the carrying value of the project will be written down to its fair value.
In order to estimate future cash flows, we consider historical cash flows, existing contracts, capacity prices and PPAs, changes in the market environment and other factors that may affect future cash flows. To the extent applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our earnings forecasts).

7



The use of this method involves inherent uncertainty. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the effect of such variations could be material.
When we determine that our assets meet the assets held-for-sale criteria, they are reported at the lower of their carrying amount or fair value less the cost to sell. We are also required to evaluate our equity method investments to determine whether or not they are impaired when the value is considered an “other than a temporary” decline in value.
Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. We will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment including contract terms, tenor and credit risk of counterparties. We may also consider prices of similar assets, consult with brokers, or employ other valuation techniques. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the effect of such variations could be material.
We did not record any material impairments during the three and nine months ended September 30, 2016 and 2015.
New Accounting Standards and Disclosure Requirements
Revenue Recognition — In May 2014, the FASB issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers.” The comprehensive new revenue recognition standard will supersede all existing revenue recognition guidance. The core principle of the standard is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard also requires expanded disclosures surrounding revenue recognition. The standard is effective for fiscal periods beginning after December 15, 2016, including interim periods within that reporting period and allows for either full retrospective or modified retrospective adoption with early adoption being prohibited. In August 2015, the FASB deferred the effective date of Accounting Standards Update 2014-09 for public entities by one year, such that the standard will become effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017. The standard permits entities to adopt early, but only as of the original effective date. In March 2016, the FASB issued Accounting Standards Update 2016-08 “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)” which clarifies implementation guidance for principal versus agent considerations in the new revenue recognition standard. In May 2016, the FASB issued Accounting Standards Update 2016-12 “Narrow-Scope Improvements and Practical Expedients” which addresses assessing the collectability of a contract, the presentation of sales taxes and other taxes collected from customers, non-cash consideration and completed contracts and contract modifications at transition. We are currently assessing the potential effect the revenue recognition standard may have on our financial condition, results of operations or cash flows.
Consolidation — In February 2015, the FASB issued Accounting Standards Update 2015-02, “Amendments to the Consolidation Analysis.” The standard amends the consolidation model used in determining whether a reporting entity should consolidate the financial results of certain of its partially- and wholly-owned subsidiaries. All of our subsidiaries are subject to reevaluation under the revised consolidation model. Specifically, the amendments (i) modify the evaluation of whether limited partnerships and similar legal entities are voting interest entities or VIEs, (ii) eliminate the presumption that a general partner should consolidate the financial results of a limited partnership, (iii) affect the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships and (iv) provide an exception for certain types of entities. This standard became effective for fiscal periods beginning after December 15, 2015, including interim periods within that reporting period. We adopted Accounting Standards Update 2015-02 in the first quarter of 2016 which did not have a material effect on our financial condition, results of operations or cash flows.
Debt Issuance Costs — In April 2015, the FASB issued Accounting Standards Update 2015-03, “Simplifying the Presentation of Debt Issuance Costs.” The standard requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, which is consistent with the presentation of debt discounts. In August 2015, the FASB issued Accounting Standards Update 2015-15, “Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements” which allows an entity to present debt issuance costs associated with a line-of-credit arrangement as an asset regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The standards became effective for fiscal years beginning after December 15, 2015, including interim periods within that reporting period. We retrospectively adopted Accounting Standard Updates 2015-03 and 2015-15 in the first quarter of 2016 which resulted in a $152 million reclassification of debt issuance costs from other assets to debt, net of current portion on our Consolidated Condensed Balance Sheet at December 31, 2015.

8



Cloud Computing Arrangements — In April 2015, the FASB issued Accounting Standards Update 2015-05, “Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement.” The standard provides guidance regarding whether a cloud computing arrangement represents a software license or a service contract. The standard became effective for fiscal years beginning after December 15, 2015, including interim periods. We adopted Accounting Standards Update 2015-05 in the first quarter of 2016 which did not have a material effect on our financial condition, results of operations or cash flows.
Inventory In July 2015, the FASB issued Accounting Standards Update 2015-11, “Simplifying the Measurement of Inventory.” The standard changes the inventory valuation method from the lower of cost or market to the lower of cost or net realizable value for inventory valued under the first-in, first-out or average cost methods. The standard is effective for fiscal years beginning after December 15, 2016, including interim periods and requires prospective adoption with early adoption permitted. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.
Leases — In February 2016, the FASB issued Accounting Standards Update 2016-02, “Leases.” The comprehensive new lease standard will supersede all existing lease guidance. The standard requires that a lessee should recognize a right-to-use asset and a lease liability for substantially all operating leases based on the present value of the minimum rental payments. Entities may make an accounting policy election to not recognize lease assets and liabilities for leases with a term of 12 months or less. For lessors, the accounting for leases remains substantially unchanged. The standard also requires expanded disclosures surrounding leases. The standard is effective for fiscal periods beginning after December 15, 2018, including interim periods within that reporting period and requires modified retrospective adoption with early adoption permitted. We are currently assessing the potential effect this standard may have on our financial condition, results of operations or cash flows.
Stock-Based Compensation In March 2016, the FASB issued Accounting Standards Update 2016-09, “Improvements to Employee Share-Based Payment Accounting.” The standard applies to several aspects of accounting for stock-based compensation including the recognition of excess tax benefits and deficiencies and their related presentation in the statement of cash flows as well as accounting for forfeitures. The standard also requires that shares withheld to satisfy tax withholding obligations associated with the vesting of restricted stock awarded to employees be presented as a financing activity in the statement of cash flows. The standard is effective for fiscal years beginning after December 15, 2016, including interim periods and allows for prospective, retrospective or modified retrospective adoption, depending on the area covered in the standard, with early adoption permitted. We early adopted Accounting Standards Update 2016-09 in the third quarter of 2016. The cumulative-effect adjustment to accumulated deficit for all excess tax benefits not previously recognized as of the beginning of the year is substantially offset by a corresponding change in the valuation allowance. The implementation of Accounting Standards Update 2016-09 did not have a material effect on our financial condition, results of operations or cash flows.
Statement of Cash Flows — In August 2016, the FASB issued Accounting Standards Update 2016-15, “Classification of Certain Cash Receipts and Cash Payments.” The standard addresses several matters of diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows including the presentation of debt extinguishment costs and distributions received from equity method investments. The standard is effective for fiscal years beginning after December 15, 2017, including interim periods and allows for retrospective adoption with early adoption permitted. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.
2.
Acquisitions and Divestitures
Acquisition of NAES
On October 9, 2016, we announced that we entered into an agreement, through our indirect, wholly-owned subsidiaries Calpine Energy Services Holdco II, LLC and Calpine Energy Financial Holdings, LLC, to purchase NAES and a swap contract from Noble Americas Gas & Power Corp. and Noble Group Limited for approximately $800 million plus approximately $100 million of net working capital estimated at closing. We expect to recover approximately $200 million through collateral synergies and the runoff of acquired legacy hedges, substantially within the first year. NAES is a commercial and industrial retail electricity provider with customers in 18 states in the U.S. including California, Texas, the Mid-Atlantic and Northeast, where our wholesale power generation fleet is primarily concentrated. The acquisition of this large direct energy sales platform is consistent with our stated goal of getting closer to our end-use customers and expands our retail customer base, complementing our existing retail business while providing us a valuable sales channel for reaching a much greater portion of the load we seek to serve. The transaction is expected to close in the fourth quarter of 2016, subject to federal regulatory approval and approval of the shareholders of Noble Group Limited, and will be funded with a combination of cash on hand and debt financing.

9



Acquisition of Granite Ridge Energy Center
On February 5, 2016, we, through our indirect, wholly-owned subsidiary Calpine Granite Holdings, LLC, completed the purchase of Granite Ridge Energy Center, a power plant with a nameplate capacity of 745 MW (summer peaking capacity of 695 MW), from Granite Ridge Holdings, LLC, for approximately $500 million, excluding working capital and other adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant increased capacity in our East segment, specifically the constrained New England market. Beginning operations in 2003, Granite Ridge Energy Center is located in Londonderry, New Hampshire and features two combustion turbines, two heat recovery steam generators and one steam turbine. We funded the acquisition with a combination of cash on hand and our 2023 First Lien Term Loan obtained in the fourth quarter of 2015, and the purchase price was primarily allocated to property, plant and equipment. The pro forma incremental effect of Granite Ridge Energy Center on our results of operations for each of the three and nine months ended September 30, 2016 and 2015 is not material.
Acquisition of Champion Energy
On October 1, 2015, we, through our indirect, wholly-owned subsidiary Calpine Energy Services Holdco, LLC, completed the purchase of Champion Energy Marketing, LLC from a subsidiary of Crane Champion Holdco, LLC, which owned a 75% interest, and EDF Trading North America, LLC, which owned a 25% interest, for approximately $240 million, excluding working capital adjustments. The addition of this well-established retail sales organization is consistent with our stated goal of getting closer to our end-use customers and provides us a valuable sales channel for directly reaching a much greater portion of the load we seek to serve. The purchase price was funded with cash on hand and any excess of the purchase price over the fair values of Champion Energy’s assets and liabilities was recorded as goodwill; however, the goodwill we recorded as a result of this acquisition was immaterial. The purchase price allocation was finalized during the third quarter of 2016 which did not result in any material adjustments.
Sale of Mankato Power Plant
On October 26, 2016, we, through our indirect, wholly-owned subsidiaries, New Steamboat Holdings, LLC and Mankato Holdings, LLC, completed the sale of our Mankato Power Plant, a 375 MW natural gas-fired, combined-cycle power plant and 345 MW expansion project under advanced development located in Minnesota, to Southern Power Company, a subsidiary of Southern Company, for $396 million, excluding working capital and other adjustments. This transaction supports our effort to divest non-core assets outside our strategic concentration. We expect to use the proceeds from the sale to fund pending acquisitions and for other corporate purposes. We expect to record a gain on sale of assets, net of approximately $160 million during the fourth quarter of 2016, and our federal and state NOLs will almost entirely offset the projected taxable gain from the sale.
Sale of South Point Energy Center
On April 1, 2016, we entered into an asset sale agreement for the sale of substantially all of the assets comprising our South Point Energy Center to Nevada Power Company d/b/a NV Energy for approximately $76 million plus the assumption by the purchaser of existing transmission capacity contracts with a future net present value payment obligation of approximately $112 million, approximately $9 million in remaining tribal lease costs and approximately $21 million in near-term repairs, maintenance and capital improvements to restore the power plant to full capacity. The sale is subject to certain conditions precedent, as well as federal and state regulatory approvals, and is expected to close no later than the first quarter of 2017. The natural gas-fired, combined-cycle plant is located on the Fort Mojave Indian Reservation in Mohave Valley, Arizona, and features a summer peaking capacity of 504 MW. This transaction supports our effort to divest non-core assets outside our strategic concentration.
Sale of Osprey Energy Center
We executed an asset sale agreement in the fourth quarter of 2014 for the sale of our Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments, which will be consummated in January 2017 upon the conclusion of a PPA with a term of 27 months. The sale has received FERC and state regulatory approvals and represents a strategic disposition of a power plant in a wholesale power market dominated by regulated utilities.

10



Assets Held for Sale
The assets of South Point Energy Center, which is part of our West segment, and the assets of Osprey Energy Center and Mankato Power Plant, including the expansion project at our Mankato Power Plant, which are part of our East segment, are reported as current assets held for sale on our Consolidated Condensed Balance Sheet at September 30, 2016.
The table below presents the components of our current assets held for sale at September 30, 2016 (in millions):
 
September 30, 2016
Assets:
 
Current assets
$
12

Property, plant and equipment, net
401

Other long-term assets
39

Total current assets held for sale
$
452

3.
Variable Interest Entities and Unconsolidated Investments
We consolidate all of our VIEs where we have determined that we are the primary beneficiary. There were no changes to our determination of whether we are the primary beneficiary of our VIEs for the nine months ended September 30, 2016. See Note 5 in our 2015 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 10,266 MW at September 30, 2016 and December 31, 2015, 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 $1 million during each of the three and nine months ended September 30, 2016 and $2 million during each of the three and nine months ended September 30, 2015.
Unconsolidated VIEs and Investments in Power Plants
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.
We account for these entities under the equity method of accounting and include our net equity interest in investments in power plants on our Consolidated Condensed Balance Sheets. At September 30, 2016 and December 31, 2015, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):
 
 
Ownership Interest as of
September 30, 2016
 
September 30, 2016
 
December 31, 2015
Greenfield LP
50%
 
$
70

 
$
65

Whitby
50%
 
10

 
14

Total investments in power plants
 
 
$
80

 
$
79

Our risk of loss related to our unconsolidated VIEs is limited to our investment balance. Holders of the debt of our unconsolidated investments do not have recourse to Calpine Corporation and its other subsidiaries; therefore, the debt of our unconsolidated investments is not reflected on our Consolidated Condensed Balance Sheets. At September 30, 2016 and December 31, 2015, equity method investee debt was approximately $270 million and $269 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $135 million and $135 million at September 30, 2016 and December 31, 2015, respectively.

11



Our equity interest in the net income from Greenfield LP and Whitby for the three and nine months ended September 30, 2016 and 2015, is recorded in (income) from unconsolidated investments in power plants. The following table sets forth details of our (income) from unconsolidated investments in power plants for the periods indicated (in millions):
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2016
 
2015
 
2016
 
2015
Greenfield LP
 
$
(3
)
 
$
(3
)
 
$
(8
)
 
$
(9
)
Whitby
 
(3
)
 
(3
)
 
(8
)
 
(9
)
Total
 
$
(6
)
 
$
(6
)
 
$
(16
)
 
$
(18
)

Distributions from Greenfield LP were $1 million and $6 million during the three and nine months ended September 30, 2016, respectively, and $10 million during each of the three and nine months ended September 30, 2015. Distributions from Whitby were nil and $13 million during each of the three and nine months ended September 30, 2016 and 2015.
4.
Debt
We retrospectively adopted Accounting Standards Update 2015-03 in the first quarter of 2016. As a result, we recast our Consolidated Condensed Balance Sheet at December 31, 2015 resulting in a $152 million reclassification of debt issuance costs from other assets to debt, net of current portion. Our debt at September 30, 2016 and December 31, 2015, was as follows (in millions):
 
September 30, 2016

December 31, 2015
Senior Unsecured Notes
$
3,410

 
$
3,406

First Lien Term Loans
2,637

 
3,277

First Lien Notes
2,408

 
1,789

Project financing, notes payable and other
1,628

 
1,715

CCFC Term Loans
1,556

 
1,565

Capital lease obligations
181

 
185

Subtotal
11,820

 
11,937

Less: Current maturities
197

 
221

Total long-term debt
$
11,623

 
$
11,716

Our effective interest rate on our consolidated debt, excluding the effects of capitalized interest and mark-to-market gains (losses) on interest rate hedging instruments, decreased to 5.5% for the nine months ended September 30, 2016, from 5.7% for the same period in 2015. The issuance of our New 2023 First Lien Term Loan in May 2016, our 2024 Senior Unsecured Notes in February 2015 and our 2022 First Lien Term Loan in May 2015 allowed us to reduce our overall cost of debt by replacing a portion of our First Lien Term Loans and First Lien Notes with debt carrying lower interest rates.
Senior Unsecured Notes
The amounts outstanding under our Senior Unsecured Notes are summarized in the table below (in millions):
 
September 30, 2016
 
December 31, 2015
2023 Senior Unsecured Notes
$
1,236

 
$
1,235

2024 Senior Unsecured Notes
642

 
641

2025 Senior Unsecured Notes
1,532

 
1,530

Total Senior Unsecured Notes
$
3,410

 
$
3,406


12



First Lien Term Loans
The amounts outstanding under our senior secured First Lien Term Loans are summarized in the table below (in millions):
 
September 30, 2016
 
December 31, 2015
2019 First Lien Term Loan
$

 
$
795

2020 First Lien Term Loan

 
378

2022 First Lien Term Loan
1,562

 
1,571

2023 First Lien Term Loan
530

 
533

New 2023 First Lien Term Loan
545

 

Total First Lien Term Loans
$
2,637

 
$
3,277

On May 31, 2016, we entered into a $562 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 New 2023 First Lien Term Loan credit agreement), plus an applicable margin of 2.00%, or (ii) LIBOR plus 3.00% per annum (with no LIBOR floor) and matures on May 31, 2023. We paid an upfront fee of an amount equal to 1.0% of the aggregate principal amount of the New 2023 First Lien Term Loan, which is structured as original issue discount and recorded approximately $11 million in deferred financing costs during the second quarter of 2016 related to the issuance of our New 2023 First Lien Term Loan. The New 2023 First Lien Term Loan contains substantially similar covenants, qualifications, exceptions and limitations as the First Lien Term Loans and the First Lien Notes.
We used the proceeds from the New 2023 First Lien Term Loan and the 2026 First Lien Notes, discussed below, to repay the 2019 and 2020 First Lien Term Loans and recorded $15 million in debt extinguishment costs during the second quarter of 2016 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):
 
September 30, 2016
 
December 31, 2015
2022 First Lien Notes
$
739

 
$
737

2023 First Lien Notes
569

 
568

2024 First Lien Notes
484

 
484

2026 First Lien Notes
616

 

Total First Lien Notes
$
2,408

 
$
1,789

On May 31, 2016, we issued $625 million in aggregate principal amount of 5.25% senior secured notes due 2026 in a private placement. Our 2026 First Lien Notes bear interest at 5.25% payable semi-annually on June 1 and December 1 of each year, beginning on December 1, 2016. Our 2026 First Lien Notes mature on June 1, 2026 and contain substantially similar covenants, qualifications, exceptions and limitations as our First Lien Notes. We recorded approximately $9 million in deferred financing costs during the second quarter of 2016 related to the issuance of our 2026 First Lien Notes.
Corporate Revolving Facility and Other Letter of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at September 30, 2016 and December 31, 2015 (in millions):
 
September 30, 2016
 
December 31, 2015
Corporate Revolving Facility(1)
$
268

 
$
316

CDHI
261

 
241

Various project financing facilities
232

 
198

Total
$
761

 
$
755

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

13



On February 8, 2016, we amended our Corporate Revolving Facility, extending the maturity by two years to June 27, 2020, and increasing the capacity by an additional $178 million to $1,678 million through June 27, 2018, reverting back to $1,520 million through the maturity date. Further, we increased the letter of credit sublimit by $250 million to $1.0 billion and extended the maturity by two years to June 27, 2020.
Fair Value of Debt
We record our debt instruments based on contractual terms, net of any applicable premium or discount. The following table details the fair values and carrying values of our debt instruments at September 30, 2016 and December 31, 2015 (in millions):
 
September 30, 2016
 
December 31, 2015
 
Fair Value
 
Carrying Value
 
Fair Value
 
Carrying Value
Senior Unsecured Notes
$
3,429

 
$
3,410

 
$
3,063

 
$
3,406

First Lien Term Loans
2,694

 
2,637

 
3,197

 
3,277

First Lien Notes
2,537

 
2,408

 
1,885

 
1,789

Project financing, notes payable and other(1)
1,576

 
1,537

 
1,653

 
1,608

CCFC Term Loans
1,566

 
1,556

 
1,494

 
1,565

Total
$
11,802

 
$
11,548

 
$
11,292

 
$
11,645

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

We measure the fair value of our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes and CCFC Term Loans using market information, including quoted market prices or dealer quotes for the identical liability when traded as an asset (categorized as level 2). We measure the fair value of our project financing, notes payable and other debt instruments using discounted cash flow analyses based on our current borrowing rates for similar types of borrowing arrangements (categorized as level 3). We do not have any debt instruments with fair value measurements categorized as level 1 within the fair value hierarchy.
5.
Assets and Liabilities with Recurring Fair Value Measurements
Cash Equivalents — Highly liquid investments which meet the definition of cash equivalents, primarily investments in money market accounts and other interest-bearing accounts, are included in both our cash and cash equivalents and our restricted cash on our Consolidated Condensed Balance Sheets. Certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. We do not have any cash equivalents invested in institutional prime money market funds which require use of a floating net asset value and are subject to liquidity fees and redemption restrictions. Our cash equivalents are classified within level 1 of the fair value hierarchy.
Margin Deposits and Margin Deposits Posted with Us by Our Counterparties — Margin deposits and margin deposits posted with us by our counterparties represent cash collateral paid between our counterparties and us to support our commodity contracts. Our margin deposits and margin deposits posted with us by our counterparties are generally cash and cash equivalents and 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 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.

14



The fair value of our derivatives includes consideration of our credit standing, the credit standing of our counterparties and the effect of credit enhancements, if any. We have also recorded credit reserves in the determination of fair value based on our expectation of how market participants would determine fair value. Such valuation adjustments are generally based on market evidence, if available, or our best estimate.
Our level 1 fair value derivative instruments primarily consist of power and natural gas swaps, futures and options traded on the NYMEX or Intercontinental Exchange.
Our level 2 fair value derivative instruments primarily consist of interest rate hedging instruments and OTC power and natural gas forwards for which market-based pricing inputs in the principal or most advantageous market are representative of executable prices for market participants. These inputs are observable at commonly quoted intervals for substantially the full term of the instruments. In certain instances, our level 2 derivative instruments may utilize models to measure fair value. These models are industry-standard models that incorporate various assumptions, including quoted interest rates, correlation, volatility, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Our level 3 fair value derivative instruments may consist of OTC power and natural gas forwards and options where pricing inputs are unobservable, as well as other complex and structured transactions. Complex or structured transactions are tailored to our customers’ needs and can introduce the need for internally-developed model inputs which might not be observable in or corroborated by the market. When such inputs have a significant effect on the measurement of fair value, the instrument is categorized in level 3. Our valuation models may incorporate historical correlation information and extrapolate available broker and other information to future periods. OTC options are valued using industry-standard models, including the Black-Scholes option-pricing model. At each balance sheet date, we perform an analysis of all instruments subject to fair value measurement and include in level 3 all of those whose fair value is based on significant unobservable inputs.
For a definition of the different levels in the fair value hierarchy, see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Application of Critical Accounting Policies — Fair Value Measurements” in our 2015 Form 10-K.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect our estimate of the fair value of our assets and liabilities and their placement within the fair value hierarchy levels. The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2016 and December 31, 2015, by level within the fair value hierarchy:
 
Assets and Liabilities with Recurring Fair Value Measures as of September 30, 2016
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
786

 
$

 
$

 
$
786

Margin deposits
120

 

 

 
120

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,036

 

 

 
1,036

Commodity forward contracts(2)

 
178

 
60

 
238

Interest rate hedging instruments

 
8

 

 
8

Total assets
$
1,942

 
$
186

 
$
60

 
$
2,188

Liabilities:
 
 
 
 
 
 
 
Margin deposits posted with us by our counterparties
$
30

 
$

 
$

 
$
30

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,004

 

 

 
1,004

Commodity forward contracts(2)

 
310

 
32

 
342

Interest rate hedging instruments

 
81

 

 
81

Total liabilities
$
1,034

 
$
391

 
$
32

 
$
1,457


15



 
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2015
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
1,134

 
$

 
$

 
$
1,134

Margin deposits
89

 

 

 
89

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,736

 

 

 
1,736

Commodity forward contracts(2)

 
220

 
54

 
274

Interest rate hedging instruments

 
1

 

 
1

Total assets
$
2,959

 
$
221

 
$
54

 
$
3,234

Liabilities:
 
 
 
 
 
 
 
Margin deposits posted with us by our counterparties
$
35

 
$

 
$

 
$
35

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,604

 

 

 
1,604

Commodity forward contracts(2)

 
413

 
100

 
513

Interest rate hedging instruments

 
90

 

 
90

Total liabilities
$
1,639

 
$
503

 
$
100

 
$
2,242

___________
(1)
As of September 30, 2016 and December 31, 2015, we had cash equivalents of $561 million and $906 million included in cash and cash equivalents and $225 million and $228 million included in restricted cash, respectively.
(2)
Includes OTC swaps and options.
At September 30, 2016 and December 31, 2015, the derivative instruments classified as level 3 primarily included commodity contracts, which are classified as level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net derivative position classified as level 3 is predominantly driven by market commodity prices. The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at September 30, 2016 and December 31, 2015:
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
September 30, 2016
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
Power Contracts
 
$
7

 
Discounted cash flow
 
Market price (per MWh)
 
$9.62 — $80.18/MWh
Power Congestion Products
 
$
12

 
Discounted cash flow
 
Market price (per MWh)
 
$(11.47) — $10.89/MWh
 
 
 
 
 
 
 
 
 
 
 
December 31, 2015
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
Power Contracts
 
$
(54
)
 
Discounted cash flow
 
Market price (per MWh)
 
$6.72 — $83.25/MWh
Power Congestion Products
 
$
8

 
Discounted cash flow
 
Market price (per MWh)
 
$(11.47) — $12.19/MWh

16



The following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the periods indicated (in millions):
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2016
 
2015
 
2016
 
2015
Balance, beginning of period
 
$
(63
)
 
$
243

 
$
(46
)
 
$
85

Realized and mark-to-market gains (losses):
 
 
 
 
 
 
 
 
Included in net income:
 
 
 
 
 
 
 
 
Included in operating revenues(1)
 
30

 
70

 
9

 
236

Included in fuel and purchased energy expense(2)
 
(31
)
 
(2
)
 
(24
)
 
(2
)
Purchases and settlements:
 
 
 
 
 
 
 
 
Purchases
 
1

 

 
4

 
3

Settlements
 
15

 
(8
)
 
(4
)
 
(24
)
Transfers in and/or out of level 3(3):
 
 
 
 
 
 
 
 
Transfers into level 3(4)
 
1

 

 

 

Transfers out of level 3(5)
 
75

 
(11
)
 
89

 
(6
)
Balance, end of period
 
$
28

 
$
292

 
$
28

 
$
292

Change in unrealized gains (losses) relating to instruments still held at end of period
 
$
(1
)
 
$
68

 
$
(15
)
 
$
234

___________
(1)
For power contracts and other power-related products, included on our Consolidated Condensed Statements of Operations.
(2)
For natural gas and power contracts, swaps and options, included on our Consolidated Condensed Statements of Operations.
(3)
We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no transfers into or out of level 1 for each of the three and nine months ended September 30, 2016 and 2015.
(4)
We had $1 million and nil in gains transferred out of level 2 into level 3 for the three months ended September 30, 2016 and 2015, respectively. There were no transfers out of level 2 into level 3 for each of the nine months ended September 30, 2016 and 2015.
(5)
We had $(75) million in losses and $11 million in gains transferred out of level 3 into level 2 for the three months ended September 30, 2016 and 2015, respectively, and $(89) million in losses and $6 million in gains transferred out of level 3 into level 2 for the nine months ended September 30, 2016 and 2015, respectively, due to changes in market liquidity in various power markets.
6.
Derivative Instruments
Types of Derivative Instruments and Volumetric Information
Commodity Instruments — We are exposed to changes in prices for the purchase and sale of power, natural gas, fuel oil, environmental products and other energy commodities. We use derivatives, which include physical commodity contracts and financial commodity instruments such as OTC and exchange traded swaps, futures, options, forward agreements and instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) or instruments that settle on power price relationships between delivery points for the purchase and sale of power and natural gas to attempt to maximize the risk-adjusted returns by economically hedging a portion of the commodity price risk associated with our assets. By entering into these transactions, we are able to economically hedge a portion of our Spark Spread at estimated generation and prevailing price levels.
We also engage in limited trading activities related to our commodity derivative portfolio as authorized by our Board of Directors and monitored by our Chief Risk Officer and Risk Management Committee of senior management. These transactions are executed primarily for the purpose of providing improved price and price volatility discovery, greater market access, and profiting from our market knowledge, all of which benefit our asset hedging activities. Our trading gains and losses were not material for each of the three and nine months ended September 30, 2016 and 2015.
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 September 30, 2016, the maximum length of time over which we were hedging using interest rate hedging instruments designated as cash flow hedges was 7 years.

17



As of September 30, 2016 and December 31, 2015, the net forward notional buy (sell) position of our outstanding commodity derivative instruments that did not qualify or were not designated under the normal purchase normal sale exemption and our interest rate hedging instruments were as follows (in millions):
Derivative Instruments
 
Notional Amounts
 
September 30, 2016
 
December 31, 2015
Power (MWh)
 
(49
)
 
(41
)
Natural gas (MMBtu)
 
846

 
996

Environmental credits (Tonnes)
 
17

 
8

Interest rate hedging instruments
 
$
3,791

(1) 
$
1,320

___________
(1)
We entered into interest rate hedging instruments during the second quarter of 2016 to hedge approximately $2.5 billion of variable rate corporate debt for 2017 through 2019 which effectively places a ceiling on LIBOR at rates varying from 1.44% to 1.8125% for hedged interest payments. See Note 4 for a further discussion of our First Lien Term Loans.
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. Currently, we do not believe that it is probable that any additional collateral posted as a result of a one credit notch downgrade from its current level would be material. The aggregate fair value of our derivative liabilities with credit risk-related contingent provisions as of September 30, 2016, was $4 million for which we have posted collateral of $1 million by posting margin deposits or granting additional first priority liens on the assets currently subject to first priority liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. However, if our credit rating were downgraded by one notch from its current level, we estimate that additional collateral of $4 million would be required and that no counterparty could request immediate, full settlement.
Accounting for Derivative Instruments
We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Condensed Statements of Operations until the period of delivery. Revenues and expenses derived from instruments that qualified for hedge accounting or represent an economic hedge are recorded in the same financial statement line item as the item being hedged. Hedge accounting requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We present the cash flows from our derivatives in the same category as the item being hedged (or economically hedged) within operating activities on our Consolidated Condensed Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows are classified within financing activities.
Cash Flow Hedges — We only apply hedge accounting to our interest rate hedging instruments. We report the effective portion of the mark-to-market gain or loss on our interest rate hedging instruments designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Gains and losses due to ineffectiveness on interest rate hedging instruments are recognized currently in earnings as a component of interest expense. If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value are recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedge instrument remains deferred in AOCI until such time as the forecasted transaction affects earnings or until it is determined that the forecasted transaction is probable of not occurring.
Derivatives Not Designated as Hedging Instruments — We enter into power, natural gas, interest rate, environmental product and fuel oil transactions that primarily act as economic hedges to our asset and interest rate portfolio, but either do not qualify as hedges under the hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected. Changes in fair value of commodity derivatives not designated as hedging instruments are recognized currently in earnings and are separately stated on our Consolidated Condensed Statements of Operations in mark-to-market gain/loss as a component of operating revenues (for power and Heat Rate swaps and options) and fuel and purchased energy expense (for natural gas, power, environmental product and fuel oil contracts, swaps and options). Changes in fair value of interest rate derivatives not designated as hedging instruments are recognized currently in earnings as interest expense.

18



Derivatives Included on Our Consolidated Condensed Balance Sheets
The following tables present the fair values of our derivative instruments recorded on our Consolidated Condensed Balance Sheets by location and hedge type at September 30, 2016 and December 31, 2015 (in millions):
 
September 30, 2016
  
Commodity
Instruments
 
Interest Rate
Hedging Instruments
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
959

 
$

 
$
959

Long-term derivative assets
315

 
8

 
323

Total derivative assets
$
1,274

 
$
8

 
$
1,282

 
 
 
 
 
 
Current derivative liabilities
$
958

 
$
33

 
$
991

Long-term derivative liabilities
388

 
48

 
436

Total derivative liabilities
$
1,346

 
$
81

 
$
1,427

Net derivative assets (liabilities)
$
(72
)
 
$
(73
)
 
$
(145
)

 
December 31, 2015
 
Commodity
Instruments
 
Interest Rate
Hedging Instruments
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
1,698

 
$

 
$
1,698

Long-term derivative assets
312

 
1

 
313

Total derivative assets
$
2,010

 
$
1

 
$
2,011

 
 
 
 
 
 
Current derivative liabilities
$
1,697

 
$
37

 
$
1,734

Long-term derivative liabilities
420

 
53

 
473

Total derivative liabilities
$
2,117

 
$
90

 
$
2,207

Net derivative assets (liabilities)
$
(107
)
 
$
(89
)
 
$
(196
)

 
September 30, 2016
 
December 31, 2015
 
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
$
8

 
$
81

 
$
1

 
$
90

Total derivatives designated as cash flow hedging instruments
$
8

 
$
81

 
$
1

 
$
90

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity instruments
$
1,274

 
$
1,346

 
$
2,010

 
$
2,117

Total derivatives not designated as hedging instruments
$
1,274

 
$
1,346

 
$
2,010

 
$
2,117

Total derivatives
$
1,282

 
$
1,427

 
$
2,011

 
$
2,207

We elected not to offset fair value amounts recognized as derivative instruments on our Consolidated Condensed Balance Sheets that are executed with the same counterparty under master netting arrangements or other contractual netting provisions negotiated with the counterparty. Our netting arrangements include a right to set off or net together purchases and sales of similar products in the margining or settlement process. In some instances, we have also negotiated cross commodity netting rights which allow for the net presentation of activity with a given counterparty regardless of product purchased or sold. We also post cash collateral in support of our derivative instruments which may also be subject to a master netting arrangement with the same counterparty.

19



The tables below set forth our net exposure to derivative instruments after offsetting amounts subject to a master netting arrangement with the same counterparty at September 30, 2016 and December 31, 2015 (in millions):
 
 
September 30, 2016
 
 
Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets
 
 
Gross Amounts Presented on our Consolidated Condensed Balance Sheets
 
Derivative Asset (Liability) not Offset on the Consolidated Condensed Balance Sheets
 
Margin/Cash (Received) Posted (1)
 
Net Amount
Derivative assets:
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
1,036

 
$
(988
)
 
$
(48
)
 
$

Commodity forward contracts
 
238

 
(128
)
 
(17
)
 
93

Interest rate hedging instruments
 
8

 

 

 
8

Total derivative assets
 
$
1,282

 
$
(1,116
)
 
$
(65
)
 
$
101

Derivative (liabilities):
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
(1,004
)
 
$
988

 
$
16

 
$

Commodity forward contracts
 
(342
)
 
128

 

 
(214
)
Interest rate hedging instruments
 
(81
)
 

 

 
(81
)
Total derivative (liabilities)
 
$
(1,427
)
 
$
1,116

 
$
16

 
$
(295
)
Net derivative assets (liabilities)
 
$
(145
)
 
$

 
$
(49
)
 
$
(194
)
 
 
December 31, 2015
 
 
Gross Amounts Not Offset on the Consolidated Condensed Balance Sheets
 
 
Gross Amounts Presented on our Consolidated Condensed Balance Sheets
 
Derivative Asset (Liability) not Offset on the Consolidated Condensed Balance Sheets
 
Margin/Cash (Received) Posted (1)
 
Net Amount
Derivative assets:
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
1,736

 
$
(1,602
)
 
$
(134
)
 
$

Commodity forward contracts
 
274

 
(202
)
 
(3
)
 
69

Interest rate hedging instruments
 
1

 

 

 
1

Total derivative assets
 
$
2,011

 
$
(1,804
)
 
$
(137
)
 
$
70

Derivative (liabilities):
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
(1,604
)
 
$
1,602

 
$
2

 
$

Commodity forward contracts
 
(513
)
 
202

 
3

 
(308
)
Interest rate hedging instruments
 
(90
)
 

 

 
(90
)
Total derivative (liabilities)
 
$
(2,207
)
 
$
1,804

 
$
5

 
$
(398
)
Net derivative assets (liabilities)
 
$
(196
)
 
$

 
$
(132
)
 
$
(328
)
____________
(1)
Negative balances represent margin deposits posted with us by our counterparties related to our derivative activities that are subject to a master netting arrangement. Positive balances reflect margin deposits and natural gas and power prepayments posted by us with our counterparties related to our derivative activities that are subject to a master netting arrangement. See Note 7 for a further discussion of our collateral.
Derivatives Included on Our Consolidated Condensed Statements of Operations
Changes in the fair values of our derivative instruments (both assets and liabilities) are reflected either in cash for option premiums paid or collected, in OCI, net of tax, for the effective portion of derivative instruments which qualify for and we have elected cash flow hedge accounting treatment, or on our Consolidated Condensed Statements of Operations as a component of mark-to-market activity within our earnings.

20



The following tables detail the components of our total activity for both the net realized gain (loss) and the net mark-to-market gain (loss) recognized from our derivative instruments in earnings and where these components were recorded on our Consolidated Condensed Statements of Operations for the periods indicated (in millions):
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
Realized gain (loss)(1)(2)
 
 
 
 
 
 
 
Commodity derivative instruments
$
32

 
$
160

 
$
213

 
$
323

Total realized gain (loss)
$
32

 
$
160

 
$
213

 
$
323

 
 
 
 
 
 
 
 
Mark-to-market gain (loss)(3)
 
 
 
 
 
 
 
Commodity derivative instruments
$
109

 
$
(75
)
 
$
(22
)
 
$
(6
)
Interest rate hedging instruments

 
1

 
1

 
2

Total mark-to-market gain (loss)
$
109

 
$
(74
)
 
$
(21
)
 
$
(4
)
Total activity, net
$
141

 
$
86

 
$
192

 
$
319

___________
(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 derivative activity related to the acquisition of Champion Energy.
(3)
In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification of AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
Realized and mark-to-market gain (loss)
 
 
 
 
 
 
 
Derivatives contracts included in operating revenues(1)(2)
$
308

 
$
189

 
$
240

 
$
423

Derivatives contracts included in fuel and purchased energy expense(1)(2)
(167
)
 
(104
)
 
(49
)
 
(106
)
Interest rate hedging instruments included in interest expense(3)

 
1

 
1

 
2

Total activity, net
$
141

 
$
86

 
$
192

 
$
319

___________
(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 derivative activity related to the acquisition of Champion Energy.
(3)
In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification of AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.
Derivatives Included in OCI and AOCI
The following table details the effect of our net derivative instruments that qualified for hedge accounting treatment and are included in OCI and AOCI for the periods indicated (in millions):
 
Three Months Ended September 30,
 
Three Months Ended September 30,
 
Gain (Loss) Recognized in
OCI (Effective Portion)
 
Gain (Loss) Reclassified from
AOCI into Income (Effective Portion)(3)(4)
 
2016
 
2015
 
2016
 
2015
 
Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate hedging instruments(1)(2)
$
18

 
$
(4
)
 
$
(11
)
 
$
(12
)
 
Interest expense

21



 
Nine Months Ended September 30,
 
Nine Months Ended September 30,
 
Gain (Loss) Recognized in
OCI (Effective Portion)
 
Gain (Loss) Reclassified from
AOCI into Income (Effective Portion)(3)(4)
 
2016
 
2015
 
2016
 
2015
 
Affected Line Item on the Consolidated Condensed Statements of Operations
Interest rate hedging instruments(1)(2)
$

 
$
4

 
$
(33
)
 
$
(36
)
 
Interest expense
____________
(1)
We did not record any material gain (loss) on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during the three and nine months ended September 30, 2016 and 2015.
(2)
We recorded an income tax expense of nil for each of the three and nine months ended September 30, 2016 and 2015, in AOCI related to our cash flow hedging activities.
(3)
Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $127 million and $127 million at September 30, 2016 and December 31, 2015, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $11 million and $11 million at September 30, 2016 and December 31, 2015, respectively.
(4)
Includes a loss of $1 million for each of the three and nine months ended September 30, 2016, that was reclassified from AOCI to interest expense, where the hedged transactions are no longer expected to occur.
We estimate that pre-tax net losses of $39 million would be reclassified from AOCI into interest expense during the next 12 months as the hedged transactions settle; however, the actual amounts that will be reclassified will likely vary based on changes in interest rates. Therefore, we are unable to predict what the actual reclassification from AOCI into earnings (positive or negative) will be for the next 12 months.
7.
Use of Collateral
We use margin deposits, prepayments and letters of credit as credit support with and from our counterparties for commodity procurement and risk management activities. In addition, we have granted additional first priority liens on the assets currently subject to first priority liens under various debt agreements as collateral under certain of our power and natural gas agreements and certain of our interest rate hedging instruments in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to the counterparties under such agreements. The counterparties under such agreements share the benefits of the collateral subject to such first priority liens pro rata with the lenders under our various debt agreements.
The table below summarizes the balances outstanding under margin deposits, natural gas and power prepayments, and exposure under letters of credit and first priority liens for commodity procurement and risk management activities as of September 30, 2016 and December 31, 2015 (in millions):
 
September 30, 2016
 
December 31, 2015
Margin deposits(1)
$
120

 
$
89

Natural gas and power prepayments
27

 
34

Total margin deposits and natural gas and power prepayments with our counterparties(2)
$
147

 
$
123

 
 
 
 
Letters of credit issued
$
586

 
$
600

First priority liens under power and natural gas agreements(3)
299

 
382

First priority liens under interest rate hedging instruments
83

 
92

Total letters of credit and first priority liens with our counterparties
$
968

 
$
1,074

 
 
 
 
Margin deposits posted with us by our counterparties(1)(4)
$
30

 
$
35

Letters of credit posted with us by our counterparties
35

 
24

Total margin deposits and letters of credit posted with us by our counterparties
$
65

 
$
59


22



___________
(1)
Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Condensed Balance Sheets. We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation, and we do not offset amounts recognized for the right to reclaim, or the obligation to return, cash collateral with corresponding derivative instrument fair values. See Note 6 for further discussion of our derivative instruments subject to master netting arrangements.
(2)
At September 30, 2016 and December 31, 2015, $138 million and $101 million, respectively, were included in margin deposits and other prepaid expense and $9 million and $22 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.
(3)
Includes $268 million and $345 million related to first priority liens under power supply contracts associated with our retail hedging activities at September 30, 2016 and December 31, 2015, respectively.
(4)
Included in other current liabilities on our Consolidated Condensed Balance Sheets.
Future collateral requirements for cash, first priority liens and letters of credit may increase or decrease based on the extent of our involvement in hedging and optimization contracts, movements in commodity prices, and also based on our credit ratings and general perception of creditworthiness in our market.
8.
Income Taxes
Income Tax Expense (Benefit)

The table below shows our consolidated income tax expense (benefit) from continuing operations (excluding noncontrolling interest) and our effective tax rates for the periods indicated (in millions):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
Income tax expense (benefit)
$
(4
)
 
$
28

 
$
17

 
$
32

Effective tax rate
(1
)%
 
9
%
 
20
%
 
10
%
Our income tax rates do not bear a customary relationship to statutory income tax rates primarily as a result of the effect of our NOLs, changes in unrecognized tax benefits and valuation allowances. For the three and nine months ended September 30, 2016 and 2015, our income tax expense (benefit) is largely comprised of discrete tax items and estimated state and foreign income taxes in jurisdictions where we do not have NOLs or valuation allowances. See Note 10 in our 2015 Form 10-K for further information regarding our NOLs.   
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 occurred. Any adjustment of state or federal returns would likely result in a reduction of deferred tax assets rather than a cash payment of income taxes in tax jurisdictions where we have NOLs.
Valuation Allowance — U.S. GAAP requires that we consider all available evidence, both positive and negative, and tax planning strategies to determine whether, based on the weight of that evidence, a valuation allowance is needed to reduce the value of deferred tax assets. Future realization of the tax benefit of an existing deductible temporary difference or carryforward ultimately depends on the existence of sufficient taxable income of the appropriate character within the carryback or carryforward periods available under the tax law. Due to our history of losses, we were unable to assume future profits; however, we are able to consider available tax planning strategies.
Unrecognized Tax Benefits — At September 30, 2016, we had unrecognized tax benefits of $58 million. If recognized, $18 million of our unrecognized tax benefits could affect the annual effective tax rate and $40 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 $13 million for income tax matters at September 30, 2016. We recognize interest and penalties related to unrecognized tax benefits in income tax expense (benefit) on our Consolidated Condensed Statements of Operations. We believe that it is reasonably possible that a decrease within the range of nil and $19 million in unrecognized tax benefits could occur within the next twelve months.

23



9.
Earnings per Share
We include restricted stock units for which no future service is required as a condition to the delivery of the underlying common stock in our calculation of weighted average shares outstanding. Reconciliations of the amounts used in the basic and diluted earnings per common share computations for the three and nine months ended September 30, 2016 and 2015 are as follows (shares in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
Diluted weighted average shares calculation:
 
 
 
 
 
 
 
Weighted average shares outstanding (basic)
354,215

 
355,443

 
353,929

 
365,053

Share-based awards
2,137

 
2,233

 
2,051

 
3,166

Weighted average shares outstanding (diluted)
356,352

 
357,676

 
355,980

 
368,219

We excluded the following items from diluted earnings per common share for the three and nine months ended September 30, 2016 and 2015, because they were anti-dilutive (shares in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
Share-based awards
1,610

 
4,982

 
1,679

 
4,208

10.
Stock-Based Compensation
Equity Classified Share-Based Awards
Stock-based compensation expense recognized for our equity classified share-based awards was $7 million and $8 million for the three months ended September 30, 2016 and 2015, respectively, and $22 million and $24 million for the nine months ended September 30, 2016 and 2015, respectively. We did not record any significant tax benefits related to stock-based compensation expense in any period as we are not benefiting from a significant portion of our deferred tax assets, including deductions related to stock-based compensation expense. In addition, we did not capitalize any stock-based compensation expense as part of the cost of an asset for the nine months ended September 30, 2016 and 2015. At September 30, 2016, there was unrecognized compensation cost of $31 million related to restricted stock which is expected to be recognized over a weighted average period of 1.4 years. We issue new shares from our share reserves set aside for the Calpine Equity Incentive Plans when stock options are exercised and for other share-based awards.
A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the nine months ended September 30, 2016, is as follows:
 
Number of
Restricted
Stock Awards
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2015
3,528,270

 
$
19.91

Granted
2,947,826

 
$
12.40

Forfeited
218,932

 
$
16.21

Vested
1,301,920

 
$
19.02

Nonvested — September 30, 2016
4,955,244

 
$
15.84

The total fair value of our restricted stock and restricted stock units that vested during the nine months ended September 30, 2016 and 2015 was approximately $16 million and $34 million, respectively.
Liability Classified Share-Based Awards
During the first quarter of 2016, our Board of Directors approved the award of performance share units to certain senior management employees. These performance share units will be settled in cash with payouts based on the relative performance of Calpine’s TSR over the three-year performance period of January 1, 2016 through December 31, 2018 compared with the TSR performance of the S&P 500 companies over the same period, as modified by the IPP Sector Modifier which may either increase or decrease the payout based on Calpine’s TSR within its IPP Peers. The performance share units vest on the last day of the

24



performance period and will be settled in cash; thus, these awards are liability classified and are measured at fair value using a Monte Carlo simulation model at each reporting date until settlement. Stock-based compensation expense recognized related to our liability classified share-based awards was $(1) million for each of the three months ended September 30, 2016 and 2015 and $1 million and $(5) million for the nine months ended September 30, 2016 and 2015, respectively.
A summary of our performance share unit activity for the nine months ended September 30, 2016, is as follows:
 
Number of
Performance Share Units
 
Weighted
Average
Grant-Date
Fair Value
Nonvested — December 31, 2015
517,906

 
$
23.36

Granted
657,807

 
$
14.81

Vested(1)
3,249

 
$
23.91

Nonvested — September 30, 2016
1,172,464

 
$
18.56

___________
(1)
In accordance with the applicable performance share unit agreements, performance share units granted to employees who meet the retirement eligibility requirements stipulated in the Equity Plan are fully vested upon the later of the date on which the employee becomes eligible to retire or one-year anniversary of the grant date.
For a further discussion of the Calpine Equity Incentive Plans, see Note 12 in our 2015 Form 10-K.
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.
12.
Segment Information
We assess our business on a regional basis due to the effect on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors affecting supply and demand. At September 30, 2016, our reportable segments were West (including geothermal), Texas and East (including Canada). 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 reviewed by our chief operating decision maker to assess the performance of our segments. The tables below show our financial data for our segments for the periods indicated (in millions).

25



 
Three Months Ended September 30, 2016
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
524

 
$
1,067

 
$
764

 
$

 
$
2,355

Intersegment revenues
1

 
3

 
2

 
(6
)
 

Total operating revenues
$
525

 
$
1,070

 
$
766

 
$
(6
)
 
$
2,355

Commodity Margin
$
298

 
$
198

 
$
324

 
$

 
$
820

Add: Mark-to-market commodity activity, net and other(1)
11

 
110

 
(51
)
 
(7
)
 
63

Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
79

 
65

 
78

 
(7
)
 
215

Depreciation and amortization expense
56

 
53

 
52

 

 
161

Sales, general and other administrative expense
9

 
13

 
12

 
(1
)
 
33

Other operating expenses
8

 
2

 
7

 
1

 
18

(Income) from unconsolidated investments in power plants

 

 
(6
)
 

 
(6
)
Income from operations
157

 
175

 
130

 

 
462

Interest expense, net of interest income
 
 
 
 
 
 
 
 
157

Other (income) expense, net
 
 
 
 
 
 
 
 
8

Income before income taxes
 
 
 
 
 
 
 
 
$
297


 
Three Months Ended September 30, 2015
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
736

 
$
709

 
$
503

 
$

 
$
1,948

Intersegment revenues
1

 
4

 
3

 
(8
)
 

Total operating revenues
$
737

 
$
713

 
$
506

 
$
(8
)
 
$
1,948

Commodity Margin
$
385

 
$
264

 
$
325

 
$

 
$
974

Add: Mark-to-market commodity activity, net and other(1)
68

 
(98
)
 
(62
)
 
(7
)
 
(99
)
Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
87

 
62

 
57

 
(6
)
 
200

Depreciation and amortization expense
61

 
58

 
48

 
(1
)
 
166

Sales, general and other administrative expense
7

 
15

 
10

 
1

 
33

Other operating expenses
8

 
2

 
8

 
(2
)
 
16

(Income) from unconsolidated investments in power plants

 

 
(6
)
 

 
(6
)
Income from operations
290

 
29

 
146

 
1

 
466

Interest expense, net of interest income
 
 
 
 
 
 
 
 
158

Other (income) expense, net
 
 
 
 
 
 
 
 
1

Income before income taxes
 
 
 
 
 
 
 
 
$
307



26



 
Nine Months Ended September 30, 2016
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
1,159

 
$
2,129

 
$
1,846

 
$

 
$
5,134

Intersegment revenues
4

 
10

 
9

 
(23
)
 

Total operating revenues
$
1,163

 
$
2,139

 
$
1,855

 
$
(23
)
 
$
5,134

Commodity Margin
$
749

 
$
511

 
$
797

 
$

 
$
2,057

Add: Mark-to-market commodity activity, net and other(2)
(5
)
 
7

 
(44
)
 
(21
)
 
(63
)
Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
268

 
236

 
258

 
(21
)
 
741

Depreciation and amortization expense
181

 
159

 
163

 

 
503

Sales, general and other administrative expense
27

 
43

 
36

 

 
106

Other operating expenses
23

 
6

 
27

 
(1
)
 
55

(Income) from unconsolidated investments in power plants

 

 
(16
)
 

 
(16
)
Income from operations
245

 
74

 
285

 
1

 
605

Interest expense, net of interest income
 
 
 
 
 
 
 
 
469

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
36

Income before income taxes
 
 
 
 
 
 
 
 
$
100


 
Nine Months Ended September 30, 2015
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Revenues from external customers
$
1,672

 
$
1,860

 
$
1,504

 
$

 
$
5,036

Intersegment revenues
3

 
12

 
7

 
(22
)
 

Total operating revenues
$
1,675

 
$
1,872

 
$
1,511

 
$
(22
)
 
$
5,036

Commodity Margin
$
843

 
$
583

 
$
740

 
$

 
$
2,166

Add: Mark-to-market commodity activity, net and other(2)
173

 
(47
)
 
(84
)
 
(21
)
 
21

Less:
 
 
 
 
 
 
 
 
 
Plant operating expense
313

 
233

 
206

 
(20
)
 
732

Depreciation and amortization expense
193

 
157

 
135

 
(1
)
 
484

Sales, general and other administrative expense
23

 
47

 
29

 
1

 
100

Other operating expenses
28

 
6

 
24

 
(2
)
 
56

(Income) from unconsolidated investments in power plants

 

 
(18
)
 

 
(18
)
Income from operations
459


93


280


1

 
833

Interest expense, net of interest income
 
 
 
 
 
 
 
 
468

Debt modification and extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
40

Income before income taxes
 
 
 
 
 
 
 
 
$
325

_________
(1)
Includes $40 million and $41 million of lease levelization and $25 million and $4 million of amortization expense for the three months ended September 30, 2016 and 2015, respectively.
(2)
Includes $(2) million and $(1) million of lease levelization and $79 million and $11 million of amortization expense for the nine months ended September 30, 2016 and 2015, respectively.

27



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 one of the largest power generators in the U.S. measured by power produced. We own and operate primarily natural gas-fired and geothermal power plants in North America and have a significant presence in major competitive wholesale power markets in California (included in our West segment), Texas (included in our Texas segment) and the Northeast and Mid-Atlantic regions (included in our East segment) of the U.S. We sell power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. We have invested in clean power generation to become a recognized leader in developing, constructing, owning and operating an environmentally responsible portfolio of flexible and reliable power plants.
In order to manage our various physical assets and contractual obligations, we execute commodity and commodity transportation agreements within the guidelines of our Risk Management Policy. We purchase primarily natural gas and some fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We also purchase power for sale to our retail customers and purchase electric transmission rights to deliver power to our customers. We also enter into natural gas, power, environmental product, fuel oil and other physical and financial commodity contracts to hedge certain business risks and optimize our portfolio of power plants. Seasonality and weather can have a significant effect on our results of operations and are also considered in our hedging and optimization activities.
Our capital allocation philosophy seeks to maximize levered cash returns to equity while maintaining a strong balance sheet. We strive to enhance shareholder value through the combination of investing for growth at attractive returns, managing the balance sheet through debt pay down and returning capital to shareholders. We view our stock as an attractive investment opportunity, and we use the projected returns from share repurchases as the benchmark against which all other investment decisions are measured. We are committed to remaining fiscally disciplined and balanced in our capital allocation decisions.
Our goal is to be recognized as the premier power generation company in the U.S. as measured by our employees, shareholders, customers and policy-makers as well as the communities in which our facilities are located. We seek to achieve sustainable growth through financially disciplined power plant development, construction, acquisition, operation and ownership, and by pursuing opportunities to improve our fleet performance and reduce operating costs. We continue to make significant progress to deliver financially disciplined growth, to enhance shareholder value through disciplined capital allocation including the return of capital to shareholders and to manage the balance sheet for future growth and success with the following achievements during 2016:
We produced approximately 86 million MWh of electricity during the nine months ended September 30, 2016.
Our employees achieved a total recordable incident rate of 0.56 recordable injuries per 100 employees during the nine months ended September 30, 2016 which places us in the first quartile performance for power generation companies with 1,000 or more employees.
Our entire fleet achieved a starting reliability of 97.8% during the nine months ended September 30, 2016.
On February 5, 2016, we completed the purchase of Granite Ridge Energy Center, a power plant with a nameplate capacity of 745 MW (summer peaking capacity of 695 MW), for approximately $500 million, excluding working capital and other adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant increased capacity in our East segment, specifically the constrained New England market.
On February 8, 2016, we amended our Corporate Revolving Facility, extending the maturity by two years to June 27, 2020, and increasing the capacity by an additional $178 million to $1,678 million through June 27, 2018, reverting back to $1,520 million through the maturity date. Further, we increased the letter of credit sublimit by $250 million to $1.0 billion and extended the maturity by two years to June 27, 2020.
On April 1, 2016, we entered into an asset sale agreement for the sale of substantially all of the assets comprising our South Point Energy Center to Nevada Power Company d/b/a NV Energy for approximately $76 million plus the

28



assumption by the purchaser of existing transmission capacity contracts with a future net present value payment obligation of approximately $112 million, approximately $9 million in remaining tribal lease costs and approximately $21 million in near-term repairs, maintenance and capital improvements to restore the power plant to full capacity. The sale is subject to certain conditions precedent, as well as federal and state regulatory approvals, and is expected to close no later than the first quarter of 2017. This transaction supports our effort to divest non-core assets outside our strategic concentration.
In May 2016, we repaid our 2019 and 2020 First Lien Term Loans with the proceeds from our New 2023 First Lien Term Loan and 2026 First Lien Notes which extended the maturity on approximately $1.2 billion of corporate debt.
On October 9, 2016, we announced that we entered into an agreement to purchase NAES and a swap contract for approximately $800 million plus approximately $100 million of net working capital estimated at closing. We expect to recover approximately $200 million through collateral synergies and the runoff of acquired legacy hedges, substantially within the first year. NAES is a commercial and industrial retail electricity provider with customers in 18 states in the U.S. including California, Texas, the Mid-Atlantic and Northeast, where our wholesale power generation fleet is primarily concentrated. The acquisition of this best-in-class direct energy sales platform is consistent with our stated goal of getting closer to our end-use customers and expands our retail customer base, complementing our existing retail business while providing us a valuable sales channel for reaching a much greater portion of the load we seek to serve.
On October 26, 2016, we completed the sale of our Mankato Power Plant, a 375 MW natural gas-fired, combined-cycle power plant and 345 MW expansion project under advanced development located in Minnesota, to Southern Power Company, a subsidiary of Southern Company, for $396 million, excluding working capital and other adjustments. This transaction supports our effort to divest non-core assets outside our strategic concentration.
We successfully originated new contracts with customers related to our Texas City Power Plant and Morgan, RockGen and Los Medanos Energy Centers and announced an expansion of the service territory for Champion Energy. We also satisfied final regulatory approval requirements for a 20-year PPA, which will facilitate a 345 MW expansion of our Mankato Power Plant, and received final regulatory approval for a ten-year PPA associated with our Geysers Assets.
We assess our business on a regional basis due to the effect on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors affecting supply and demand. Our reportable segments are West (including geothermal), Texas and East (including Canada).
Our portfolio, including partnership interests, consists of 82 power plants, including one under construction, with an aggregate current generation capacity of 26,907 MW and 828 MW under construction. Our fleet, including projects under construction, consists of 67 natural gas-fired combustion turbine-based plants, one fuel oil-fired steam-based plant, 13 geothermal steam turbine-based plants and one photovoltaic solar plant. Our segments have an aggregate generation capacity of 7,425 MW in the West, 9,427 MW in Texas and 10,055 MW with an additional 828 MW under construction in the East. Inclusive of our power generation portfolio and our retail sales platforms, we operate in 20 states in the U.S. and in Canada.
Legislative and Regulatory Update
We are subject to complex and stringent energy, environmental and other laws and regulations at the federal, state and local levels as well as rules within the ISO and RTO markets in which we participate. Federal and state legislative and regulatory actions, including those by ISO/RTOs, continue to change how our business is regulated. We are actively participating in these debates at the federal, regional, state and ISO/RTO levels. Significant updates are discussed below. For a further discussion of the environmental and other governmental regulations that affect us, see “— Governmental and Regulatory Matters” in Part I, Item 1 of our 2015 Form 10-K.
CAISO
The CPUC and CAISO continue to evaluate capacity procurement policies and products for the California power market. With the expectation of significant increases in renewables, both entities are evaluating the need for operational flexibility, including the ability to start and ramp quickly as well as the ability to operate efficiently at low output levels or cycle off. We are an active participant in these discussions and support products and policies that would provide appropriate compensation for the required attributes. As these proceedings are ongoing, we cannot predict the ultimate effect on our financial condition, results of operations or cash flows, although we believe our fleet offers many features that can, and do, provide operational flexibility to the power markets.
In July 2016, we filed a protest with the FERC in response to a complaint filed against the CAISO on June 17, 2016, by the owner of a natural gas-fired power plant located in Kern County, California. Our protest requests the FERC to reject the relief

29



sought in the complaint as a one-off solution to a larger problem and, rather, to convene a technical conference to consider whether the California wholesale power market allows modern, efficient natural gas-fired power plants that are needed for reliability and flexibility to recover their costs, including a return of, and on, capital and to consider necessary changes to the market structure to ensure revenue adequacy. On October 3, 2016, the FERC denied our request for a technical conference but encouraged the CAISO to continue an investigation into possible compensation for generation units that are needed but otherwise uneconomic to operate.
ERCOT
The PUCT is considering changes regarding its approach to resource adequacy, including price formation and scarcity pricing as operating reserves decline. ERCOT successfully launched the Operating Reserve Demand Curve (“ORDC”) functionality on June 1, 2014. This application produces a price “adder” to the clearing price of energy that increases as reserve capacity declines. The PUCT requested a review of the effectiveness of the ORDC and requested input from ERCOT and market participants, including any recommendations to improve the ORDC. The PUCT continues to consider the appropriate reliability standard that should be used to set ERCOT’s planning reserve margin. As these proceedings are ongoing and the timing of these changes is uncertain, we cannot predict the ultimate effect on our financial condition, results of operations or cash flows.
PJM
On April 4, 2016, the Governor of Maryland signed into law the Reauthorization of the Greenhouse Gas Emissions Reduction Act which builds on the 2009 Greenhouse Gas Emissions Reduction Act that required a 25% reduction of GHG emissions from 2006 levels by 2020. The legislation requires the Maryland Department of the Environment (“MDE”), in coordination with other Maryland agencies, to develop plans, adopt regulations and implement programs to reduce GHGs. The legislation includes several “off ramps” designed to protect manufacturers and electric generators. Under the bill, the State must demonstrate MDE’s compliance plans will have a positive effect on Maryland’s economy and will protect existing manufacturing jobs.
Over significant opposition, on March 31, 2016, the Ohio Public Utility Commission (“PUCO”) voted unanimously to approve two out-of-market PPAs – one between American Electric Power, Inc. (“AEP”) and its generation affiliate and a second between FirstEnergy Corp. (“FE”) and its generation affiliate. Separately, three complaints regarding the AEP and FE PPAs were filed with the FERC. On April 27, 2016, the FERC ruled on two of these complaints, rescinding certain waivers granted in the past to AEP and FE and finding that the AEP and FE PPAs are subject to FERC review and approval prior to transacting under them.
Both FE and AEP sought rehearing of the March 31, 2016 PUCO order. In response to FE’s rehearing requests, PUCO ordered further hearings which began on July 11, 2016. In the rehearing proceeding, FE offered a new proposal to recast the PPA in a manner that would obviate the need for FERC review, referred to as the RRS rider. On October 12, 2016, the PUCO issued an order rejecting FE’s RRS rider proposal and instead ordered FE’s Ohio utilities to implement a Distribution Modernization Rider as proposed by PUCO staff. It is expected that the October 12, 2016 PUCO decision will be appealed to the Ohio Supreme Court. AEP’s rehearing request is pending before the PUCO.
Beginning several years ago, New Jersey and Maryland each directed their load serving entities to issue requests for proposals (“RFP”) for the construction of new natural gas-fired generation plants in their respective states and to enter into long term capacity contracts with the generators selected in the RFP process. Several generators and load serving entities challenged the New Jersey and Maryland actions in federal court and prevailed in their challenges against the states in federal district court and before the Third and Fourth Circuits of the U.S. Courts of Appeals, respectively. The states and one of the winning generators filed petitions for certiorari with the U.S. Supreme Court. On October 19, 2015, the U.S. Supreme Court granted certiorari for the appeal of the Fourth Circuit decision. On April 19, 2016, the U.S. Supreme Court issued a decision affirming the Fourth Circuit’s ruling and on April 25, 2016, dismissed the petitions for certiorari of the Third Circuit decision.
We believe the current competitive construct of the PJM power market whereby new construction of power generation facilities is determined by forward price signals and not ratepayer guaranteed rate recovery is the most efficient mechanism for incentivizing the construction of new power plants.
ISO-NE
ISO-NE continues to propose refinements to various aspects of its tariff that may affect overall market opportunities. At present, the ISO is currently updating the Cost of New Entry which is an important parameter in the operation of the Forward Capacity Market Demand Curve. The likelihood and potential effect of any pending proposals on our business is currently unknown.

30



Several New England states have issued or are planning to issue requests for proposals for new, large-scale renewable resources, including offshore wind generation and Canadian hydroelectric generation. The effect these efforts may have on our business is currently unknown.
NYISO
On August 1, 2016, the New York State Public Service Commission (“PSC”) approved the Clean Energy Standard which requires 50% of the state’s generation to be produced by renewable resources by 2030. In addition, the Clean Energy Standard provides for out-of-market financial subsidies for some of the state’s existing nuclear generation facilities. Several parties have sought rehearing of the PSC’s ruling, and a lawsuit challenging the PSC’s ruling on constitution grounds has been filed in a federal district court. We believe these subsidies will adversely affect the power markets in NYISO by artificially suppressing prices.
Independent Electricity System Operator (“IESO”)
Ontario is implementing a new GHG law with an associated Cap-and-Trade program which will become effective January 1, 2017. The result of this program will require power generators to either acquire related CO2 allowances on their own behalf or, in most cases, the natural gas pipeline supplying the power generation facility will be required to procure such allowances and bill the power generator in the form of a CO2 surcharge on its natural gas transportation invoice. Greenfield LP has a long-term Clean Energy Supply Contract with the IESO, successor to the Ontario Power Authority. We believe the contract contemplates and provides for the pass-through of CO2 cost, although there has been some communications from the IESO which may indicate an alternative view. Greenfield LP is currently negotiating to remedy this matter prior to the January 1, 2017 effective date. As this issue is ongoing, we cannot predict the ultimate effect on our financial condition, results of operations or cash flows.
On a related note, Whitby has a PPA with the Ontario Electricity Financial Corporation, successor to Ontario Hydro and is also determining its position related to CO2 cost.
Mercury and Air Toxics Standards (“MATS”) and Cross-State Air Pollution Rule (“CSAPR”)
MATS and CSAPR have been heavily litigated since their promulgation. On June 13, 2016, the U.S. Supreme Court denied a request to stay MATS which effectively ends the legal challenges to stop MATS from being implemented. CSAPR took effect on January 1, 2015 and there are no remaining substantive judicial challenges which could abrogate CSAPR. On April 25, 2016, the EPA published in the Federal Register the final, revised “necessary and appropriate” determination to address the narrow issue for which the U.S. Supreme Court, and subsequently the U.S. Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”), had remanded the MATS rule to the EPA for further action. This effectively addresses previous litigation related to MATS, although this action itself is now the subject of further litigation.
MATS and CSAPR primarily affect coal-fired power plants; therefore, these rules do not directly affect our power plants. However, we believe that well-founded regulations protecting health and the environment could benefit our competitive position by better recognizing the value of our investments in clean power generation technology.
Clean Power Plan
The Clean Power Plan requires a reduction in GHG emissions from existing power plants of 32% from 2005 levels by 2030. On February 9, 2016, the U.S. Supreme Court issued a stay of the Clean Power Plan until the D.C. Circuit issues a ruling on the merits and through final determination in any further appeal to the U.S. Supreme Court from the D.C. Circuit decision. Litigation challenging the Clean Power Plan is currently ongoing with oral arguments having been held on September 27, 2016 in the D.C. Circuit. Overall, we support the Clean Power Plan and believe we are well positioned to comply with its provisions. We expect the Clean Power Plan to be beneficial to Calpine.
Regional Haze
On July 15, 2016, the United States Court of Appeals for the Fifth Circuit issued a stay of the Regional Haze Federal Implementation Plan the EPA imposed on the state of Texas that would require installation of SO2 emission controls on 16 units at nine coal-fired power plants in Texas and also denied the EPA’s motion to transfer the case to the D.C. Circuit. While this will not directly affect our fleet, it does have the potential to affect the power market in Texas because the affected facilities would either have to further reduce emissions or retire.
California: GHG - Cap-and-Trade Regulation
AB 32 requires the state to reduce statewide GHG emissions in reference to 1990 levels. To meet this mandate, the California Air Resource Board (“CARB”) has promulgated a number of regulations, including the Cap-and-Trade Regulation and

31



Mandatory Reporting Rule, which took effect on January 1, 2012. These regulations have since been amended by the CARB several times.
Under the Cap-and-Trade Regulation, the first compliance period for covered entities like us began on January 1, 2013 and ended on December 31, 2014. The second and third compliance periods, wherein the program applies to a broader scope of entities, including transportation fuels and natural gas distribution, run through the end of 2017 and 2020, respectively. Covered entities must surrender compliance instruments, which include both allowances and offset credits, in an amount equivalent to their GHG emissions.
On January 1, 2014, the California Cap-and-Trade market was officially linked to the GHG Cap-and-Trade market in Québec. The first joint GHG allowance auction occurred on November 25, 2014. Joint auctions of allowances issued by both jurisdictions, which can be used interchangeably, are held quarterly. In April 2015, the Canadian province of Ontario announced that it would develop a Cap-and-Trade program with the aim of joining the linked California-Québec market. Ontario’s Cap-and-Trade Regulation was finalized in May 2016, and will take effect starting in 2017. Market linkage remains under evaluation and could occur as soon as 2018. The Governor of New York has also proposed linking the Regional Greenhouse Gas Initiative, a carbon market operating in nine northeastern states, with the California-Québec market.
On May 22, 2014, the CARB approved its first update to the Climate Change Scoping Plan pursuant to AB 32. The updated Scoping Plan states that California is on track to meet its 2020 emissions target and makes recommendations for how the state can achieve the goal established by a 2005 executive order of reducing statewide GHG emissions to 80% below 1990 levels by 2050, including recommending the establishment of a mid-term emissions target for 2030. On April 29, 2015, California Governor Jerry Brown issued an executive order that establishes a new interim GHG reduction target of 40% below 1990 levels by 2030 and orders the CARB to update the Climate Change Scoping Plan to express the 2030 target in tons of GHG emissions. The CARB is presently moving forward with an update reflecting this target.
Legislation concerning California’s 2030 target, known as Senate Bill 32 (“SB 32”), passed both houses of the state legislature and was signed into law by Governor Brown on September 8, 2016. SB 32 amends AB 32 by requiring CARB to ensure that statewide GHG emissions are reduced to at least 40% below 1990 levels by 2030. SB 32 was joined to companion legislation, Assembly Bill 197 (“AB 197”), which Governor Brown also signed into law on September 8, 2016. AB 197 amends AB 32 to specify that CARB must prioritize emission reduction rules and regulations that result in direct emission reductions from sources of GHG emissions. While the author of AB 197 confirmed in an accompanying statement that AB 197 does not preclude the CARB from adopting market-based compliance mechanisms pursuant to AB 32, neither SB 32, nor AB 197, expressly affirms the CARB’s authority to extend the Cap-and-Trade Regulation beyond 2020.
On September 22, 2016, the CARB considered proposed amendments to the Cap-and-Trade Regulation that would, among other things, extend the program beyond 2020. The proposed extension would support California’s achievement of GHG reductions of at least 40% below 1990 levels by 2030 while simultaneously functioning as the centerpiece of California’s proposed plan to demonstrate compliance with the federal Clean Power Plan regulation. Due to uncertainty created by litigation currently pending at the California Court of Appeals challenging the existing Cap-and-Trade Regulation as an unlawful tax and potential claims that might be brought challenging the CARB’s adoption of the proposed amendments to the Cap-and-Trade Regulation, Governor Brown has stated that he intends to pursue legislation in 2017 affirming the CARB’s authority to adopt the Cap-and-Trade Regulation or seek such authorization through the voter initiative process.
Overall, we support AB 32 and expect the net effect of the Cap-and-Trade Regulation to be beneficial to Calpine. We also believe we are well positioned to comply with the Cap-and-Trade Regulation.
The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 (the “Dodd-Frank Act”)
In June 2016, as mandated by the Dodd-Frank Act, the SEC adopted final rules requiring resource extraction issuers to report, on an annual basis, any payments made by the issuer to the U.S. Federal Government or a foreign government for the purpose of the commercial development of oil, natural gas or minerals. The annual disclosure filing of these payments must be made with the SEC for fiscal years ending after September 30, 2018.Therefore, for calendar year end companies, such as Calpine, the initial information must be provided to the SEC by May 30, 2019. We anticipate that we will be required to file a report disclosing the total amount of payments made to the U.S. Federal Government in conjunction with our geothermal leases from which we extract steam for our Geysers Assets.


32



RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2016 AND 2015
Below are our results of operations for the three months ended September 30, 2016 as compared to the same period in 2015 (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.
 
2016
 
2015
 
Change
 
% Change
Operating revenues:
 
 
 
 
 
 
 
Commodity revenue
$
2,063

 
$
1,888

 
$
175

 
9

Mark-to-market gain
287

 
55

 
232

 
#

Other revenue
5

 
5

 

 

Operating revenues
2,355

 
1,948

 
407

 
21

Operating expenses:
 
 
 
 
 
 
 
Fuel and purchased energy expense:
 
 
 
 
 
 
 
Commodity expense
1,294

 
943

 
(351
)
 
(37
)
Mark-to-market loss
178

 
130

 
(48
)
 
(37
)
Fuel and purchased energy expense
1,472

 
1,073

 
(399
)
 
(37
)
Plant operating expense
215

 
200

 
(15
)
 
(8
)
Depreciation and amortization expense
161

 
166

 
5

 
3

Sales, general and other administrative expense
33

 
33

 

 

Other operating expenses
18

 
16

 
(2
)
 
(13
)
Total operating expenses
1,899

 
1,488

 
(411
)
 
(28
)
(Income) from unconsolidated investments in power plants
(6
)
 
(6
)
 

 

Income from operations
462

 
466

 
(4
)
 
(1
)
Interest expense
158

 
159

 
1

 
1

Interest (income)
(1
)
 
(1
)
 

 

Other (income) expense, net
8

 
1

 
(7
)
 
#

Income before income taxes
297

 
307

 
(10
)
 
(3
)
Income tax expense (benefit)
(4
)
 
28

 
32

 
#

Net income
301

 
279

 
22

 
8

Net income attributable to the noncontrolling interest
(6
)
 
(6
)
 

 

Net income attributable to Calpine
$
295

 
$
273

 
$
22

 
8

 
2016
 
2015
 
Change
 
% Change
Operating Performance Metrics:
 
 
 
 
 
 
 
MWh generated (in thousands)(1)(2)
33,552

 
32,583

 
969

 
3

Average availability(2)
97.3
%
 
97.0
%
 
0.3
 %
 

Average total MW in operation(1)
26,502

 
25,807

 
695

 
3

Average capacity factor, excluding peakers
62.6
%
 
63.3
%
 
(0.7
)%
 
(1
)
Steam Adjusted Heat Rate(2)
7,333

 
7,336

 
3

 

__________
#
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.

33



We evaluate our Commodity revenue and Commodity expense on a collective basis as 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 and Adjusted EBITDA.”
Commodity revenue, net of Commodity expense, decreased $176 million for the three months ended September 30, 2016, compared to the same period in 2015, primarily due to:
(in millions)
 
 
$
(129
)
 
Lower energy margins due to decreased contribution from hedges, lower realized Spark Spreads in our Texas segment and the expiration of the Pastoria Energy Center PPA. These factors were partially offset by increased contribution from our retail hedging activity and the positive effect of a new PPA associated with our Morgan Energy Center in the East segment
(44
)
 
Lower regulatory capacity revenue primarily in PJM and the West at our power plants which were fully operational period-over-period
19

 
A full quarter of energy and capacity revenue associated with our 695 MW Granite Ridge Energy Center, which was acquired on February 5, 2016
(22
)
 
Contract amortization, lease levelization related to tolling contracts and other(1)
$
(176
)
 
 
__________
(1)
Commodity Margin and Adjusted EBITDA exclude 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 or non-recurring items. See “Commodity Margin and Adjusted EBITDA” for a description of these Non-GAAP financial measures.
    
Mark-to-market gain/loss from hedging our future generation, retail activities and fuel needs had a favorable variance of $184 million from a net loss of $75 million for the three months ended September 30, 2015 compared to a net gain of $109 million for the three months ended September 30, 2016. The net gain of $109 million during the three months ended September 30, 2016 is primarily driven by the maturity of unfavorable power hedges and fluctuations in forward prices during the period. The net loss of $75 million during the three months ended September 30, 2015 is primarily driven by the maturity of favorable power hedges and fluctuations in forward prices during the period.

Our normal, recurring plant operating expense decreased by $9 million for the three months ended September 30, 2016 compared to the same period in 2015, after excluding a $12 million increase attributable to power plant portfolio changes and our acquisition of Champion Energy and an $11 million increase in major maintenance expense resulting from our plant outage schedule net of cost from scrap parts related to outages, primarily due to lower property taxes associated with two power plants in our Texas segment.
    
Other (income) expense, net increased by $7 million for the three months ended September 30, 2016 compared to the same period in 2015 primarily due to a $3 million increase resulting from a foreign currency translation loss related to our Canadian subsidiaries and a $2 million increase related to credit fees associated with our retail operations in the three months ended September 30, 2016.
 
During the three months ended September 30, 2016, we recorded an income tax benefit of $4 million compared to income tax expense of $28 million for the three months ended September 30, 2015. The favorable period-over-period change primarily resulted from a decrease in state income tax expense due to lower income in the current year in state tax jurisdictions where we do not have NOLs.

34



RESULTS OF OPERATIONS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2016 AND 2015
Below are our results of operations for the nine months ended September 30, 2016 as compared to the same period in 2015 (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.
 
2016
 
2015
 
Change
 
% Change
Operating revenues:
 
 
 
 
 
 
 
Commodity revenue
$
5,199

 
$
4,933

 
$
266

 
5

Mark-to-market gain (loss)
(79
)
 
89

 
(168
)
 
#

Other revenue
14

 
14

 

 

Operating revenues
5,134

 
5,036

 
98

 
2

Operating expenses:
 
 
 
 
 
 
 
Fuel and purchased energy expense:
 
 
 
 
 
 
 
Commodity expense
3,197

 
2,754

 
(443
)
 
(16
)
Mark-to-market (gain) loss
(57
)
 
95

 
152

 
#

Fuel and purchased energy expense
3,140

 
2,849

 
(291
)
 
(10
)
Plant operating expense
741

 
732

 
(9
)
 
(1
)
Depreciation and amortization expense
503

 
484

 
(19
)
 
(4
)
Sales, general and other administrative expense
106

 
100

 
(6
)
 
(6
)
Other operating expenses
55

 
56

 
1

 
2

Total operating expenses
4,545

 
4,221

 
(324
)
 
(8
)
(Income) from unconsolidated investments in power plants
(16
)
 
(18
)
 
(2
)
 
(11
)
Income from operations
605

 
833

 
(228
)
 
(27
)
Interest expense
472

 
471

 
(1
)
 

Interest (income)
(3
)
 
(3
)
 

 

Debt modification and extinguishment costs
15

 
32

 
17

 
53

Other (income) expense, net
21

 
8

 
(13
)
 
#

Income before income taxes
100

 
325

 
(225
)
 
(69
)
Income tax expense
17

 
32

 
15

 
47

Net income
83

 
293

 
(210
)
 
(72
)
Net income attributable to the noncontrolling interest
(15
)
 
(11
)
 
(4
)
 
(36
)
Net income attributable to Calpine
$
68

 
$
282

 
$
(214
)
 
(76
)
 
2016
 
2015
 
Change
 
% Change
Operating Performance Metrics:
 
 
 
 
 
 
 
MWh generated (in thousands)(1)(2)
84,032

 
85,104

 
(1,072
)
 
(1
)
Average availability(2)
90.9
%
 
90.8
%
 
0.1
 %
 

Average total MW in operation(1)
26,414

 
25,777

 
637

 
2

Average capacity factor, excluding peakers
53.4
%
 
56.3
%
 
(2.9
)%
 
(5
)
Steam Adjusted Heat Rate(2)
7,307

 
7,312

 
5

 

__________
#
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.

35



We evaluate our Commodity revenue and Commodity expense on a collective basis as 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 and Adjusted EBITDA.”
Commodity revenue, net of Commodity expense, decreased $177 million for the nine months ended September 30, 2016, compared to the same period in 2015, primarily due to:
(in millions)
 
 
$
(160
)
 
Lower energy margins due to decreased contribution from hedges, lower realized Spark Spreads in our Texas segment and the expirations of the Pastoria Energy Center PPA and the Greenleaf operating lease. These factors were partially offset by increased contribution from our retail hedging activity and the positive effect of a new PPA associated with our Morgan Energy Center in the East segment
(24
)
 
Lower regulatory capacity revenue primarily in the West at our power plants which were fully operational period-over-period
40

 
A natural gas pipeline transportation billing credit received in the West segment
35

 
The effect of our portfolio management activities, primarily including approximately eight months of energy and capacity revenue associated with our 695 MW Granite Ridge Energy Center, which was acquired on February 5, 2016, and approximately five months associated with our 309 MW Garrison Energy Center, which commenced commercial operations in June 2015
(68
)
 
Contract amortization, lease levelization related to tolling contracts and other(1)
$
(177
)
 
 
__________
(1)
Commodity Margin and Adjusted EBITDA exclude 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 or non-recurring items. See “Commodity Margin and Adjusted EBITDA” for a description of these Non-GAAP financial measures.

Our normal, recurring plant operating expense decreased by $21 million for the nine months ended September 30, 2016 compared to the same period in 2015, after excluding a $35 million increase attributable to power plant portfolio changes and our acquisition of Champion Energy, a $12 million decrease in major maintenance expense resulting from our plant outage schedule net of cost from scrap parts related to outages and a $7 million increase in stock-based compensation expense and other miscellaneous items, primarily due to lower property taxes associated with two power plants in our Texas segment as well as lower repairs and maintenance expense.
    
Depreciation and amortization expense increased by $19 million for the nine months ended September 30, 2016 compared to the same period in 2015 primarily due to a $27 million increase resulting from the acquisitions of Granite Ridge Energy Center and Champion Energy, partially offset by a decrease of $6 million primarily due to the reclassification of property, plant and equipment, net to current assets held for sale where these assets are no longer depreciated. See Note 2 of the Notes to Consolidated Condensed Financial Statements for a further description of our current assets held for sale.

Debt extinguishment costs for the nine months ended September 30, 2016 consisted of $15 million from the write-off of deferred financing costs in connection with the repayment of our 2019 and 2020 First Lien Term Loans in May 2016. Debt modification and extinguishment costs for the nine months ended September 30, 2015, consisted of $19 million in connection with the repurchase of approximately $147 million of our 2023 First Lien Notes, which comprised of $18 million of prepayment penalties and $1 million associated with the write-off of deferred financing costs, and $13 million in costs related to the issuance of our 2022 First Lien Term Loan in May 2015.

Other (income) expense, net increased by $13 million for the nine months ended September 30, 2016 compared to the same period in 2015 primarily due to a $7 million increase resulting from a foreign currency translation loss related to our Canadian subsidiaries and a $5 million increase related to credit fees associated with our retail operations in the nine months ended September 30, 2016.
 
During the nine months ended September 30, 2016, we recorded an income tax expense of $17 million compared to $32 million for the nine months ended September 30, 2015. The favorable period-over-period change primarily resulted from a decrease in state income tax expense due to lower income in the current year in state tax jurisdictions where we do not have NOLs.

36



COMMODITY MARGIN AND ADJUSTED EBITDA
Management’s Discussion and Analysis of Financial Condition and Results of Operations includes financial information prepared in accordance with U.S. GAAP, as well as the non-GAAP financial measures, Commodity Margin and Adjusted EBITDA, discussed below, which we use as measures of our performance. Generally, a non-GAAP financial measure is a numerical measure of financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with U.S. GAAP.
We use Commodity Margin, a non-GAAP financial measure, to assess our performance by our reportable segments. Commodity Margin includes our power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, environmental compliance expense, and realized settlements from our marketing, hedging, optimization and trading activities, but excludes mark-to-market activity and other revenues. We believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure reviewed by our chief operating decision maker. Commodity Margin is not a measure calculated in accordance with U.S. GAAP and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with U.S. GAAP. Commodity Margin does not intend to represent income from operations, the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. See Note 12 of the Notes to Consolidated Condensed Financial Statements for a reconciliation of Commodity Margin to income from operations by segment.
Commodity Margin by Segment for the Three Months Ended September 30, 2016 and 2015
The following tables show our Commodity Margin and related operating performance metrics by segment for the three months ended September 30, 2016 and 2015 (exclusive of the noncontrolling interest). In the comparative tables below, favorable variances are shown without brackets while unfavorable variances are shown with brackets. The MWh generated by segment below represent generation from power plants that we both consolidate and operate. Generation, average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive.

West:
2016
 
2015
 
Change
 
% Change
Commodity Margin (in millions)
$
298

 
$
385

 
$
(87
)
 
(23
)
Commodity Margin per MWh generated
$
35.72

 
$
38.05

 
$
(2.33
)
 
(6
)
 
 
 
 
 
 
 
 
MWh generated (in thousands)
8,343

 
10,117

 
(1,774
)
 
(18
)
Average availability
98.9
%
 
97.6
%
 
1.3
 %
 
1

Average total MW in operation
7,425

 
7,425

 

 

Average capacity factor, excluding peakers
54.5
%
 
66.0
%
 
(11.5
)%
 
(17
)
Steam Adjusted Heat Rate
7,213

 
7,333

 
120

 
2


West — Commodity Margin in our West segment decreased by $87 million, or 23%, for the three months ended September 30, 2016 compared to the three months ended September 30, 2015, primarily due to lower contribution from hedges, as we realized lower power prices at our Geysers Assets resulting from lower forward natural gas prices. Also contributing to the period-over-period decrease in Commodity Margin was the expiration of a PPA and a resource adequacy contract at our Pastoria Energy Center in December 2015. Generation decreased 18% due to the suspension of operations at our Sutter Energy Center in 2016, the reclassification of our South Point Energy Center to inactive reserve in 2016 pending being sold in early 2017 and lower generation at our contracted Russell City Energy Center in the third quarter of 2016 resulting from a rate case which increased natural gas transportation costs.
Texas:
2016
 
2015
 
Change
 
% Change
Commodity Margin (in millions)
$
198

 
$
264

 
$
(66
)
 
(25
)
Commodity Margin per MWh generated
$
14.48

 
$
19.45

 
$
(4.97
)
 
(26
)
 
 
 
 
 
 
 
 
MWh generated (in thousands)
13,670

 
13,576

 
94

 
1

Average availability
97.0
%
 
97.2
%
 
(0.2
)%
 

Average total MW in operation
9,191

 
9,191

 

 

Average capacity factor, excluding peakers
67.4
%
 
66.9
%
 
0.5
 %
 
1

Steam Adjusted Heat Rate
7,142

 
7,111

 
(31
)
 


37




Texas — Commodity Margin in our Texas segment decreased by $66 million, or 25%, for the three months ended September 30, 2016 compared to the three months ended September 30, 2015, primarily due to lower realized Spark Spreads resulting from a decrease in hedge value and lower market liquidations, partially offset by positive contribution from our retail hedging activity.
East:
2016
 
2015
 
Change
 
% Change
Commodity Margin (in millions)
$
324

 
$
325

 
$
(1
)
 

Commodity Margin per MWh generated
$
28.08

 
$
36.56

 
$
(8.48
)
 
(23
)
 
 
 
 
 
 
 
 
MWh generated (in thousands)
11,539

 
8,890

 
2,649

 
30

Average availability
96.5
%
 
96.2
%
 
0.3
%
 

Average total MW in operation
9,886

 
9,191

 
695

 
8

Average capacity factor, excluding peakers
64.3
%
 
55.8
%
 
8.5
%
 
15

Steam Adjusted Heat Rate
7,660

 
7,710

 
50

 
1

    
East — Commodity Margin in our East segment was relatively unchanged for the three months ended September 30, 2016 compared to the three months ended September 30, 2015. The positive factors contributing to our period-over-period results primarily consisted of a full quarter of operation at our 695 MW Granite Ridge Energy Center, which was acquired on February 5, 2016, and the positive effect of a new PPA associated with our Morgan Energy Center, which became effective in February 2016. The positive factors were offset by lower contribution from hedges, partially offset by higher contribution from our retail hedging activity, and lower regulatory capacity revenue in PJM. Generation increased 30% primarily due to the acquisition of our 695 MW Granite Ridge Energy Center on February 5, 2016 and an increase in generation at our power plants which were fully operational period-over-period due to stronger market conditions.
Commodity Margin by Segment for the Nine Months Ended September 30, 2016 and 2015
The following tables show our Commodity Margin and related operating performance metrics by segment for the nine months ended September 30, 2016 and 2015 (exclusive of the noncontrolling interest). In the comparative tables below, favorable variances are shown without brackets while unfavorable variances are shown with brackets. The MWh generated by segment below represent generation from power plants that we both consolidate and operate. Generation, average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive.
West:
2016
 
2015
 
Change
 
% Change
Commodity Margin (in millions)
$
749

 
$
843

 
$
(94
)
 
(11
)
Commodity Margin per MWh generated
$
37.84

 
$
32.67

 
$
5.17

 
16

 
 
 
 
 
 
 
 
MWh generated (in thousands)
19,796

 
25,800

 
(6,004
)
 
(23
)
Average availability
91.6
%
 
89.6
%
 
2.0
 %
 
2

Average total MW in operation
7,425

 
7,491

 
(66
)
 
(1
)
Average capacity factor, excluding peakers
43.5
%
 
56.1
%
 
(12.6
)%
 
(22
)
Steam Adjusted Heat Rate
7,276

 
7,322

 
46

 
1


West — Commodity Margin in our West segment decreased by $94 million, or 11%, for the nine months ended September 30, 2016 compared to the nine months ended September 30, 2015, primarily due to lower contribution from hedges, as we realized lower power prices at our Geysers Assets resulting from lower forward natural gas prices. Also contributing to the period-over-period decrease in Commodity Margin was the expiration of a PPA and a resource adequacy contract at our Pastoria Energy Center in December 2015 and the expiration of the operating lease related to the Greenleaf power plants in June 2015. The decrease in Commodity Margin was partially offset by the receipt of a natural gas transportation pipeline billing credit during the second quarter of 2016. Generation decreased 23% primarily due to the suspension of operations at our Sutter Energy Center in 2016, the reclassification of our South Point Energy Center to inactive reserve in 2016 pending being sold in early 2017 and an increase in hydroelectric generation in California and the Pacific Northwest during the nine months ended September 30, 2016 compared to the same period in 2015.

38



Texas:
2016
 
2015
 
Change
 
% Change
Commodity Margin (in millions)
$
511

 
$
583

 
$
(72
)
 
(12
)
Commodity Margin per MWh generated
$
13.70

 
$
16.05

 
$
(2.35
)
 
(15
)
 
 
 
 
 
 
 
 
MWh generated (in thousands)
37,306

 
36,314

 
992

 
3

Average availability
90.8
%
 
90.9
%
 
(0.1
)%
 

Average total MW in operation
9,191

 
9,191

 

 

Average capacity factor, excluding peakers
61.7
%
 
60.3
%
 
1.4
 %
 
2

Steam Adjusted Heat Rate
7,113

 
7,096

 
(17
)
 


Texas — Commodity Margin in our Texas segment decreased by $72 million, or 12%, for the nine months ended September 30, 2016 compared to the nine months ended September 30, 2015, primarily due to lower realized Spark Spreads resulting from a decrease in hedge value and lower market liquidations, partially offset by positive contribution from our retail hedging activity.
East:
2016
 
2015
 
Change
 
% Change
Commodity Margin (in millions)
$
797

 
$
740

 
$
57

 
8

Commodity Margin per MWh generated
$
29.60

 
$
32.19

 
$
(2.59
)
 
(8
)
 
 
 
 
 
 
 
 
MWh generated (in thousands)
26,930

 
22,990

 
3,940

 
17

Average availability
90.7
%
 
91.6
%
 
(0.9
)%
 
(1
)
Average total MW in operation
9,798

 
9,095

 
703

 
8

Average capacity factor, excluding peakers
52.4
%
 
50.9
%
 
1.5
 %
 
3

Steam Adjusted Heat Rate
7,614

 
7,660

 
46

 
1

    
East — Commodity Margin in our East segment increased by $57 million, or 8%, for the nine months ended September 30, 2016 compared to the nine months ended September 30, 2015, primarily due to approximately eight months of operation at our 695 MW Granite Ridge Energy Center, which was acquired on February 5, 2016, and approximately five months of operation at our 309 MW Garrison Energy Center, which commenced commercial operations in June 2015. Also contributing to the period-over-period increase in Commodity Margin was the positive effect of a new PPA associated with our Morgan Energy Center which became effective in February 2016. The increase in Commodity Margin was partially offset by lower contribution from hedges, partially offset by higher contribution from our retail hedging activity. Generation increased 17% primarily due to the acquisition of our 695 MW Granite Ridge Energy Center on February 5, 2016, our 309 MW Garrison Energy Center, which commenced commercial operations in June 2015, and an increase in generation at our power plants which were fully operational period-over-period due to stronger market conditions primarily in the third quarter of 2016.
Adjusted EBITDA
We define Adjusted EBITDA, a non-GAAP financial measure, as EBITDA adjusted for certain items described below and presented in the accompanying reconciliation. Adjusted EBITDA is not a measure calculated in accordance with U.S. GAAP, and should be viewed as a supplement to, and not a substitute for, our results of operations presented in accordance with U.S. GAAP. Adjusted EBITDA is not intended to represent cash flows from operations or net income (loss) as defined by U.S. GAAP as an indicator of operating performance. Furthermore, Adjusted EBITDA is not necessarily comparable to similarly-titled measures reported by other companies.
We believe Adjusted EBITDA is useful to investors and other users of our financial statements in evaluating our operating performance because it provides them with an additional tool to compare business performance across companies and across periods. We believe that EBITDA is widely used by investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired.
Additionally, we believe that investors commonly adjust EBITDA information to eliminate the effect of restructuring and other expenses, which vary widely from company to company and impair comparability. As we define it, Adjusted EBITDA represents EBITDA adjusted for the effects of impairment losses, gains or losses on sales, dispositions or retirements of assets, any mark-to-market gains or losses from accounting for derivatives, adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, stock-based compensation expense, operating lease expense, non-cash gains and losses from foreign currency translations, major maintenance expense, gains or losses on the repurchase, modification or extinguishment of debt, non-

39



cash GAAP-related adjustments to levelize revenues from tolling agreements and any unusual or non-recurring items plus adjustments to reflect the Adjusted EBITDA from our unconsolidated investments. We adjust for these items in our Adjusted EBITDA as our management believes that these items would distort their ability to efficiently view and assess our core operating trends.
In summary, our management uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with our Board of Directors, shareholders, creditors, analysts and investors concerning our financial performance.
The tables below provide a reconciliation of Adjusted EBITDA to our income from operations on a segment basis and to net income attributable to Calpine on a consolidated basis for the periods indicated (in millions). 
 
Three Months Ended September 30, 2016
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Net income attributable to Calpine
 
 
 
 
 
 
 
 
$
295

Net income attributable to the noncontrolling interest
 
 
 
 
 
 
 
 
6

Income tax (benefit)
 
 
 
 
 
 
 
 
(4
)
Other (income) expense, net
 
 
 
 
 
 
 
 
8

Interest expense, net of interest income
 
 
 
 
 
 
 
 
157

Income from operations
$
157

 
$
175

 
$
130

 
$

 
$
462

Add:
 
 
 
 
 
 
 
 
 
Adjustments to reconcile income from operations to Adjusted EBITDA:
 
 
 
 
 
 
 
 
 
Depreciation and amortization expense, excluding deferred financing costs(1)
55

 
53

 
52

 

 
160

Major maintenance expense
11

 
14

 
18

 

 
43

Operating lease expense

 

 
6

 

 
6

Mark-to-market (gain) loss on commodity derivative activity
(30
)
 
(113
)
 
34

 

 
(109
)
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest(2)
(12
)
 

 
8

 

 
(4
)
Stock-based compensation expense
2

 
3

 
1

 

 
6

Loss on dispositions of assets
1

 

 

 

 
1

Contract amortization

 
10

 
15

 

 
25

Other
36

 
(1
)
 
7

 

 
42

Total Adjusted EBITDA
$
220

 
$
141

 
$
271

 
$

 
$
632


40




 
Three Months Ended September 30, 2015
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Net income attributable to Calpine
 
 
 
 
 
 
 
 
$
273

Net income attributable to the noncontrolling interest
 
 
 
 
 
 
 
 
6

Income tax expense
 
 
 
 
 
 
 
 
28

Other (income) expense, net
 
 
 
 
 
 
 
 
1

Interest expense, net of interest income
 
 
 
 
 
 
 
 
158

Income from operations
$
290

 
$
29

 
$
146

 
$
1

 
$
466

Add:
 
 
 
 
 
 
 
 
 
Adjustments to reconcile income from operations to Adjusted EBITDA:
 
 
 
 
 
 
 
 
 
Depreciation and amortization expense, excluding deferred financing costs(1)
59

 
58

 
47

 

 
164

Major maintenance expense
8

 
11

 
8

 

 
27

Operating lease expense

 

 
6

 

 
6

Mark-to-market (gain) loss on commodity derivative activity
(95
)
 
106

 
64

 

 
75

Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest(2)
(12
)
 

 
9

 

 
(3
)
Stock-based compensation expense
3

 
2

 
2

 

 
7

Loss on dispositions of assets
4

 
1

 

 

 
5

Contract amortization

 

 
4

 

 
4

Other
44

 

 
(3
)
 
(1
)
 
40

Total Adjusted EBITDA
$
301

 
$
207

 
$
283

 
$

 
$
791


41




 
Nine Months Ended September 30, 2016
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Net income attributable to Calpine
 
 
 
 
 
 
 
 
$
68

Net income attributable to the noncontrolling interest
 
 
 
 
 
 
 
 
15

Income tax expense
 
 
 
 
 
 
 
 
17

Debt extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
36

Interest expense, net of interest income
 
 
 
 
 
 
 
 
469

Income from operations
$
245

 
$
74

 
$
285

 
$
1

 
$
605

Add:
 
 
 
 
 
 
 
 
 
Adjustments to reconcile income from operations to Adjusted EBITDA:
 
 
 
 
 
 
 
 
 
Depreciation and amortization expense, excluding deferred financing costs(1)
177

 
159

 
163

 

 
499

Major maintenance expense
51

 
63

 
72

 

 
186

Operating lease expense

 

 
19

 

 
19

Mark-to-market (gain) loss on commodity derivative activity
37

 
(37
)
 
22

 

 
22

Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest(2)
(21
)
 

 
29

 

 
8

Stock-based compensation expense
8

 
9

 
6

 

 
23

Loss on dispositions of assets
1

 
2

 
3

 

 
6

Contract amortization
1

 
52

 
26

 

 
79

Other
6

 
1

 
5

 
(1
)
 
11

Total Adjusted EBITDA
$
505

 
$
323

 
$
630

 
$

 
$
1,458


42



 
Nine Months Ended September 30, 2015
 
West
 
Texas
 
East
 
Consolidation
and
Elimination
 
Total
Net income attributable to Calpine
 
 
 
 
 
 
 
 
$
282

Net income attributable to the noncontrolling interest
 
 
 
 
 
 
 
 
11

Income tax expense
 
 
 
 
 
 
 
 
32

Debt modification and extinguishment costs and other (income) expense, net
 
 
 
 
 
 
 
 
40

Interest expense, net of interest income
 
 
 
 
 
 
 
 
468

Income from operations
$
459

 
$
93

 
$
280

 
$
1

 
$
833

Add:
 
 
 
 
 
 
 
 
 
Adjustments to reconcile income from operations to Adjusted EBITDA:
 
 
 
 
 
 
 
 
 
Depreciation and amortization expense, excluding deferred financing costs(1)
189

 
157

 
134

 

 
480

Major maintenance expense
74

 
66

 
55

 

 
195

Operating lease expense
4

 

 
19

 

 
23

Mark-to-market (gain) loss on commodity derivative activity
(142
)
 
70

 
78

 

 
6

Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest(2)
(19
)
 

 
25

 

 
6

Stock-based compensation expense
8

 
7

 
4

 

 
19

Loss on dispositions of assets
4

 
3

 
1

 

 
8

Contract amortization

 

 
11

 

 
11

Other
2

 
1

 
3

 
(1
)
 
5

Total Adjusted EBITDA
$
579

 
$
397

 
$
610

 
$

 
$
1,586

____________
(1)
Excludes depreciation and amortization expense attributable to the noncontrolling interest.
(2)
Adjustments to reflect Adjusted EBITDA from unconsolidated investments include (gain) loss on mark-to-market activity of nil for each of the three and nine months ended September 30, 2016 and 2015.

43



LIQUIDITY AND CAPITAL RESOURCES
We maintain a strong focus on liquidity. We manage our liquidity to help provide access to sufficient funding to meet our business needs and financial obligations throughout business cycles.
Our business is capital intensive. Our ability to successfully implement our strategy is dependent on the continued availability of capital on attractive terms. In addition, our ability to successfully operate our business is dependent on maintaining sufficient liquidity. We believe that we have adequate resources from a combination of cash and cash equivalents on hand and cash expected to be generated from future operations to continue to meet our obligations as they become due.
Liquidity
The following table provides a summary of our liquidity position at September 30, 2016 and December 31, 2015 (in millions):

 
September 30, 2016
 
December 31, 2015
Cash and cash equivalents, corporate(1)
$
440

 
$
850

Cash and cash equivalents, non-corporate
121

 
56

Total cash and cash equivalents
561

 
906

Restricted cash
225

 
228

Corporate Revolving Facility availability(2)
1,410

 
1,184

CDHI letter of credit facility availability
39

 
59

Total current liquidity availability(3)
$
2,235

 
$
2,377

____________
(1)
Includes $30 million and $35 million of margin deposits posted with us by our counterparties at September 30, 2016 and December 31, 2015, respectively. See Note 7 of the Notes to Consolidated Condensed Financial Statements for further information related to our collateral.
(2)
On February 8, 2016, we amended our Corporate Revolving Facility, extending the maturity by two years to June 27, 2020, and increasing the capacity by an additional $178 million to $1,678 million through June 27, 2018, reverting back to $1,520 million through the maturity date. Further, we increased the letter of credit sublimit by $250 million to $1.0 billion and extended the maturity by two years to June 27, 2020. Our ability to use availability under our Corporate Revolving Facility is unrestricted.
(3)
Our ability to use corporate cash and cash equivalents is unrestricted. See Note 1 of the Notes to Consolidated Condensed Financial Statements for a description of the restrictions on our use of non-corporate cash and cash equivalents and restricted cash. Our $300 million CDHI letter of credit facility is restricted to support certain obligations under PPAs, power transmission and natural gas transportation agreements.
Our principal source for future liquidity is cash flows generated from our operations. We believe that cash on hand and expected future cash flows from operations will be sufficient to meet our liquidity needs for our operations, both in the near and longer term. See “Cash Flow Activities” below for a further discussion of our change in cash and cash equivalents.
Our principal uses of liquidity and capital resources, outside of those required for our operations, include, but are not limited to, collateral requirements to support our commercial hedging and optimization activities, debt service obligations including principal and interest payments, and capital expenditures for construction, project development and other growth initiatives. In addition, we may use capital resources to opportunistically repurchase our shares of common stock. The ultimate decision to allocate capital to share repurchases will be based upon the expected returns compared to alternative uses of capital. 
Cash Management — We manage our cash in accordance with our cash management system subject to the requirements of our Corporate Revolving Facility and requirements under certain of our project debt and lease agreements or by regulatory agencies. Our cash and cash equivalents, as well as our restricted cash balances, are invested in money market funds that are not FDIC insured. We place our cash, cash equivalents and restricted cash in what we believe to be creditworthy financial institutions.
We have never paid cash dividends on our common stock. Future cash dividends, if any, may be authorized at the discretion of our Board of Directors and will depend upon, among other things, our future operations and earnings, capital requirements, general financial condition, contractual and financing restrictions and such other factors as our Board of Directors may deem relevant.

44



Liquidity Sensitivity
Significant changes in commodity prices and Market Heat Rates can affect our liquidity as we use margin deposits, cash prepayments and letters of credit as credit support (collateral) with and from our counterparties for commodity procurement and risk management activities. Utilizing our portfolio of transactions subject to collateral exposure, we estimate that as of September 30, 2016, an increase of $1/MMBtu in natural gas prices would result in an increase of collateral required by approximately $220 million. If natural gas prices decreased by $1/MMBtu, we estimate that our collateral requirements would decrease by approximately $212 million. Changes in Market Heat Rates also affect our liquidity. For example, as demand increases, less efficient generation is dispatched, which increases the Market Heat Rate and results in increased collateral requirements. Historical relationships of natural gas and Market Heat Rate movements for our portfolio of assets have been volatile over time and are influenced by the absolute price of natural gas and the regional characteristics of each power market. We estimate that at September 30, 2016, an increase of 500 Btu/KWh in the Market Heat Rate would result in an increase in collateral required by approximately $52 million. If Market Heat Rates were to fall at a similar rate, we estimate that our collateral required would decrease by approximately $51 million. These amounts are not necessarily indicative of the actual amounts that could be required, which may be higher or lower than the amounts estimated above, and also exclude any correlation between the changes in natural gas prices and Market Heat Rates that may occur concurrently. These sensitivities will change as new contracts or hedging activities are executed.
In order to effectively manage our future Commodity Margin, we have economically hedged a portion of our generation and natural gas portfolio mostly through power and natural gas forward physical and financial transactions; however, we currently remain susceptible to significant price movements for 2016 and beyond. In addition to the price of natural gas, our Commodity Margin is highly dependent on other factors such as:
the level of Market Heat Rates;
our continued ability to successfully hedge our Commodity Margin;
changes in U.S. macroeconomic conditions;
maintaining acceptable availability levels for our fleet;
the effect of current and pending environmental regulations in the markets in which we participate;
improving the efficiency and profitability of our operations;
increasing future contractual cash flows; and
our significant counterparties performing under their contracts with us.
Additionally, scheduled outages related to the life cycle of our power plant fleet in addition to unscheduled outages may result in maintenance expenditures that are disproportionate in differing periods. In order to manage such liquidity requirements, we maintain additional liquidity availability in the form of our Corporate Revolving Facility (noted in the table above), letters of credit and the ability to issue first priority liens for collateral support. It is difficult to predict future developments and the amount of credit support that we may need to provide should such conditions occur, we experience another economic recession or energy commodity prices increase significantly.
Letter of Credit Facilities 
The table below represents amounts issued under our letter of credit facilities at September 30, 2016 and December 31, 2015 (in millions):
 
September 30, 2016
 
December 31, 2015
Corporate Revolving Facility(1)
$
268

 
$
316

CDHI
261

 
241

Various project financing facilities
232

 
198

Total
$
761

 
$
755

____________
(1)
The Corporate Revolving Facility represents our primary revolving facility.
Capital Management
In connection with our goals of enhancing long-term shareholder value, we have completed the following key capital management transaction during 2016, as further described below.

45



Corporate Revolving Facility
On February 8, 2016, we amended our Corporate Revolving Facility, extending the maturity by two years to June 27, 2020, and increasing the capacity by an additional $178 million to $1,678 million through June 27, 2018, reverting back to $1,520 million through the maturity date. Further, we increased the letter of credit sublimit by $250 million to $1.0 billion and extended the maturity by two years to June 27, 2020.
New 2023 First Lien Term Loan and 2026 First Lien Notes
In May 2016, we repaid our 2019 and 2020 First Lien Term Loans with the proceeds from our New 2023 First Lien Term Loan and 2026 First Lien Notes which extended the maturity on approximately $1.2 billion of corporate debt. See Note 4 of the Notes to Consolidated Condensed Financial Statements for a further description of our New 2023 First Lien Term Loan and 2026 First Lien Notes.
Managing and Growing our Portfolio
Our goal is to continue to grow our presence in core markets with an emphasis on acquisitions, expansions or modernizations of existing power plants. We intend to take advantage of favorable opportunities to continue to design, develop, acquire, construct and operate the next generation of highly efficient, operationally flexible and environmentally responsible power plants where such investment meets our rigorous financial hurdles, particularly if power contracts and financing are available and attractive returns are expected. Likewise, we actively seek to divest non-core assets where we can find opportunities to do so accretively. In addition, we believe that modernizations and expansions to our current assets offer proven and financially disciplined opportunities to improve our operations, capacity and efficiencies. Our significant projects under construction, growth initiatives, modernizations and strategic asset sales are discussed below.
NAES — On October 9, 2016, we announced that we entered into an agreement to purchase NAES and a swap contract for approximately $800 million plus approximately $100 million of net working capital estimated at closing. We expect to recover approximately $200 million through collateral synergies and the runoff of acquired legacy hedges, substantially within the first year. NAES is a commercial and industrial retail electricity provider with customers in 18 states in the U.S. including California, Texas, the Mid-Atlantic and Northeast, where our wholesale power generation fleet is primarily concentrated. The acquisition of this best-in-class direct energy sales platform is consistent with our stated goal of getting closer to our end-use customers and expands our retail customer base, complementing our existing retail business while providing us a valuable sales channel for reaching a much greater portion of the load we seek to serve.
Granite Ridge Energy Center — On February 5, 2016, we completed the purchase of Granite Ridge Energy Center, a power plant with a nameplate capacity of 745 MW (summer peaking capacity of 695 MW), for approximately $500 million, excluding working capital and other adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant increased capacity in our East segment, specifically the constrained New England market.
York 2 Energy Center — York 2 Energy Center is an 828 MW dual-fuel, combined-cycle project that will be co-located with our York Energy Center in Peach Bottom Township, Pennsylvania. Once complete, the power plant will feature two combustion turbines, two heat recovery steam generators and one steam turbine. The project is now under construction and the initial 760 MW of capacity cleared PJM’s last three base residual auctions with the 68 MW of incremental capacity clearing the last two base residual auctions. Due to construction delays, we are now targeting COD in late 2017.
Guadalupe Peaking Energy Center — In April 2015, we executed an agreement with Guadalupe Valley Electric Cooperative (“GVEC”) that will facilitate the construction of a 418 MW natural gas-fired peaking power plant to be co-located with our Guadalupe Energy Center. Under the terms of the agreement, construction of the Guadalupe Peaking Energy Center (“GPEC”) may commence at our discretion, so long as the power plant reaches COD by June 1, 2019. When the power plant begins commercial operation, GVEC will purchase a 50% ownership interest in GPEC. Once built, GPEC will feature two fast-ramping combustion turbines capable of responding to peaks in power demand. This project represents a mutually beneficial response to our customer’s desire to have direct access to peaking generation resources, as it leverages the benefits of our existing site and development rights and our construction and operating expertise, as well as our customer’s ability to fund its investment at attractive rates, all while affording us the flexibility of timing the plant’s construction in response to market pricing signals.
PJM and ISO-NE Development Opportunities — We continue to evaluate development projects in the PJM and ISO-NE market areas that feature cost advantages such as existing infrastructure and favorable transmission queue positions. These projects continue to advance entitlements (such as permits, zoning and transmission) for potential future development when/if economic as compared to purchasing existing power plants in the region.

46



Mankato Power Plant — On October 26, 2016, we completed the sale of our Mankato Power Plant, a 375 MW natural gas-fired, combined-cycle power plant and 345 MW expansion project under advanced development located in Minnesota, to Southern Power Company, a subsidiary of Southern Company, for $396 million, excluding working capital and other adjustments. This transaction supports our effort to divest non-core assets outside our strategic concentration.
South Point Energy Center On April 1, 2016, we entered into an asset sale agreement for the sale of substantially all of the assets comprising our South Point Energy Center to Nevada Power Company d/b/a NV Energy for approximately $76 million plus the assumption by the purchaser of existing transmission capacity contracts with a future net present value payment obligation of approximately $112 million, approximately $9 million in remaining tribal lease costs and approximately $21 million in near-term repairs, maintenance and capital improvements to restore the power plant to full capacity. The sale is subject to certain conditions precedent, as well as federal and state regulatory approvals, and is expected to close no later than the first quarter of 2017. The natural gas-fired, combined-cycle plant is located on the Fort Mojave Indian Reservation in Mohave Valley, Arizona, and features a summer peak capacity of 504 MW. This transaction supports our effort to divest non-core assets outside our strategic concentration.
Osprey Energy Center We executed an asset sale agreement in the fourth quarter of 2014 for the sale of our Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments, which will be consummated in January 2017 upon the conclusion of a PPA with a term of 27 months. The sale has received FERC and state regulatory approvals and represents a strategic disposition of a power plant in a wholesale power market dominated by regulated utilities.
Clear Lake Power Plant — During the third quarter of 2016, we filed with ERCOT to retire our 400 MW Clear Lake Power Plant. Built in 1985, Clear Lake is an older technology. Due to growing maintenance costs and lack of adequate compensation in Texas, we have chosen to retire the power plant. ERCOT has approved our plan to cease operations. We are working together with the facility’s bilateral counterparty to mutually agree on a date to cease commercial operations, which is expected no later than February 2017. The book value associated with our Clear Lake Power Plant is immaterial.
Customer Relationships
We continue to focus on providing products and services that are beneficial to our customers. A summary of certain significant achievements and contracts entered into in 2016 are as follows:
West
Our ten-year PPA with Southern California Edison for 50 MW of capacity and renewable energy from our Geysers Assets commencing in January 2018 was approved by the CPUC in the second quarter of 2016.
During the third quarter of 2016, Champion Energy expanded its service territory and now offers electricity service to commercial and industrial customers in California.
We entered into a new five-year PPA with USS-POSCO Industries to provide 50 MW of energy and steam from our Los Medanos Energy Center commencing in January 2017 which also provides for yearly extensions through 2024.
Texas
We entered into a new five-year steam agreement, subject to certain conditions precedent, with a wholly-owned subsidiary of The Dow Chemical Company to provide steam from our Texas City Power Plant through 2021.
During the third quarter of 2016, Champion Energy was ranked highest in customer satisfaction among Texas retail electric providers according to the J.D. Power 2016 Electric Provider Retail Customer Satisfaction Study. This is the sixth time Champion Energy has received the top ranking in the past seven years.
East
We entered into a new ten-year PPA with the Tennessee Valley Authority to provide 615 MW of energy and capacity from our Morgan Energy Center commencing in February 2016.
We satisfied final regulatory approval requirements for our 20-year PPA with Xcel Energy, which will facilitate a 345 MW expansion of our Mankato Power Plant.
We entered into a new five-year PPA with a third party to provide 50 MW of capacity from our RockGen Energy Center commencing in June 2017, which increases to 100 MW of capacity commencing in June 2019.
During the first quarter of 2016, Champion Energy expanded its New England service territory and now offers electricity service to commercial and industrial customers in Maine and Connecticut.

47



Wildfire at our Geysers Assets
In September 2015, a wildfire spread to our Geysers Assets in Lake and Sonoma counties, California. The wildfire affected several of our geothermal power plants in the region, which sustained damage to ancillary structures such as cooling towers and communication/electric deliverability infrastructure. Repairs have been completed and our Geysers Assets are currently generating renewable power for our customers at pre-fire levels. We believe the repair and replacement costs, as well as our net revenue losses relating to the wildfire, will be limited to our insurance deductibles of approximately $36 million, all of which was recognized in 2015. Any losses incurred in 2016 related to the wildfire will be primarily offset by insurance proceeds, when such proceeds are realizable. We record insurance proceeds in the same financial statement line as the related loss is incurred and recorded approximately $9 million and $17 million in business interruption proceeds in operating revenues during the three and nine months ended September 30, 2016, respectively. We do not anticipate the wildfire or timing of insurance proceeds recovery to have a material effect on our financial condition, results of operations or cash flows. 
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, 2015, our consolidated federal NOLs totaled approximately $6.9 billion.
Cash Flow Activities
The following table summarizes our cash flow activities for the nine months ended September 30, 2016 and 2015 (in millions):
 
2016
 
2015
Beginning cash and cash equivalents
$
906

 
$
717

Net cash provided by (used in):
 
 
 
Operating activities
667

 
559

Investing activities
(841
)
 
(450
)
Financing activities
(171
)
 
(167
)
Net decrease in cash and cash equivalents
(345
)
 
(58
)
Ending cash and cash equivalents
$
561

 
$
659

Net Cash Provided By Operating Activities
Cash provided by operating activities for the nine months ended September 30, 2016, was $667 million compared to $559 million for the nine months ended September 30, 2015. The increase was primarily due to:
Income from operations — Income from operations, adjusted for non-cash items, decreased by $125 million for the nine months ended September 30, 2016, compared to the same period in 2015. Non-cash items consist primarily of depreciation and amortization, income from unconsolidated investments in power plants and mark-to-market activity. The decrease in income from operations was primarily driven by a $112 million decrease in Commodity revenue, net of Commodity expense, excluding non-cash amortization, a $9 million increase in plant operating expense and a $6 million increase in sales, general and other administration expenses. See “Results of Operations for the Nine Months Ended September 30, 2016 and 2015” above for further discussion of these changes.
Working capital employed Working capital employed decreased by $167 million for the nine months ended September 30, 2016, compared to the same period in 2015, after adjusting for changes in debt, restricted cash and mark-to-market related balances which did not affect cash provided by operating activities. The decrease was primarily due to changes in our net margin posting requirements, derivative option premium activity and inventory offset by an increase in accounts receivable, net of accounts payable primarily driven by timing differences in commodity market prices as well as the effect of the acquisition of Champion Energy during the fourth quarter of 2015.
Interest paid Cash paid for interest decreased by $44 million to $421 million for the nine months ended September 30, 2016, from $465 million for the nine months ended September 30, 2015. The decrease was primarily due to our refinancing activities and timing of interest payments.
Debt modification & extinguishment payments During the nine months ended September 30, 2015, we made cash payments of $18 million related to repurchase penalties for a portion of the 2023 First Lien Notes and cash payments

48



of $13 million related to the debt modification costs associated with the issuance of the 2022 First Lien Term Loan. There was no similar activity for the nine months ended September 30, 2016.
Net Cash Used In Investing Activities
Cash used in investing activities for the nine months ended September 30, 2016, was $841 million compared to $450 million for the nine months ended September 30, 2015. The increase was primarily due to:
Purchase of Granite Ridge Energy Center — During the nine months ended September 30, 2016, we purchased a natural gas-fired, combined-cycle power plant located in Londonderry, New Hampshire for $526 million. There were no acquisitions during the nine months ended September 30, 2015.
Capital expenditures — Capital expenditures for the nine months ended September 30, 2016, were $337 million, a decrease of $74 million, compared to expenditures of $411 million for the nine months ended September 30, 2015. The decrease was primarily due to lower expenditures on construction projects and outages.
Restricted Cash Restricted cash decreased $2 million for the nine months ended September 30, 2016, compared to an increase of $31 million for the nine months ended September 30, 2015. The decrease was primarily attributed to the timing of funding the restricted accounts, maintenance and construction payments and debt payments.
Net Cash Used In Financing Activities
Cash used in financing activities for the nine months ended September 30, 2016, was $171 million compared to $167 million for the nine months ended September 30, 2015. The increase was primarily due to:
First Lien Term Loans, First Lien Notes and Senior Unsecured Notes — During the nine months ended September 30, 2016, we utilized proceeds from the issuance of the New 2023 First Lien Term Loan and the 2026 First Lien Notes to repay the 2019 and 2020 First Lien Term Loans of $1.2 billion. During the nine months ended September 30, 2015, we received proceeds of $650 million from the issuance of the 2024 Senior Unsecured Notes which were used to repurchase $147 million of the 2023 First Lien Notes. In addition, we utilized proceeds from the issuance of the 2022 First Lien Term Loan to repay the 2018 First Lien Term Loan of $1.6 billion.
Stock repurchases — During the nine months ended September 30, 2016, we repurchased an immaterial amount of common stock as compared to $510 million paid to repurchase our common stock during the nine months ended September 30, 2015.
Financing costs — During the nine months ended September 30, 2016, we incurred finance costs of $27 million due to the issuances of the New 2023 First Lien Term Loan and 2026 First Lien Notes and amending the Corporate Revolving Facility. During the nine months ended September 30, 2015, we incurred finance costs of $17 million due to the issuances of the 2024 Senior Unsecured Notes and the 2022 First Lien Term Loan and the re-pricing of the project debt for Los Esteros Critical Energy Facility, LLC.
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 2015 Form 10-K.

49



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, load sales, steam sales, buying and selling standard physical 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 subsidiary, Champion Energy, also provides us with an additional outlet to transact hedging activities related to our wholesale power plant portfolio.
We conduct our hedging and optimization activities within a structured risk management framework based on controls, policies and procedures. We monitor these activities through active and ongoing management and oversight, defined roles and responsibilities, and daily risk estimates and reporting. Additionally, we seek to manage the associated risks through diversification, by controlling position sizes, by using portfolio position limits, and by entering into offsetting positions that lock in a margin. We also 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 power and Heat Rate swaps and options) and fuel and purchased energy expense (for natural gas, power, environmental product and fuel oil contracts, swaps and options). 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 mostly through power and natural gas forward physical and financial transactions; however, we currently remain susceptible to significant price movements for 2016 and beyond. When we elect to enter into these transactions, we are able to economically hedge a portion of our Spark Spread at pre-determined generation and price levels.
We have historically used interest rate hedging instruments to adjust the mix between our fixed and variable rate debt. To the extent eligible, our interest rate hedging instruments have been designated as cash flow hedges, and changes in fair value are recorded in OCI to the extent they are effective with gains and losses reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. See Note 6 of the Notes to Consolidated Condensed Financial Statements for further discussion of our derivative instruments.
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 $1.3 billion at September 30, 2016, when compared to approximately $2.0 billion at December 31, 2015, and our derivative liabilities have decreased to approximately $1.4 billion at September 30, 2016, when compared to approximately $2.2 billion at December 31, 2015. The fair value of our level 3 derivative assets and liabilities at September 30, 2016 represent a small portion of our total assets and liabilities measured at fair value (approximately 3% and 2%, respectively). See Note 5 of the Notes to Consolidated Condensed Financial Statements for further information related to our level 3 derivative assets and liabilities.

50



The change in fair value of our outstanding commodity and interest rate hedging instruments from January 1, 2016, through September 30, 2016, is summarized in the table below (in millions):
 
Commodity Instruments
 
Interest Rate Hedging Instruments
 
Total
Fair value of contracts outstanding at January 1, 2016
$
(107
)
 
$
(89
)
 
$
(196
)
Items recognized or otherwise settled during the period(1)(2)
(6
)
 
28

 
22

Fair value attributable to new contracts
59

 
8

 
67

Changes in fair value attributable to price movements
(15
)
 
(20
)
 
(35
)
Changes in fair value attributable to nonperformance risk
(3
)
 

 
(3
)
Fair value of contracts outstanding at September 30, 2016(3)
$
(72
)
 
$
(73
)
 
$
(145
)
__________
(1)
Commodity contract settlements consist of the realization of previously recognized gains on contracts not designated as hedging instruments of $73 million (represents a portion of Commodity revenue and Commodity expense as reported on our Consolidated Condensed Statements of Operations) and $67 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 $26 million related to realized losses from settlements of designated cash flow hedges and $2 million related to realized losses from settlements of undesignated interest rate hedging instruments (represents a portion of interest expense as reported on our Consolidated Condensed Statements of Operations).
(3)
Net commodity and interest rate derivative assets and liabilities reported in Notes 5 and 6 of the Notes to Consolidated Condensed Financial Statements.
The change since the last balance sheet date in the total value of the derivatives (both assets and liabilities) is reflected either in cash for option premiums paid or collected, in OCI, net of tax for cash flow hedges, or on our Consolidated Condensed Statements of Operations as a component (gain or loss) in earnings.
The following tables detail the components of our total activity for both the net realized gain (loss) and the net mark-to-market gain (loss) recognized from our derivative instruments in earnings and where these components were recorded on our Consolidated Condensed Statements of Operations for the periods indicated (in millions):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
Realized gain (loss)(1)(2)
 
 
 
 
 
 
 
Commodity derivative instruments
$
32

 
$
160

 
$
213

 
$
323

Total realized gain (loss)
$
32

 
$
160

 
$
213

 
$
323

 
 
 
 
 
 
 
 
Mark-to-market gain (loss)(3)
 
 
 
 
 
 
 
Commodity derivative instruments
$
109

 
$
(75
)
 
$
(22
)
 
$
(6
)
Interest rate hedging instruments

 
1

 
1

 
2

Total mark-to-market gain (loss)
$
109

 
$
(74
)
 
$
(21
)
 
$
(4
)
Total activity, net
$
141

 
$
86

 
$
192

 
$
319

___________
(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 derivative activity related to the acquisition of Champion Energy.
(3)
In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification of AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.

51



 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
Realized and mark-to-market gain (loss)
 
 
 
 
 
 
 
Derivatives contracts included in operating revenues(1)(2)
$
308

 
$
189

 
$
240

 
$
423

Derivatives contracts included in fuel and purchased energy expense(1)(2)
(167
)
 
(104
)
 
(49
)
 
(106
)
Interest rate hedging instruments included in interest expense(3)

 
1

 
1

 
2

Total activity, net
$
141

 
$
86

 
$
192

 
$
319

___________
(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 derivative activity related to the acquisition of Champion Energy.
(3)
In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification of AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.
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 at September 30, 2016, based on price source and the period during which the instruments will mature, are summarized in the table below (in millions):
Fair Value Source
 
2016
 
2017-2018
 
2019-2020
 
After 2020
 
Total
Prices actively quoted
 
$
(8
)
 
$
39

 
$
1

 
$

 
$
32

Prices provided by other external sources
 
(5
)
 
(59
)
 
(31
)
 

 
(95
)
Prices based on models and other valuation methods
 
(2
)
 
(8
)
 
2

 
(1
)
 
(9
)
Total fair value
 
$
(15
)
 
$
(28
)
 
$
(28
)
 
$
(1
)
 
$
(72
)
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.
The table below presents the high, low and average of our daily VAR for the three and nine months ended September 30, 2016 and 2015 (in millions):
 
2016
 
2015
Three months ended September 30:
 
 
 
High
$
39

 
$
42

Low
$
15

 
$
19

Average
$
27

 
$
30

 
 
 
 
Nine months ended September 30:
 
 
 
High
$
39

 
$
42

Low
$
14

 
$
17

Average
$
24

 
$
26

As of September 30
$
18

 
$
32


52



Due to the inherent limitations of statistical measures such as VAR, the VAR calculation may not capture the full extent of our commodity price exposure. As a result, actual changes in the value of our energy commodity portfolio could be different from the calculated VAR, and could have a material effect on our financial results. In order to evaluate the risks of our portfolio on a comprehensive basis and augment our VAR analysis, we also measure the risk of the energy commodity portfolio using several analytical methods including sensitivity analysis, non-statistical scenario analysis, including stress testing, and daily position report analysis.
We utilize the forward commodity markets to hedge price risk associated with our power plant portfolio. Our ability to hedge relies in part on market liquidity and the number of counterparties with which to transact. While the number of counterparties in these markets has decreased, to date this occurrence has not had a material adverse effect on our results of operations or financial condition. However, should these conditions persist or increase, it could decrease our ability to hedge our forward commodity price risk and create incremental volatility in our earnings. The effects of declining liquidity in the forward commodity markets is also mitigated by our retail subsidiary, Champion Energy, 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. Increasing natural gas prices or Market Heat Rates can cause increased collateral requirements. Our liquidity management framework is intended to maximize liquidity access and minimize funding costs during times of rising prices. See further discussion regarding our uses of collateral as they relate to our commodity procurement and risk management activities in Note 7 of the Notes to Consolidated Condensed Financial Statements.
Credit Risk — Credit risk relates to the risk of loss resulting from nonperformance or non-payment by our counterparties related to their contractual obligations with us. Risks surrounding counterparty performance and credit could ultimately affect the amount and timing of expected cash flows. We also have credit risk if counterparties 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’ 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 customers relating to our sales of power and steam and our hedging, optimization and trading activities. We believe that our credit policies and portfolio of transactions adequately monitor and diversify our credit risk, and currently our counterparties 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 credit quality associated with the net fair value of outstanding derivative commodity instruments is included in our derivative assets and (liabilities) at September 30, 2016, and the period during which the instruments will mature are summarized in the table below (in millions):

Credit Quality
(Based on Standard & Poor’s Ratings
as of September 30, 2016)
 
2016
 
2017-2018
 
2019-2020
 
After 2020
 
Total
Investment grade
 
$
(18
)
 
$
(39
)
 
$
(30
)
 
$
(1
)
 
$
(88
)
Non-investment grade
 
3

 
6

 
1

 

 
10

No external ratings
 

 
5

 
1

 

 
6

Total fair value
 
$
(15
)
 
$
(28
)
 
$
(28
)
 
$
(1
)
 
$
(72
)

53



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 $(5) million at September 30, 2016.


54



APPLICATION OF CRITICAL ACCOUNTING POLICIES
The preparation of financial statements in accordance with U.S. GAAP requires management to make certain estimates and assumptions which are inherently imprecise and may differ significantly from actual results achieved. We have updated the following critical accounting policy to provide additional detail on our process of testing for impairments of our power plants. Otherwise, there have been no changes to the critical accounting policies previously disclosed in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Application of Critical Accounting Policies” of our 2015 Form 10-K.
Impairment Evaluation of Long-Lived Assets (Including Intangibles and Investments)
We evaluate our long-lived assets, such as property, plant and equipment, equity method investments, turbine equipment and specifically identified intangibles, on an annual basis or when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Examples of such events or changes in circumstances are:
a significant decrease in the market price of a long-lived asset;
a significant adverse change in the manner an asset is being used or its physical condition;
an adverse action by a regulator or legislature or an adverse change in the business climate;
an accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an asset;
a current-period loss combined with a history of losses or the projection of future losses; or
a change in our intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold or disposed of before the end of its previously estimated useful life.
When we believe an impairment condition on long-lived assets such as property, plant and equipment may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities for long-lived assets that are expected to be held and used. We use a fundamental long-term view of the power market which is based on long-term production volumes, price curves and operating costs together with the regulatory and environmental requirements within each individual market to prepare our multi-year forecast. Since we manage and market our power sales as a portfolio rather than at the individual power plant level or customer level within each designated market, pool or segment, we group our power plants based upon the corresponding market for valuation purposes. If we determine that the undiscounted cash flows from an asset or group of assets to be held and used are less than the associated carrying amount, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment loss.
We have temporarily suspended operations at our Sutter Energy Center. While the long-term market forecasted cash flows continue to support the carrying value of the asset, if the forecasted cash flows were to materially deteriorate, this could result in a permanent shut down of the facility and in the recognition of an impairment of our Sutter Energy Center and other plants within the respective market.
When we believe an impairment condition may exist on specifically identifiable finite-lived intangibles or an investment, we must estimate their fair value to determine the amount of any impairment loss. Significant judgment is required in determining fair value as discussed in our 2015 Form 10-K in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Application of Critical Accounting Policies — Fair Value Measurements.”
All construction and development projects are reviewed for impairment whenever there is an indication of potential reduction in fair value. If it is determined that it is no longer probable that the projects will be completed and all capitalized costs recovered through future operations, the carrying values of the projects would be written down to their fair value. When we determine that our assets meet the assets held-for-sale criteria, they are reported at the lower of the carrying amount or fair value less the cost to sell. We are also required to evaluate our equity method investments to determine whether or not they are impaired when the value is considered an “other than a temporary” decline in value.
See Note 2 of the Notes to Consolidated Financial Statements in our 2015 Form 10-K for further discussion of our impairment evaluation of long-lived assets.
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.


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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 2015 Form 10-K.

Item 4.
Controls and Procedures
Disclosure Controls and Procedures
As of the end of the period covered by this Report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rule 13a-15(e) and Rule 15d-15(e) of the Exchange Act. Based upon, and as of the date of, this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective such that the information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Changes in Internal Control Over Financial Reporting
During the third quarter of 2016, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


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PART II — OTHER INFORMATION

Item 1.
Legal Proceedings

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

Item 1A.
Risk Factors

Various risk factors could have a negative effect on our business, financial position, cash flows and results of operations. These include the following risk factor, in addition to the risk factors previously disclosed in Part I, Item 1A “Risk Factors” of our 2015 Form 10-K:
State legislative and regulatory action could adversely affect our competitive position and business.
Certain states have taken or are considering taking anticompetitive actions by subsidizing or otherwise providing economic support to existing, uneconomic power plants in a manner that could have an adverse effect on the deregulated power markets. We are actively participating in many of the legislative, regulatory and judicial processes challenging these actions at the state and federal levels. If these anticompetitive actions are ultimately upheld and implemented, they could adversely affect capacity and energy prices in the deregulated electricity markets which in turn could have a material negative effect on our business prospects and financial results.
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
Repurchase of Equity Securities
Period
 
(a)
Total Number of
Shares Purchased(1)
 
(b)
Average Price
Paid Per Share
 
(c)
Total Number  of
Shares Purchased
as Part of
Publicly Announced
Plans or Programs(2)
 
(d)
Maximum Dollar Value of Shares That May
Yet Be Purchased
Under the Plans or
Programs (in millions)(2)
July
 
376

 
$
15.02

 

 
$
307

August
 
5,737

 
$
13.17

 

 
$
307

September
 
865

 
$
12.53

 

 
$
307

Total
 
6,978

 
$
13.19

 

 
$
307

___________
(1)
To satisfy tax withholding obligations associated with the vesting of restricted stock awarded to employees during the third quarter of 2016, we withheld a total of 6,978 shares that are included in the total number of shares purchased.

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

Item 3.
Defaults Upon Senior Securities

None.

Item 4.
Mine Safety Disclosures

Not applicable.

Item 5.
Other Information

None.


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Item 6.
Exhibits
EXHIBIT INDEX
Exhibit
Number
 
Description
 
 
 
31.1
 
Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
31.2
 
Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
32.1
 
Certification of the Chief Executive Officer and the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. *
 
 
 
101.INS
 
XBRL Instance Document.
 
 
 
101.SCH
 
XBRL Taxonomy Extension Schema.
 
 
101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase.
 
 
101.DEF
 
XBRL Taxonomy Extension Definition Linkbase.
 
 
101.LAB
 
XBRL Taxonomy Extension Label Linkbase.
 
 
101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase.
_______________
*
Furnished herewith.


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

CALPINE CORPORATION
(Registrant)
 
 
By:
 
/s/  ZAMIR RAUF
 
 
Zamir Rauf
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
Date: October 27, 2016


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