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EX-31.1 - SECTION 302 CERTIFICATION OF CHIEF EXECUTIVE OFFICER - CALPINE CORPcpn_exhibit311x06302015.htm
EX-31.2 - SECTION 302 CERTIFICATION OF CHIEF FINANCIAL OFFICER - CALPINE CORPcpn_exhibit312x06302015.htm
EX-32.1 - CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER - CALPINE CORPcpn_exhibit321x06302015.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 June 30, 2015
 
 
 
 
Or
 
 
 
[    ]
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
 
 
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File No. 001-12079
______________________
Calpine Corporation
(A Delaware Corporation)
I.R.S. Employer Identification No. 77-0212977
717 Texas Avenue, Suite 1000, Houston, Texas 77002
Telephone: (713) 830-2000
Not Applicable
(Former Address)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes [X]    No [    ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes [X]    No [    ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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. (Check one):
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: 360,092,812 shares of common stock, par value $0.001, were outstanding as of July 28, 2015.


 




CALPINE CORPORATION AND SUBSIDIARIES
REPORT ON FORM 10-Q
For the Quarter Ended June 30, 2015
INDEX
 
 
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

i



DEFINITIONS
As used in this report for the quarter ended June 30, 2015 (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
2014 Form 10-K
 
Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2014, filed with the SEC on February 13, 2015
 
 
 
2018 First Lien Term Loans
 
Collectively, the $1.3 billion first lien senior secured term loan dated March 9, 2011 and the $360 million first lien senior secured term loan dated June 17, 2011
 
 
 
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 hereto, Morgan Stanley Senior Funding, Inc., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent
 
 
 
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 hereto, Citibank, N.A., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent
 
 
 
2022 First Lien Notes
 
The $750 million aggregate principal amount of 6.0% senior secured notes due 2022, issued October 31, 2013
 
 
 
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 hereto, Morgan Stanley Senior Funding, Inc., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent
 
 
 
2023 First Lien Notes
 
The $1.2 billion aggregate principal amount of 7.875% senior secured notes due 2023, issued January 14, 2011
 
 
 
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
 
 
 
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 extraordinary, 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

ii



ABBREVIATION
 
DEFINITION
 
 
 
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
 
Commodity 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 and New York
 
 
 
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
 
 
 
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 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
 
 
 

iii



ABBREVIATION
 
DEFINITION
Corporate Revolving Facility
 
The $1.5 billion aggregate amount revolving credit facility credit agreement, dated as of December 10, 2010, as amended on June 27, 2013 and July 30, 2014, among Calpine Corporation, Goldman Sachs Bank USA, as administrative agent, Goldman Sachs Credit Partners L.P., as 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
 
 
 
EPA
 
U.S. Environmental Protection Agency
 
 
 
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 and the 2024 First Lien Notes
 
 
 
First Lien Term Loans
 
Collectively, the 2018 First Lien Term Loans, the 2019 First Lien Term Loan, the 2020 First Lien Term Loan and the 2022 First Lien Term Loan
 
 
 
GE
 
General Electric International, Inc.
 
 
 
Geysers Assets
 
Our geothermal power plant assets, including our steam extraction and gathering assets, located in northern California consisting of 14 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
 
 
 
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

iv



ABBREVIATION
 
DEFINITION
 
 
 
MWh
 
Megawatt hour(s), a measure of power produced, purchased or sold
 
 
 
NOL(s)
 
Net operating loss(es)
 
 
 
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
 
 
 
RPS
 
Renewable Portfolio Standard
 
 
 
RTO(s)
 
Regional Transmission Organization(s)
 
 
 
SEC
 
U.S. Securities and Exchange Commission
 
 
 
Securities Act
 
U.S. Securities Act of 1933, as amended
 
 
 
Senior Unsecured Notes
 
Collectively, the 2023 Senior Unsecured Notes, the 2024 Senior Unsecured Notes and the 2025 Senior Unsecured Notes
 
 
 
Spark Spread(s)
 
The difference between the sales price of power per MWh and the cost of natural gas to produce it
 
 
 
Steam Adjusted Heat Rate
 
The adjusted Heat Rate for our natural gas-fired power plants, excluding peakers, calculated by dividing (a) the fuel consumed in Btu reduced by the net equivalent Btu in steam exported to a third party by (b) the KWh generated. Steam Adjusted Heat Rate is a measure of fuel efficiency, so the lower our Steam Adjusted Heat Rate, the lower our cost of generation
 
 
 
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

v



Forward-Looking Statements

This Report contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this Report, including without limitation, the “Management’s Discussion and Analysis” section. We use words such as “believe,” “intend,” “expect,” “anticipate,” “plan,” “may,” “will,” “should,” “estimate,” “potential,” “project” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. 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 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 revenues may not occur at expected levels;
Natural disasters, such as hurricanes, earthquakes, droughts and floods, acts of terrorism or cyber attacks that may impact our power plants or the markets our power plants serve and our corporate headquarters;
Disruptions in or limitations on the transportation of natural gas, fuel oil and 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 2014 Form 10-K and in other reports filed by us with the SEC.

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

vi



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

vii



PART I — FINANCIAL INFORMATION
Item 1.
Financial Statements

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
(Unaudited)
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2015
 
2014
 
2015
 
2014
 
(in millions, except share and per share amounts)
Operating revenues:
 
 
 
 
 
 
 
 
Commodity revenue
 
$
1,407

 
$
1,766

 
$
3,045

 
$
3,814

Mark-to-market gain
 
31

 
169

 
34

 
83

Other revenue
 
4

 
4

 
9

 
7

Operating revenues
 
1,442

 
1,939

 
3,088

 
3,904

Operating expenses:
 
 
 
 
 

 

Fuel and purchased energy expense:
 
 
 
 
 
 
 
 
Commodity expense
 
734

 
1,106

 
1,811

 
2,476

Mark-to-market (gain) loss
 
32

 
28

 
(35
)
 
15

Fuel and purchased energy expense
 
766

 
1,134

 
1,776

 
2,491

Plant operating expense
 
272

 
274

 
532

 
539

Depreciation and amortization expense
 
160

 
147

 
318

 
300

Sales, general and other administrative expense
 
30

 
38

 
67

 
71

Other operating expenses
 
20

 
21

 
40

 
43

Total operating expenses
 
1,248

 
1,614

 
2,733

 
3,444

(Income) from unconsolidated investments in power plants
 
(7
)
 
(4
)
 
(12
)
 
(13
)
Income from operations
 
201

 
329

 
367

 
473

Interest expense
 
158

 
169

 
312

 
335

Interest (income)
 
(1
)
 
(2
)
 
(2
)
 
(3
)
Debt modification and extinguishment costs
 
13

 

 
32

 
1

Other (income) expense, net
 
5

 
6

 
7

 
16

Income before income taxes
 
26

 
156

 
18

 
124

Income tax expense (benefit)
 
5

 
15

 
4

 
(4
)
Net income
 
21

 
141

 
14

 
128

Net income attributable to the noncontrolling interest
 
(2
)
 
(2
)
 
(5
)
 
(6
)
Net income attributable to Calpine
 
$
19

 
$
139

 
$
9

 
$
122

 
 
 
 
 
 
 
 
 
Basic earnings per common share attributable to Calpine:
 
 
 
 
 
 
 
 
Weighted average shares of common stock outstanding (in thousands)
 
366,975

 
416,507

 
369,938

 
418,296

Net income per common share attributable to Calpine — basic
 
$
0.05

 
$
0.33

 
$
0.02

 
$
0.29

 
 
 
 
 
 
 
 
 
Diluted earnings per common share attributable to Calpine:
 
 
 
 
 
 
 
 
Weighted average shares of common stock outstanding (in thousands)
 
369,946

 
421,348

 
373,404

 
422,697

Net income per common share attributable to Calpine — diluted
 
$
0.05

 
$
0.33

 
$
0.02

 
$
0.29


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 June 30,
 
Six Months Ended June 30,
 
 
2015
 
2014
 
2015
 
2014
 
(in millions)
Net income
 
$
21

 
$
141

 
$
14

 
$
128

Cash flow hedging activities:
 
 
 
 
 
 
 
 
Gain (loss) on cash flow hedges before reclassification adjustment for cash flow hedges realized in net income
 
2

 
(22
)
 
(16
)
 
(35
)
Reclassification adjustment for loss on cash flow hedges realized in net income
 
12

 
13

 
24

 
26

Foreign currency translation gain (loss)
 
4

 
6

 
(8
)
 

Income tax expense
 

 

 

 

Other comprehensive income (loss)
 
18

 
(3
)
 

 
(9
)
Comprehensive income
 
39

 
138

 
14

 
119

Comprehensive (income) attributable to the noncontrolling interest
 
(4
)
 
(1
)
 
(6
)
 
(5
)
Comprehensive income attributable to Calpine
 
$
35

 
$
137

 
$
8

 
$
114


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


2



CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
(Unaudited)

 
 
June 30,
 
December 31,
 
 
2015
 
2014
 
 
(in millions, except share and per share amounts)
ASSETS
 
 
 
 
Current assets:
 
 
 
 
Cash and cash equivalents ($254 and $229 attributable to VIEs)
 
$
422

 
$
717

Accounts receivable, net of allowance of $3 and $4
 
595

 
648

Inventories
 
477

 
447

Margin deposits and other prepaid expense
 
152

 
148

Restricted cash, current ($93 and $106 attributable to VIEs)
 
162

 
195

Derivative assets, current
 
1,607

 
2,058

Other current assets
 
32

 
7

Total current assets
 
3,447

 
4,220

Property, plant and equipment, net ($4,260 and $4,342 attributable to VIEs)
 
13,147

 
13,190

Restricted cash, net of current portion ($47 and $48 attributable to VIEs)
 
48

 
49

Investments in power plants
 
87

 
95

Long-term derivative assets
 
637

 
439

Other assets ($172 and $164 attributable to VIEs)
 
391

 
385

Total assets
 
$
17,757

 
$
18,378

LIABILITIES & STOCKHOLDERS’ EQUITY
 
 
 
 
Current liabilities:
 
 
 
 
Accounts payable
 
$
443

 
$
580

Accrued interest payable
 
133

 
165

Debt, current portion ($148 and $150 attributable to VIEs)
 
198

 
199

Derivative liabilities, current
 
1,407

 
1,782

Other current liabilities
 
355

 
473

Total current liabilities
 
2,536

 
3,199

Debt, net of current portion ($3,168 and $3,242 attributable to VIEs)
 
11,493

 
11,083

Long-term derivative liabilities
 
453

 
444

Other long-term liabilities
 
274

 
221

Total liabilities
 
14,756

 
14,947

 
 
 
 
 
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, 504,252,268 and 502,287,022 shares issued, respectively, and 361,150,393 and 381,921,264 shares outstanding, respectively
 
1

 
1

Treasury stock, at cost, 143,101,875 and 120,365,758 shares, respectively
 
(2,810
)
 
(2,345
)
Additional paid-in capital
 
12,463

 
12,440

Accumulated deficit
 
(6,531
)
 
(6,540
)
Accumulated other comprehensive loss
 
(179
)
 
(178
)
Total Calpine stockholders’ equity
 
2,944

 
3,378

Noncontrolling interest
 
57

 
53

Total stockholders’ equity
 
3,001

 
3,431

Total liabilities and stockholders’ equity
 
$
17,757

 
$
18,378


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)

 
 
Six Months Ended June 30,
 
 
2015
 
2014
 
 
(in millions)
Cash flows from operating activities:
 
 
 
 
Net income
 
$
14

 
$
128

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

 

Depreciation and amortization expense(1)
 
342

 
322

Deferred income taxes
 
3

 
(12
)
Mark-to-market activity, net
 
(70
)
 
(70
)
(Income) from unconsolidated investments in power plants
 
(12
)
 
(13
)
Return on unconsolidated investments in power plants
 
13

 
13

Stock-based compensation expense
 
12

 
22

Other
 
2

 
2

Change in operating assets and liabilities:
 

 

Accounts receivable
 
29

 
(212
)
Derivative instruments, net
 
(36
)
 
(109
)
Other assets
 
(118
)
 
(40
)
Accounts payable and accrued expenses
 
(205
)
 
378

Other liabilities
 
45

 
(60
)
Net cash provided by operating activities
 
19

 
349

Cash flows from investing activities:
 
 
 
 
Purchases of property, plant and equipment
 
(279
)
 
(258
)
Purchase of Guadalupe Energy Center
 

 
(656
)
Decrease in restricted cash
 
34

 
14

Other
 
(1
)
 

Net cash used in investing activities
 
(246
)
 
(900
)
Cash flows from financing activities:
 
 
 
 
Borrowings under CCFC Term Loans and First Lien Term Loans
 
1,592

 
420

Repayment of CCFC Term Loans and First Lien Term Loans
 
(1,613
)
 
(23
)
Borrowings under Senior Unsecured Notes
 
650

 

Repurchase of First Lien Notes
 
(147
)
 

Borrowings from project financing, notes payable and other
 

 
2

Repayments of project financing, notes payable and other
 
(85
)
 
(55
)
Financing costs
 
(17
)
 
(10
)
Stock repurchases
 
(454
)
 
(297
)
Proceeds from exercises of stock options
 
6

 
15

Net cash provided by (used in) financing activities
 
(68
)
 
52

Net decrease in cash and cash equivalents
 
(295
)
 
(499
)
Cash and cash equivalents, beginning of period
 
717

 
941

Cash and cash equivalents, end of period
 
$
422

 
$
442


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)

 
 
Six Months Ended June 30,
 
 
2015
 
2014
 
 
(in millions)
Cash paid during the period for:
 
 
 
 
Interest, net of amounts capitalized
 
$
322

 
$
288

Income taxes
 
$
17

 
$
16

 
 
 
 
 
Supplemental disclosure of non-cash investing and financing activities:
 
 
 
 
Change in capital expenditures included in accounts payable
 
$
(20
)
 
$
13

Additions to property, plant and equipment through capital lease
 
$
9

 
$

____________
(1)
Includes depreciation and amortization included in fuel and purchased energy expense and interest expense on our Consolidated Condensed Statements of Operations.
The accompanying notes are an integral part of these Consolidated Condensed Financial Statements.


5



CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
June 30, 2015
(Unaudited)
1.
Basis of Presentation and Summary of Significant Accounting Policies
We are a wholesale 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 region (included in our East segment) of the U.S. We sell wholesale 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, power marketers and others. 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 purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas, power and other physical and financial 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, 2014, included in our 2014 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, timing of major maintenance expense, variations resulting from the application of the method to calculate the provision for income tax for interim periods, volatility of commodity prices and mark-to-market gains and losses from commodity and interest rate derivative contracts.
Use of Estimates in Preparation of Financial Statements — The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures included in our Consolidated Condensed Financial Statements. Actual results could differ from those estimates.
Reclassifications — We have reclassified certain prior year amounts for comparative purposes. These reclassifications did not have a material impact on our financial condition, results of operations or cash flows.
Cash and Cash Equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts, which 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. 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, major maintenance and debt repurchases or with applicable regulatory requirements. Funds that are expected to 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 June 30, 2015 and December 31, 2014 (in millions):

 
June 30, 2015
 
December 31, 2014
 
Current
 
Non-Current
 
Total
 
Current
 
Non-Current
 
Total
Debt service
$
16

 
$
25

 
$
41

 
$
10

 
$
25

 
$
35

Rent reserve

 

 

 
4

 

 
4

Construction/major maintenance
50

 
19

 
69

 
54

 
17

 
71

Security/project/insurance
93

 
4

 
97

 
127

 
5

 
132

Other
3

 

 
3

 

 
2

 
2

Total
$
162

 
$
48

 
$
210

 
$
195

 
$
49

 
$
244

Property, Plant and Equipment, Net — At June 30, 2015 and December 31, 2014, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
 
June 30, 2015
 
December 31, 2014
 
Depreciable Lives
Buildings, machinery and equipment
$
16,422

 
$
16,059

 
3 – 47 Years
Geothermal properties
1,320

 
1,294

 
13 – 58 Years
Other
208

 
203

 
3 – 47 Years
 
17,950

 
17,556

 
 
Less: Accumulated depreciation
5,236

 
4,984

 
 
 
12,714

 
12,572

 
 
Land
121

 
120

 
 
Construction in progress
312

 
498

 
 
Property, plant and equipment, net
$
13,147

 
$
13,190

 
 
Capitalized Interest — The total amount of interest capitalized was $4 million and $6 million for the three months ended June 30, 2015 and 2014, respectively, and $9 million and $12 million for the six months ended June 30, 2015 and 2014, respectively.
Treasury Stock — During the six months ended June 30, 2015, we repurchased a total of 22.1 million shares of our outstanding common stock for approximately $454 million at an average price of $20.50 per share. Additionally, we withheld shares with a value of $11 million to satisfy tax withholding obligations associated with the vesting of restricted stock awarded to employees and with net share employee stock option exercises under the Equity Plan.
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 was 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 July 2015, the FASB approved a proposal to defer the effective date of Accounting Standards Update 2014-09 for public entities by one year, which would result in the standard being effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017. The proposal would also permit entities to early adopt, but only as of the original effective date. We are currently assessing the future impact this 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.” This 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 is effective for fiscal periods beginning after December 15, 2015, including interim

7



periods within that reporting period and allows for either full retrospective or modified retrospective adoption with early adoption permitted. We do not anticipate a material impact on our financial condition, results of operations or cash flows as a result of adopting this standard.

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. The standard is effective for fiscal years beginning after December 15, 2015, including interim periods within that reporting period and requires retrospective adoption with early adoption permitted. We do not anticipate a material impact on our financial condition, results of operations or cash flows as a result of adopting this standard.

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.” This standard provides guidance regarding whether a cloud computing arrangement represents a software license or a service contract. The standard is effective for fiscal years beginning after December 15, 2015, including interim periods and allows for either prospective or retrospective adoption with early adoption permitted. We are currently assessing the future impact this standard may have 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.” This 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 impact on our financial condition, results of operations or cash flows as a result of adopting this standard.
2.
Acquisitions
Acquisition of Champion Energy
On July 20, 2015, we announced that we have entered into an agreement, through our indirect, wholly-owned subsidiary Calpine Energy Services Holdco LLC, to purchase Champion Energy Marketing, LLC from Champion Energy Holdings, LLC, which owns a 75% interest, and EDF Trading North America, LLC, which owns a 25% interest, for approximately $240 million, excluding working capital adjustments. Champion Energy, a leading retail electric provider, is expected to serve approximately 22 million MWh of commercial, industrial and residential customer load in 2015, concentrated in Texas, PJM and the Northeast U.S. where Calpine has a substantial power generation presence. The addition of this well-established retail sales organization is expected to provide us an important outlet for directly reaching a much greater portion of the load we serve. We expect the transaction to close by the fourth quarter of 2015, subject to regulatory approvals, and will fund the acquisition with cash on hand.
Acquisition of Fore River Energy Center
On November 7, 2014, we, through our indirect, wholly-owned subsidiary Calpine Fore River Energy Center, LLC, completed the purchase of Fore River Energy Center, a power plant with a nameplate capacity of 809 MW, and related plant inventory from a subsidiary of Exelon Corporation, for approximately $530 million, excluding working capital adjustments. During the six months ended June 30, 2015, there were no material adjustments made to the initial purchase price allocation recorded in the fourth quarter of 2014 related to our acquisition of Fore River Energy Center. Although the purchase price allocation has not been finalized, we do not expect to record any material adjustments to the preliminary purchase price allocation nor do we expect to recognize any goodwill as a result of this acquisition.
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 six months ended June 30, 2015. See Note 5 in our 2014 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 and 10,365 MW at June 30, 2015 and December 31, 2014, 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

8



amounts contractually required, we provided support to these VIEs in the form of cash and other contributions of nil during each of the three and six months ended June 30, 2015 and nil and $40 million during the three and six months ended June 30, 2014, respectively.
Unconsolidated VIEs and Investments in Power Plants
We have a 50% partnership interest in Greenfield LP and in Whitby. Greenfield LP and Whitby are also 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 June 30, 2015 and December 31, 2014, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):
 
 
Ownership Interest as of
June 30, 2015
 
June 30, 2015
 
December 31, 2014
Greenfield LP
50%
 
$
78

 
$
78

Whitby
50%
 
9

 
17

Total investments in power plants
 
 
$
87

 
$
95

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; therefore, the debt of our unconsolidated investments is not reflected on our Consolidated Condensed Balance Sheets. At June 30, 2015 and December 31, 2014, equity method investee debt was approximately $312 million and $342 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $156 million and $171 million at June 30, 2015 and December 31, 2014, respectively.
Our equity interest in the net income from Greenfield LP and Whitby for the three and six months ended June 30, 2015 and 2014, is recorded in (income) from unconsolidated investments in power plants on our Consolidated Condensed Statements of Operations. The following table sets forth details of our (income) from unconsolidated investments in power plants for the periods indicated (in millions):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2015
 
2014
 
2015
 
2014
Greenfield LP
$
(4
)
 
$

 
$
(6
)
 
$
(5
)
Whitby
(3
)
 
(4
)
 
(6
)
 
(8
)
Total
$
(7
)
 
$
(4
)
 
$
(12
)
 
$
(13
)

Distributions from Greenfield LP were nil during each of the three and six months ended June 30, 2015 and 2014. Distributions from Whitby were $13 million during each of the three and six months ended June 30, 2015 and nil and $13 million during the three and six months ended June 30, 2014, respectively.
Inland Empire Energy Center Put and Call Options — We hold a call option to purchase the Inland Empire Energy Center (a 775 MW natural gas-fired power plant located in California) from GE that may be exercised between years 2017 and 2024. GE holds a put option whereby they can require us to purchase the power plant, if certain plant performance criteria are met by 2025. We determined that we are not the primary beneficiary of the Inland Empire power plant, and we do not consolidate it due to the fact that GE directs the most significant activities of the power plant including operations and maintenance.

9



Significant Unconsolidated Subsidiaries — Greenfield LP and Whitby met the criteria of significant unconsolidated subsidiaries for the six months ended June 30, 2015, based upon the relationship of our equity income from our investment to our consolidated net income before taxes. Aggregated summarized financial data for the six months ended June 30, 2015 and 2014 are set forth below (in millions):

Condensed Combined Statements of Operations
of Our Unconsolidated Subsidiaries
(Unaudited)

 
 
Six Months Ended June 30,
 
 
2015
 
2014
Revenues
 
$
98

 
$
149

Operating expenses
 
66

 
111

Income from operations
 
32

 
38

Interest expense, net of interest income
 
10

 
12

Other (income) expense, net
 
(1
)
 

Net income
 
$
23

 
$
26

4.
Debt
Our debt at June 30, 2015 and December 31, 2014, was as follows (in millions):
 
June 30, 2015

December 31, 2014
Senior Unsecured Notes
$
3,450

 
$
2,800

First Lien Term Loans
2,787

 
2,799

First Lien Notes
1,928

 
2,075

Project financing, notes payable and other
1,737

 
1,810

CCFC Term Loans
1,588

 
1,596

Capital lease obligations
201

 
202

Subtotal
11,691

 
11,282

Less: Current maturities
198

 
199

Total long-term debt
$
11,493

 
$
11,083

Our effective interest rate on our consolidated debt, excluding the impacts of capitalized interest and mark-to-market gains (losses) on interest rate swaps, decreased to 5.5% for the six months ended June 30, 2015, from 6.1% for the same period in 2014. The issuance of our Senior Unsecured Notes in July 2014 and 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 Notes and all of our 2018 First Lien Term Loans with debt carrying lower interest rates.
Senior Unsecured Notes
The amounts outstanding under our Senior Unsecured Notes are summarized in the table below (in millions):
 
June 30, 2015
 
December 31, 2014
2023 Senior Unsecured Notes
$
1,250

 
$
1,250

2024 Senior Unsecured Notes
650

 

2025 Senior Unsecured Notes
1,550

 
1,550

Total Senior Unsecured Notes
$
3,450

 
$
2,800

In February 2015, we issued $650 million in aggregate principal amount of 5.5% senior unsecured notes due 2024 in a public offering. The 2024 Senior Unsecured Notes bear interest at 5.5% per annum with interest payable semi-annually on February 1 and August 1 of each year, beginning on August 1, 2015. The 2024 Senior Unsecured Notes were issued at par, mature on February 1, 2024 and contain substantially similar covenants, qualifications, exceptions and limitations as our 2023 Senior

10



Unsecured Notes and 2025 Senior Unsecured Notes. We used the net proceeds received from the issuance of our 2024 Senior Unsecured Notes to replenish cash on hand used for the acquisition of Fore River Energy Center in the fourth quarter of 2014, to repurchase approximately $147 million of our 2023 First Lien Notes and for general corporate purposes. During the first quarter of 2015, we recorded approximately $9 million in deferred financing costs related to the issuance of our 2024 Senior Unsecured Notes and approximately $19 million in debt extinguishment costs related to the partial repurchase of our 2023 First Lien Notes.
First Lien Term Loans
The amounts outstanding under our First Lien Term Loans are summarized in the table below (in millions):
 
June 30, 2015
 
December 31, 2014
2018 First Lien Term Loans
$

 
$
1,597

2019 First Lien Term Loan
812

 
816

2020 First Lien Term Loan
384

 
386

2022 First Lien Term Loan
1,591

 

Total First Lien Term Loans
$
2,787

 
$
2,799

On May 28, 2015, we entered into our $1.6 billion 2022 First Lien Term Loan. We used the net proceeds received, together with operating cash on hand, to repay the 2018 First Lien Term Loans. The 2022 First Lien Term Loan matures on May 27, 2022 and 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 2022 First Lien Term Loan credit agreement), plus an applicable margin of 1.75%, or (ii) LIBOR plus 2.75% per annum subject to a LIBOR floor of 0.75%. An aggregate amount equal to 0.25% of the aggregate principal amount of the 2022 First Lien Term Loan will be payable at the end of each quarter commencing in September 2015. The 2022 First Lien Term Loan contains substantially similar covenants, qualifications, exceptions and limitations as the First Lien Term Loans and First Lien Notes.
We accounted for this transaction as a debt modification rather than an extinguishment of debt and, accordingly, did not record any debt extinguishment costs associated with the repayment of our 2018 First Lien Term Loans. However, in accordance with the accounting guidance for debt modification and extinguishment, we recorded approximately $13 million in debt modification costs associated with issuance costs and approximately $6 million in deferred financing costs related to the 2022 First Lien Term Loan during the second quarter of 2015.
First Lien Notes
The amounts outstanding under our First Lien Notes are summarized in the table below (in millions):
 
June 30, 2015
 
December 31, 2014
2022 First Lien Notes
$
745

 
$
745

2023 First Lien Notes(1)
693

 
840

2024 First Lien Notes
490

 
490

Total First Lien Notes
$
1,928

 
$
2,075

____________
(1)
On February 3, 2015, we repurchased approximately $147 million of our 2023 First Lien Notes with the proceeds from our 2024 Senior Unsecured Notes, as described in further detail above.

11



Corporate Revolving Facility and Other Letters of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at June 30, 2015 and December 31, 2014 (in millions):
 
June 30, 2015
 
December 31, 2014
Corporate Revolving Facility(1)
$
179

 
$
223

CDHI
244

 
214

Various project financing facilities
219

 
207

Total
$
642

 
$
644

____________
(1)
The Corporate Revolving Facility represents our primary revolving facility.
Fair Value of Debt
We record our debt instruments based on contractual terms, net of any applicable premium or discount. The following table details the fair values and carrying values of our debt instruments at June 30, 2015 and December 31, 2014 (in millions):
 
June 30, 2015
 
December 31, 2014
 
Fair Value
 
Carrying
Value
 
Fair Value
 
Carrying
Value
Senior Unsecured Notes
$
3,347

 
$
3,450

 
$
2,832

 
$
2,800

First Lien Term Loans
2,768

 
2,787

 
2,769

 
2,799

First Lien Notes
2,059

 
1,928

 
2,247

 
2,075

Project financing, notes payable and other(1)
1,660

 
1,629

 
1,734

 
1,688

CCFC Term Loans
1,564

 
1,588

 
1,540

 
1,596

Total
$
11,398

 
$
11,382

 
$
11,122

 
$
10,958

____________
(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, 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. 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 swaps. 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.

12



We utilize market data, such as pricing services and broker quotes, and assumptions that we believe market participants would use in pricing our assets or liabilities including assumptions about the risks inherent to the inputs in the valuation technique. These inputs can be either readily observable, market corroborated or generally unobservable. The market data obtained from broker pricing services is evaluated to determine the nature of the quotes obtained and, where accepted as a reliable quote, used to validate our assessment of fair value. We use other qualitative assessments to determine the level of activity in any given market. We primarily apply the market approach and income approach for recurring fair value measurements and utilize what we believe to be the best available information. We utilize valuation techniques that seek to maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the observability of those inputs.
The fair value of our derivatives includes consideration of our credit standing, the credit standing of our counterparties and the impact 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 swaps and OTC power and natural gas forwards for which market-based pricing inputs are observable. Generally, we obtain our level 2 pricing inputs from market sources such as the Intercontinental Exchange and Bloomberg. To the extent we obtain prices from brokers in the marketplace, we have procedures in place to ensure that prices represent executable prices for market participants. 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 impact 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.

13



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 June 30, 2015 and December 31, 2014, by level within the fair value hierarchy:
 
Assets and Liabilities with Recurring Fair Value Measures as of June 30, 2015
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
577

 
$

 
$

 
$
577

Margin deposits
103

 

 

 
103

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,684

 

 

 
1,684

Commodity forward contracts(2)

 
284

 
273

 
557

Interest rate swaps

 
3

 

 
3

Total assets
$
2,364

 
$
287

 
$
273

 
$
2,924

Liabilities:
 
 
 
 
 
 
 
Margin deposits posted with us by our counterparties
$
53

 
$

 
$

 
$
53

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,506

 

 

 
1,506

Commodity forward contracts(2)

 
219

 
30

 
249

Interest rate swaps

 
105

 

 
105

Total liabilities
$
1,559

 
$
324

 
$
30

 
$
1,913

 
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2014
 
Level 1    
 
Level 2    
 
Level 3    
 
Total    
 
(in millions)
Assets:
 
 
 
 
 
 
 
Cash equivalents(1)
$
896

 
$

 
$

 
$
896

Margin deposits
96

 

 

 
96

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
2,134

 

 

 
2,134

Commodity forward contracts(2)

 
195

 
164

 
359

Interest rate swaps

 
4

 

 
4

Total assets
$
3,126

 
$
199

 
$
164

 
$
3,489

Liabilities:
 
 
 
 
 
 
 
Margin deposits posted with us by our counterparties
$
47

 
$

 
$

 
$
47

Commodity instruments:
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
1,870

 

 

 
1,870

Commodity forward contracts(2)

 
163

 
79

 
242

Interest rate swaps

 
114

 

 
114

Total liabilities
$
1,917

 
$
277

 
$
79

 
$
2,273

___________
(1)
As of June 30, 2015 and December 31, 2014, we had cash equivalents of $367 million and $679 million included in cash and cash equivalents and $210 million and $217 million included in restricted cash, respectively.
(2)
Includes OTC swaps and options.

14



At June 30, 2015 and December 31, 2014, the derivative instruments classified as level 3 primarily included commodity contracts, which are classified as level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net derivative position classified as level 3 is predominantly driven by market commodity prices. The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at June 30, 2015 and December 31, 2014:
 
 
Quantitative Information about Level 3 Fair Value Measurements
 
 
June 30, 2015
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
Power Contracts
 
$
237

 
Discounted cash flow
 
Market price (per MWh)
 
$12.68 — $121.40/MWh
Power Congestion Products
 
$
7

 
Discounted cash flow
 
Market price (per MWh)
 
$(19.56) — $19.56/MWh
 
 
 
 
 
 
 
 
 
 
 
December 31, 2014
 
 
Fair Value, Net Asset
 
 
 
Significant Unobservable
 
 
 
 
(Liability)
 
Valuation Technique
 
Input
 
Range
 
 
(in millions)
 
 
 
 
 
 
Power Contracts
 
$
74

 
Discounted cash flow
 
Market price (per MWh)
 
$14.00 — $122.79/MWh
Natural Gas Contracts
 
$
5

 
Discounted cash flow
 
Market price (per MMBtu)
 
$1.00 — $10.86/MMBtu
Power Congestion Products
 
$
9

 
Discounted cash flow
 
Market price (per MWh)
 
$(19.56) — $19.56/MWh
The following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the periods indicated (in millions):
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2015
 
2014
 
2015
 
2014
Balance, beginning of period
 
$
203

 
$
8

 
$
85

 
$
14

Realized and mark-to-market gains (losses):
 
 
 
 
 
 
 
 
Included in net income:
 
 
 
 
 
 
 
 
Included in operating revenues(1)
 
45

 
(7
)
 
176

 
(15
)
Included in fuel and purchased energy expense(2)
 

 

 
2

 
6

Purchases and settlements:
 
 
 
 
 
 
 
 
Purchases
 
2

 

 
4

 

Settlements
 
(10
)
 
(3
)
 
(21
)
 
(6
)
Transfers in and/or out of level 3(3):
 
 
 
 
 
 
 
 
Transfers into level 3(4)
 

 
2

 

 

Transfers out of level 3(5)
 
3

 
(9
)
 
(3
)
 
(8
)
Balance, end of period
 
$
243

 
$
(9
)
 
$
243

 
$
(9
)
Change in unrealized gains (losses) relating to instruments still held at end of period
 
$
45

 
$
(7
)
 
$
178

 
$
(9
)
___________
(1)
For power contracts and other power-related products, included on our Consolidated Condensed Statements of Operations.
(2)
For natural gas contracts, swaps and options, included on our Consolidated Condensed Statements of Operations.
(3)
We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no transfers into or out of level 1 for each of the three and six months ended June 30, 2015 and 2014.
(4)
There were no transfers out of level 2 into level 3 for each of the three and six months ended June 30, 2015 and for the six months ended June 30, 2014. We had $2 million in gains transferred out of level 2 into level 3 for the three months ended June 30, 2014, due to changes in market liquidity in various power markets.

15



(5)
We had $3 million in losses and $(9) million in gains transferred out of level 3 into level 2 for the three months ended June 30, 2015 and 2014, respectively, and $(3) million and $(8) million in gains transferred out of level 3 into level 2 for the six months ended June 30, 2015 and 2014, 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, 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 the three and six months ended June 30, 2015 and 2014.
Interest Rate Swaps — A portion of our debt is indexed to base rates, primarily LIBOR. We have historically used interest rate swaps to adjust the mix between fixed and floating rate debt to hedge our interest rate risk for potential adverse changes in interest rates. As of June 30, 2015, the maximum length of time over which we were hedging using interest rate derivative instruments designated as cash flow hedges was 8 years.
As of June 30, 2015 and December 31, 2014, the net forward notional buy (sell) position of our outstanding commodity and interest rate swap contracts that did not qualify or were not designated under the normal purchase normal sale exemption were as follows (in millions):
Derivative Instruments
 
Notional Amounts
 
June 30, 2015
 
December 31, 2014
Power (MWh)
 
(99
)
 
(62
)
Natural gas (MMBtu)
 
874

 
291

Environmental credits (Tonnes)
 
3

 

Interest rate swaps
 
$
1,411

 
$
1,431

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 June 30, 2015, was $12 million for which we have posted collateral of $9 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 $14 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

16



hedged) within operating activities or investing 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 derivative instruments. We report the effective portion of the mark-to-market gain or loss on our interest rate swaps 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 impacts 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 and environmental product 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 contracts, environmental product 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.
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 June 30, 2015 and December 31, 2014 (in millions):
 
June 30, 2015
  
Commodity
Instruments
 
Interest Rate
Swaps
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
1,607

 
$

 
$
1,607

Long-term derivative assets
634

 
3

 
637

Total derivative assets
$
2,241

 
$
3

 
$
2,244

 
 
 
 
 
 
Current derivative liabilities
$
1,365

 
$
42

 
$
1,407

Long-term derivative liabilities
390

 
63

 
453

Total derivative liabilities
$
1,755

 
$
105

 
$
1,860

Net derivative asset (liabilities)
$
486

 
$
(102
)
 
$
384


 
December 31, 2014
 
Commodity
Instruments
 
Interest Rate
Swaps
 
Total
Derivative
Instruments
Balance Sheet Presentation
 
 
 
 
 
Current derivative assets
$
2,058

 
$

 
$
2,058

Long-term derivative assets
435

 
4

 
439

Total derivative assets
$
2,493

 
$
4

 
$
2,497

 
 
 
 
 
 
Current derivative liabilities
$
1,738

 
$
44

 
$
1,782

Long-term derivative liabilities
374

 
70

 
444

Total derivative liabilities
$
2,112

 
$
114

 
$
2,226

Net derivative asset (liabilities)
$
381

 
$
(110
)
 
$
271



17



 
June 30, 2015
 
December 31, 2014
 
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 swaps
$
3

 
$
105

 
$
4

 
$
112

Total derivatives designated as cash flow hedging instruments
$
3

 
$
105

 
$
4

 
$
112

 
 
 
 
 
 
 
 
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
Commodity instruments
$
2,241

 
$
1,755

 
$
2,493

 
$
2,112

Interest rate swaps

 

 

 
2

Total derivatives not designated as hedging instruments
$
2,241

 
$
1,755

 
$
2,493

 
$
2,114

Total derivatives
$
2,244

 
$
1,860

 
$
2,497

 
$
2,226

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.
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 June 30, 2015 and December 31, 2014 (in millions):
 
 
June 30, 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
 
$
1,684

 
$
(1,506
)
 
$
(178
)
 
$

Commodity forward contracts
 
557

 
(231
)
 
(9
)
 
317

Interest rate swaps
 
3

 

 

 
3

Total derivative assets
 
$
2,244

 
$
(1,737
)
 
$
(187
)
 
$
320

Derivative (liabilities):
 
 
 
 
 
 
 
 
Commodity exchange traded futures and swaps contracts
 
$
(1,506
)
 
$
1,506

 
$

 
$

Commodity forward contracts
 
(249
)
 
231

 
9

 
(9
)
Interest rate swaps
 
(105
)
 

 

 
(105
)
Total derivative (liabilities)
 
$
(1,860