2 0 1 2 A N N U A L R E P O R T
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Calpine Corporation
717 Texas Avenue, Suite 1000
Houston, Texas 77002
(713) 830-2000
w w w . c a l p i n e . c o m
Delivering Effective
Capital Allocation
As a management team, we are committed to being good stewards of your
capital. Our goal is to deliver Adjusted Free Cash Flow Per Share growth
of 15 – 20% compounded annually. We strive to do this by identifying high-
return growth projects while also opportunistically repurchasing our stock,
which we believe represents an investment in clean, efficient and flexible
natural gas-fired generation at attractive prices. As America moves toward
clean, affordable natural gas as the preferred fuel for power generation and
as the electric grid requires more flexible power generation to integrate inter-
mittent renewable power to assure reliability of electric supply, we believe
Calpine’s fleet is uniquely positioned to benefit from the combination of these
secular and fundamental trends that favor combined-cycle natural gas-fired
power generation as the technology of choice for America’s future.
BOARD OF DIRECTORS
J. Stuart Ryan (N)
Chairman of the Board
Chief Executive Officer, Aggregates USA and
Founding Owner and President, Rydout LLC
Retired President and Chief Operating Officer
Frank Cassidy (C)
PSEG Power LLC
Jack A. Fusco
Chief Executive Officer, Calpine Corp.
Robert C. Hinckley (A)(N)
Chairman and Managing Director, MCL Intellectual
Property LLC
W. Benjamin Moreland (A)
President and Chief Executive Officer
Crown Castle International Corp.
Robert A. Mosbacher, Jr. (C)(N)
Chairman, Mosbacher Energy Company
William E. Oberndorf (C)
Chairman, Oberndorf Enterprises, LLC
Denise M. O’Leary (C)(N)
Private Venture Capital Investor
(A) Audit Committee
(C) Compensation Committee
(N) Nominating and Governance Committee
Calpine’s management team rings the closing
bell at the New York Stock Exchange (L to R):
Thad Hill (President and COO), Jack Fusco
(CEO), Thad Miller (EVP and CLO) and
Zamir Rauf (EVP and CFO).
National Portfolio of more than 27,000 MW in Operation
NORTH REGION
30 plants
7,320 MW
309 MW Under Advanced
Development
WEST REGION
37 plants
6,751 MW
773 MW Under Construction
TEXAS REGION
13 plants
8,014 MW
390 MW Under Construction
SOUTHEAST REGION
10 plants
5,236 MW
ADJUSTED EBITDA
($ millions)
$1,712
$1,726
$1,749
ADJUSTED FREE CASH FLOW
($ millions)
ADJUSTED FREE CASH FLOW
PER SHARE
$558
$564
$489
$1.15
$1.01
$1.20
2010
2011
2012
2010
2011
2012
2010
2011
2012
All MW figures shown represent Calpine’s net ownership interest.
David C. Merritt (A)
President, BC Partners, Inc.
EXECUTIVE MANAGEMENT
Jack A. Fusco
Chief Executive Officer
John B. (Thad) Hill
President and Chief Operating Officer
GENERAL INFORMATION
Corporate Headquarters
Calpine Corporation
717 Texas Avenue, Suite 1000
Houston, Texas 77002
(713) 830-2000
www.calpine.com
Investor Relations
Calpine Corporation Investor Relations
(713) 830-8775
investor-relations@calpine.com
Independent Auditor
Pricewaterhouse Coopers LLP
Houston, Texas
Transfer Agent
Computershare, Inc.
P.O. Box 43078
Providence, RI 02940-3078
(877) 745-9351
Stock Information
Calpine Corporation’s common stock is listed on the
NYSE under the symbol CPN.
Executive Vice President, Chief Legal Officer and
W. Thaddeus Miller
Corporate Secretary
Zamir Rauf
Executive Vice President and Chief Financial Officer
Form 10-K
The Company’s Annual Report on Form 10-K for the year ended
December 31, 2012, as filed with the Securities and Exchange
Commission, is included in this report. Additional copies may
be obtained without charge by writing:
Calpine Corporation
Attn: Investor Relations
717 Texas Avenue, Suite 1000
Houston, Texas 77002
Annual Meeting
The Annual Meeting of Shareholders of Calpine Corporation
will be held on Friday, May 10, 2013, at 8 a.m. Central Time
at our corporate offices located at 717 Texas Ave., 10th floor,
Houston, TX 77002. All shareholders are cordially invited to attend.
Forward-Looking Statement
Certain statements made in this Annual Report by or on behalf
of the Company that are not historical facts are intended to be
forward-looking statements within the meaning of the safe harbor
provisions of the Private Securities Litigation Reform Act of 1995.
These statements are based on assumptions that the Company
believes are reasonable; however, many important factors, as
discussed under “Forward-Looking Statements” in the Company’s
Form 10-K for the year ended December 31, 2012, could cause
the Company’s results in the future to differ materially from the
forward-looking statements made herein and in any other documents
or oral presentations made by or on behalf of the Company.
Our clean, efficient, modern and flexible fleet is uniquely
positioned to benefit from these trends. In short, Calpine
is double-levered to economic recovery as our volume of
electricity produced rises and electricity prices increase due
to increasing demand and reductions in supply from retiring
coal, oil and nuclear units.
With these favorable secular trends as our backdrop, we
remain committed to further enhancing Calpine’s position as
a leader in the industry, with particular focus on the following
management priorities.
Premier Power Generation Company
2012 was a breakout year for Calpine – our combined-cycle
plant utilization rate (known as capacity factor) was 52%,
up nearly 23% over 2011 and the highest it has been in a
decade. Our fleet generated a record 116 billion kWh of
electricity, making us one of the nation’s largest suppliers
of wholesale electricity. Despite increased generation, we
decreased our major maintenance cost and held the line
on operating expenses, due in large part to our continued
focus on operational excellence and preventive maintenance,
which yielded our lowest ever fleetwide forced outage factor.
Our employees achieved these accomplishments while
continuing to demonstrate Calpine’s strong commitment
to workplace safety.
Improving Operations while Increasing Generation
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2008
2009
2010
2011
2012
Generation Forced Outage Factor
In 2012, Calpine produced approximately 116 billion kWh
of affordable, reliable electricity for our customers, making
us one of the nation’s largest suppliers of wholesale power.
Our pride in the Calpine team doesn’t stop at these on-the-job
feats. We kicked off an employee wellness initiative that has
already improved the lives of our employees and the commu-
nities in which we live and operate. Calpine’s community
involvement reached new heights last year, as we sponsored
86 cyclists in the MS150 race from Houston to Austin and 121
runners in the Houston Marathon and Half-Marathon. When
combined with our ongoing work with holiday drives, food
banks, Earth Day, Astro’s Community Leaders and other simi-
lar efforts throughout the company, these initiatives enabled us
to contribute more than $1 million to our communities in 2012.
Our thanks and congratulations go out to the entire Calpine
team for all of these achievements.
Fellow Shareholders,
Calpine continues to capitalize
on America’s shift toward
greater utilization of
cleaner and more affordable
power generated by modern,
efficient and flexible natural
gas-fired power plants.
This secular shift represents the culmination of a series of
transformational forces that have been driving the power
generation industry for a decade:
• America stands to benefit from an abundant and affordable
supply of clean-burning, domestic natural gas as a result
of technological advancements in drilling. Calpine’s power
plants are reliable and efficient and have a competitive
cost advantage in most markets. Meanwhile, nuclear and
coal-fired power plants are challenged in this sustained
low natural gas price environment.
• America’s electricity infrastructure is old and in need of
more than $1 trillion of new investment. Older coal- and
oil-fired power plants are facing retirement due to the
prohibitive cost of required environmental upgrades, as well
as the challenging economics of aging, inefficient plants.
• Permitting and siting issues are expensive and add signifi-
cant time to the power plant development cycle. This
effectively creates a barrier to entry for a number of years,
benefiting our existing portfolio as the economy recovers.
• Finally, as grid operators seek to integrate intermittent
renewable power from wind and solar – especially in
California – the flexibility of our existing power plants
should realize greater value by providing reliable,
dispatchable electricity.
Bosque Energy Center, Texas
Market Advocacy
Calpine is committed to advancing the principles of competitive
wholesale power markets. We advocate at the federal and
state levels for market-driven solutions in wholesale capacity
and energy markets that result in nondiscriminatory, transpar-
ent forward price signals in order to encourage economic
investment in affordable, flexible, clean and reliable electric
supply. During 2012, our advocacy efforts concentrated on:
• Preserving competitive organized markets that prevent
discrimination between new and existing generation and
create stable pricing signals that encourage necessary
investment
• Preventing the proliferation of subsidized generation and
instead allowing the markets (not administrators) to select
“winners”, and
• Leveling the playing field between generation resources
and demand response providers, who are currently subject
to less stringent performance requirements yet receive
similar compensation.
We have made progress on some fronts and while others
progress more slowly, there is momentum in the right
direction, and we are committed to being at the forefront
of advocacy on these issues in 2013.
Capital Allocation
We have committed to be good stewards of your capital.
Last year, Calpine built upon its track record of effective
capital allocation on all fronts, including asset monetization,
divestiture and acquisition, disciplined growth and share
repurchases. Along these lines, we:
• Divested at attractive prices two power plants in South
Carolina and Wisconsin for approximately $825 million,
resulting in a $222 million gain
• Acquired the 800 MW Bosque Energy Center in Texas
for $432 million, a significant discount to replacement cost
• Advanced the construction and development of five projects
totaling approximately 1,600 MW of efficient combined-cycle
capacity in California, Texas and Delaware, which we
expect to come online between 2013 and 2015
• Repurchased for $600 million approximately 7.25%
of our common stock (from November 2011 to January
2013), and
• Preserved Calpine’s financial flexibility and strength
by maintaining a healthy balance sheet, robust liquidity
(approximately $2.3 billion at the end of 2012) and
minimal near-term debt maturities.
We also announced that we are targeting Adjusted Free
Cash Flow Per Share growth of 15 – 20% compounded
annually. Our capital allocation decisions will be centered
around this goal.
Looking to 2013, our efforts will remain concentrated on
these three management priorities – continuously improving
the premier power generation company, advancing competi-
tive electricity markets and optimizing capital allocation –
which we believe are imperative to our success. We are
resolved to focus on what we do best, which is operating
natural gas-fired and geothermal power plants. In doing
so, we will be innovative, opportunistic and nimble, and we
will strive to maintain our competitive edge.
Thank you for your continued support of Calpine.
Sincerely,
Russell City Energy Center, California
J. Stuart Ryan
Chairman of the Board
Jack A. Fusco
Chief Executive Officer
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
____________________
Form 10-K
[X]
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2012
[ ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File No. 001-12079
______________________
Calpine Corporation
(A Delaware Corporation)
I.R.S. Employer Identification No. 77-0212977
717 Texas Avenue, Suite 1000, Houston, Texas 77002
Telephone: (713) 830-2000
Not Applicable
(Former Address)
Securities registered pursuant to Section 12(b) of the Act:
Calpine Corporation Common Stock, $0.001 Par Value
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [X] No [ ]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [ ] No [X]
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of
registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]
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]
Non-accelerated filer [ ]
(Do not check if a smaller reporting company)
Accelerated filer [ ]
Smaller reporting company [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes [ ] No [X]
State the aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2012, the last business day of the
registrant’s most recently completed second fiscal quarter: approximately $5,484 million.
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of
1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes [X] No [ ]
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: Calpine Corporation: 456,236,512
shares of common stock, par value $0.001, were outstanding as of February 11, 2013.
Portions of the documents listed below have been incorporated by reference into the indicated parts of this Report, as specified in the responses to
DOCUMENTS INCORPORATED BY REFERENCE
the item numbers involved.
Designated portions of the Proxy Statement relating to the 2013 Annual Meeting of Shareholders are incorporated by reference into Part III (Items
11, 12, 13, 14 and portions of Item 10)
CALPINE CORPORATION AND SUBSIDIARIES
FORM 10-K
ANNUAL REPORT
For the Year Ended December 31, 2012
TABLE OF CONTENTS
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
PART I
Business..............................................................................................................................................................
Risk Factors........................................................................................................................................................
Unresolved Staff Comments ..............................................................................................................................
Properties............................................................................................................................................................
Legal Proceedings ..............................................................................................................................................
Mine Safety Disclosures.....................................................................................................................................
PART II
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities ............................................................................................................................................................
Selected Financial Data ......................................................................................................................................
Management’s Discussion and Analysis of Financial Condition and Results of Operations.............................
Quantitative and Qualitative Disclosures about Market Risk ............................................................................
Financial Statements and Supplementary Data ..................................................................................................
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ............................
Controls and Procedures.....................................................................................................................................
Other Information...............................................................................................................................................
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
PART III
Directors, Executive Officers and Corporate Governance.................................................................................
Executive Compensation....................................................................................................................................
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters..........
Certain Relationships and Related Transactions, and Director Independence...................................................
Principal Accounting Fees and Services ............................................................................................................
Page
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PART IV
Item 15.
Exhibits, Financial Statement Schedule .............................................................................................................
Signatures .............................................................................................................................................................................
Power of Attorney ................................................................................................................................................................
Index to Consolidated Financial Statements ........................................................................................................................
97
105
106
107
i
DEFINITIONS
As used in 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
2017 First Lien Notes ...................... The $1.2 billion aggregate principal amount of 7.25% senior secured notes due 2017,
issued October 21, 2009, of which 10% of the aggregate principal amount was redeemed
on November 7, 2012 in connection with the issuance of the 2019 First Lien Term Loan
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 Notes ...................... The $400 million aggregate principal amount of 8.0% senior secured notes due 2019,
issued May 25, 2010, of which 10% of the aggregate principal amount was redeemed on
November 7, 2012 in connection with the issuance of the 2019 First Lien Term Loan
2019 First Lien Term Loan.............. The $835 million first lien senior secured term loan, dated October 9, 2012, among Calpine
Corporation, as borrower, and the lenders party hereto, and Morgan Stanley Senior
Funding, Inc., as administrative agent and Goldman Sachs Credit Partners L.P., as
collateral agent
2020 First Lien Notes ...................... The $1.1 billion aggregate principal amount of 7.875% senior secured notes due 2020,
issued July 23, 2010, of which 10% of the aggregate principal amount was redeemed on
November 7, 2012 in connection with the issuance of the 2019 First Lien Term Loan
2021 First Lien Notes ...................... The $2.0 billion aggregate principal amount of 7.50% senior secured notes due 2021,
issued October 22, 2010, of which 10% of the aggregate principal amount was redeemed
on November 7, 2012 in connection with the issuance of the 2019 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, of which 10% of the aggregate principal amount was redeemed
on November 7, 2012 in connection with the issuance of the 2019 First Lien Term Loan
AB 32............................................... California Assembly Bill 32
Adjusted EBITDA ........................... EBITDA as adjusted for the effects of (a) impairment charges, (b) major maintenance
expense, (c) operating lease expense, (d) unrealized gains or losses on commodity
derivative mark-to-market activity, (e) adjustments to reflect only the Adjusted EBITDA
from our unconsolidated investments, (f) stock-based compensation expense, (g) gains or
losses on sales, dispositions or retirements of assets, (h) non-cash gains and losses from
foreign currency translations, (i) gains or losses on the repurchase or extinguishment of
debt, (j) Conectiv Acquisition-related costs, (k) Adjusted EBITDA from our discontinued
operations and (l) 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 generation as a percent of total potential 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
Bankruptcy Code ............................. U.S. Bankruptcy Code
Bcf ................................................... Billion cubic feet
ii
ABBREVIATION
DEFINITION
Blue Spruce ..................................... Blue Spruce Energy Center, LLC, formerly an indirect, wholly-owned subsidiary of
Calpine that owned Blue Spruce Energy Center, a 310 MW natural gas-fired, peaking
power plant located in Aurora, Colorado, which was sold on December 6, 2010
Broad River ..................................... Broad River Energy LLC, formerly an indirect, wholly-owned subsidiary of Calpine that
leases the Broad River Energy Center, an 847 MW natural gas-fired, peaking power plant
located in Gaffney, South Carolina, from the BR Owner Lessors
Broad River Entities ........................ Collectively, Broad River and the BR Owner Lessors
BR Owner Lessors........................... Broad River OL-1, LLC, a Delaware limited liability company, Broad River OL-2, LLC,
a Delaware limited liability company, Broad River OL-3, LLC, a Delaware limited liability
company, and Broad River OL-4, LLC, a Delaware limited liability company, each of
which is an indirect, wholly-owned subsidiary of Calpine, which lease the Broad River
Energy Center (i) from Cherokee County, South Carolina and (ii) to Broad River
Btu ................................................... British thermal unit(s), a measure of heat content
CAA................................................. Federal Clean Air Act, U.S. Code Title 42, Chapter 85
CAIR................................................ Clean Air Interstate Rule
CAISO ............................................. California Independent System Operator
Calpine BRSP.................................. Calpine BRSP, LLC
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
CARB .............................................. California Air Resources Board
CCFC............................................... Calpine Construction Finance Company, L.P., an indirect, wholly-owned subsidiary of
CCFC Finance ................................. CCFC Finance Corp.
Calpine
CCFC Guarantors ............................ Hermiston Power LLC and Brazos Valley Energy LLC, wholly-owned subsidiaries of
CCFC
CCFC Notes..................................... The $1.0 billion aggregate principal amount of 8.0% Senior Secured Notes due 2016
issued May 19, 2009, by CCFC and CCFC Finance
CDHI ............................................... Calpine Development Holdings, Inc., an indirect, wholly-owned subsidiary of Calpine
CEHC .............................................. Conectiv Energy Holding Company, LLC, a wholly-owned subsidiary of Conectiv
CES.................................................. Calpine Energy Services, L.P.
iii
ABBREVIATION
DEFINITION
CFTC ............................................... U.S. Commodities Futures Trading Commission
Chapter 11........................................ Chapter 11 of the U.S. Bankruptcy Code
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, RGGI compliance and other environmental costs and
realized settlements from our marketing, hedging and optimization activities including
natural gas transactions hedging future power sales, but excludes the unrealized portion
of 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, RGGI compliance and other environmental costs, and realized
settlements from our marketing, hedging and optimization activities including natural gas
transactions hedging future power sales, but excludes the unrealized portion of 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 and
optimization activities, but excludes the unrealized portion of our mark-to-market activity
Company.......................................... Calpine Corporation, a Delaware corporation, and its subsidiaries
Conectiv........................................... Conectiv, LLC, a wholly-owned subsidiary of PHI
Conectiv Acquisition ....................... The acquisition of all of the membership interests in CEHC pursuant to the Conectiv
Purchase Agreement on July 1, 2010, whereby we acquired all of the power generation
assets of Conectiv from PHI, which included 18 operating power plants and York Energy
Center that was under construction and achieved COD on March 2, 2011, with 4,491 MW
of capacity
Conectiv Purchase Agreement......... Purchase Agreement by and among PHI, Conectiv, CEHC and NDH dated as of April 20,
2010
Corporate Revolving Facility .......... The $1.0 billion aggregate amount revolving credit facility credit agreement, dated as of
December 10, 2010, 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
Creed................................................ Creed Energy Center, LLC
Director Plan.................................... The Amended and Restated Calpine Corporation 2008 Director Incentive Plan
Dodd-Frank Act............................... The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
EBITDA........................................... Net income (loss) attributable to Calpine before net (income) loss attributable to the
noncontrolling interest, interest, taxes, depreciation and amortization
Effective Date..................................
January 31, 2008, the date on which the conditions precedent enumerated in the Plan of
Reorganization were satisfied or waived and the Plan of Reorganization became effective
iv
ABBREVIATION
DEFINITION
EIA................................................... Energy Information Administration of the U.S. Department of Energy
EPA.................................................. U.S. Environmental Protection Agency
Equity Plan ...................................... The Amended and Restated Calpine Corporation 2008 Equity Incentive Plan
ERCOT ............................................ Electric Reliability Council of Texas
EWG(s)............................................ Exempt wholesale generator(s)
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 Credit Facility ................. Credit Agreement, dated as of January 31, 2008, as amended by the First Amendment to
Credit Agreement and Second Amendment to Collateral Agency and Intercreditor
Agreement, dated as of August 20, 2009, among Calpine Corporation, as borrower, certain
subsidiaries of the Company named therein, as guarantors, the lenders party thereto,
Goldman Sachs Credit Partners L.P., as administrative agent and collateral agent, and the
other agents named therein
First Lien Notes ............................... Collectively, the 2017 First Lien Notes, the 2019 First Lien Notes, the 2020 First Lien
Notes, the 2021 First Lien Notes and the 2023 First Lien Notes
First Lien Term Loans ..................... Collectively, the 2018 First Lien Term Loans and the 2019 First Lien Term Loan
FRCC............................................... Florida Reliability Coordinating Council
Freestone.......................................... Freestone Energy Center, a 994 MW natural gas-fired, combined-cycle power plant located
near Fairfield, Texas
GE.................................................... General Electric International, Inc.
GEC ................................................. Collectively, Gilroy Energy Center, LLC, Creed and Goose Haven
Geysers Assets................................. Our geothermal power plant assets, including our steam extraction and gathering assets,
located in northern California consisting of 15 operating power plants and one plant not
in operation
GHG(s) ............................................ Greenhouse gas(es), primarily carbon dioxide (CO2), and including methane (CH4),
nitrous oxide (N2O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs) and
perfluorocarbons (PFCs)
Goose Haven ................................... Goose Haven Energy Center, LLC
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
v
ABBREVIATION
DEFINITION
Hg .................................................... Mercury
IOUs ................................................
Investor Owned Utilities
IRC ..................................................
Internal Revenue Code
IRS................................................... U.S. Internal Revenue Service
ISO(s) ..............................................
Independent System Operator(s)
ISO-NE ............................................
ISO New England
ISRA ................................................
Industrial Site Recovery Act
KIAC ............................................... KIAC Partners, an indirect, wholly-owned subsidiary of Calpine that leases our Kennedy
International Airport Power Plant, a 121 MW natural gas-fired, combined-cycle power
plant located at John F. Kennedy International Airport in New York
KWh ................................................ Kilowatt hour(s), a measure of power produced, purchased or sold
LIBOR ............................................. London Inter-Bank Offered Rate
Los Esteros Project Debt ................. Credit Agreement dated August 23, 2011, between Los Esteros Critical Energy Facility,
LLC, as borrower, and the lenders named therein
LTSA(s)........................................... Long-Term Service Agreement(s)
Market Heat Rate(s) ........................ The regional power price divided by the corresponding regional natural gas price
MISO ............................................... Midwest ISO
MMBtu ............................................ Million Btu
MRO ................................................ Midwest Reliability Organization
MW.................................................. Megawatt(s), a measure of plant capacity
MWh................................................ Megawatt hour(s), a measure of power produced, purchased or sold
NAAQS ........................................... National Ambient Air Quality Standards
NDH ................................................ New Development Holdings, LLC, an indirect, wholly-owned subsidiary
NDH Project Debt ........................... The $1.3 billion senior secured term loan facility and the $100 million revolving credit
facility issued on July 1, 2010, under the credit agreement, dated as of June 8, 2010, among
NDH, as borrower, Credit Suisse AG, as administrative agent, collateral agent, issuing
bank and syndication agent, Credit Suisse Securities (USA) LLC, Citigroup Global
Markets Inc. and Deutsche Bank Securities Inc., as joint book-runners and joint lead
arrangers, Credit Suisse AG, Citibank, N.A., and Deutsche Bank Trust Company
Americas, as co-documentation agents and the lenders party thereto repaid on March 9,
2011
NERC .............................................. North American Electric Reliability Council
NOL(s)............................................. Net operating loss(es)
NOX ............................................................. Nitrogen oxides
NPCC............................................... Northeast Power Coordinating Council
NYISO............................................. New York ISO
vi
ABBREVIATION
DEFINITION
NYMEX .......................................... New York Mercantile Exchange
NYSE............................................... New York Stock Exchange
OCI .................................................. Other Comprehensive Income
OMEC.............................................. Otay Mesa Energy Center, LLC, an indirect, wholly-owned subsidiary that owns the Otay
Mesa Energy Center, a 608 MW natural gas-fired, combined-cycle power plant located
in San Diego county, California
OTC ................................................. Over-the-Counter
PG&E .............................................. Pacific Gas & Electric Company
PHI................................................... Pepco Holdings, Inc.
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
Plan of Reorganization .................... Sixth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the Bankruptcy
Code filed by the U.S. Debtors with the U.S. Bankruptcy Court on December 19, 2007,
as amended, modified or supplemented
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
PUHCA 2005................................... U.S. Public Utility Holding Company Act of 2005
PURPA............................................. U.S. Public Utility Regulatory Policies Act of 1978
QF(s)................................................ Qualifying facility(ies), which are cogeneration facilities and certain small power
production facilities eligible to be “qualifying facilities” under PURPA, provided that they
meet certain power and thermal energy production requirements and efficiency standards.
QF status provides an exemption from the books and records requirement of PUHCA 2005
and grants certain other benefits to the QF
REC(s) ............................................. Renewable energy credit(s)
Report .............................................. This Annual Report on Form 10-K for the year ended December 31, 2012, filed with the
SEC on February 12, 2013
Reserve margin(s)............................ The measure of how much the total generating capacity installed in a region exceeds the
peak demand for power in that region
RFC.................................................. Reliability First Corporation
RGGI ............................................... Regional Greenhouse Gas Initiative
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
vii
ABBREVIATION
DEFINITION
RMR Contract(s) ............................. Reliability Must Run contract(s)
Rocky Mountain .............................. Rocky Mountain Energy Center, LLC, formerly an indirect, wholly-owned subsidiary of
Calpine that owned Rocky Mountain Energy Center, a 621 MW natural gas-fired,
combined-cycle power plant located in Keenesburg, Colorado, which was sold on
December 6, 2010
RPS .................................................. Renewable Portfolio Standards
RTO(s)............................................. Regional Transmission Organization(s)
Russell City Project Debt ................ Credit Agreement dated June 24, 2011, between Russell City Energy Company, LLC, as
borrower, and the lenders named therein
SEC.................................................. U.S. Securities and Exchange Commission
Securities Act................................... U.S. Securities Act of 1933, as amended
SERC ............................................... Southeastern Electric Reliability Council
SO2 ............................................................... Sulfur dioxide
South Point ...................................... South Point Energy Center, a 530 MW natural gas-fired, combined-cycle power plant
located in Mohave Valley, Arizona
Spark Spread(s) ............................... The difference between the sales price of power per MWh and the cost of fuel to produce
it
SPP................................................... Southwest Power Pool
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
TCEQ............................................... Texas Commission on Environmental Quality
TRE.................................................. Texas Reliability Entity, Inc.
U.S. Bankruptcy Court .................... U.S. Bankruptcy Court for the Southern District of New York
U.S. Debtor(s).................................. Calpine Corporation and each of its subsidiaries and affiliates that filed voluntary petitions
for reorganization under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court,
which matter was jointly administered in the U.S. Bankruptcy Court under the caption In
re Calpine Corporation, et al., Case No. 05-60200 (BRL) and was dismissed on December
19, 2011
U.S. GAAP ...................................... Generally accepted accounting principles in the U.S.
VAR................................................. Value-at-risk
VIE(s) .............................................. Variable interest entity(ies)
WECC.............................................. Western Electricity Coordinating Council
Whitby ............................................. Whitby Cogeneration Limited Partnership, a 50% partnership interest between certain of
our subsidiaries and a third party which operates the Whitby 50 MW natural gas-fired,
simple-cycle cogeneration power plant located in Ontario, Canada
viii
ABBREVIATION
DEFINITION
WP&L.............................................. Wisconsin Power & Light Company
York Energy Center.........................
565 MW dual fuel, combined-cycle generation power plant (formerly known as the Delta
Project) located in Peach Bottom Township, Pennsylvania which achieved COD on March
2, 2011
ix
Forward-Looking Statements
In addition to historical information, 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, 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 to hedge risks;
• Laws, regulation 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 and to comply with covenants under our First Lien Notes, Corporate
Revolving Facility, First Lien Term Loans, CCFC Notes 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 wastewater 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;
• The unknown future impact on our business from the Dodd-Frank Act and the rules to be promulgated thereunder;
• Competition, including risks associated with marketing and selling power in the evolving energy markets;
• 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 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; and
• Other risks identified in this Report.
Given the risks and uncertainties surrounding forward-looking statements, you should not place undue reliance on these
statements. Many of these factors are beyond our ability to control or predict. Our forward-looking statements speak only as of
the date of this Report. Other than as required by law, we undertake no obligation to update or revise forward-looking statements,
whether as a result of new information, future events, or otherwise.
Where You Can Find Other Information
Our website is www.calpine.com. Information contained on our website is not part of this Report. Information that we
furnish or file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on
Form 8-K and any amendments to or exhibits included in these reports are available for download, free of charge, on our website
soon after such reports are filed with or furnished with 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
1
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.
2
PART I
Item 1. Business
BUSINESS AND STRATEGY
Business
We are a premier wholesale power producer with operations throughout the U.S. We measure our success by delivering
long-term shareholder value. We accomplish this through our focus on operational excellence, effectively executing our hedging
strategy, our customer origination program and completing our growth capital projects on schedule and on budget. 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, Texas and the Mid-Atlantic region of the U.S. Since our inception in 1984, we have been a leader in environmental
stewardship. We have invested in clean power generation to become a recognized leader in developing, constructing, owning and
operating an environmentally responsible portfolio of power plants. Our portfolio is primarily comprised of two types of power
generation technologies: natural gas-fired combustion turbines, which are primarily efficient combined-cycle plants, and renewable
geothermal conventional steam turbines. We are among the world’s largest owners and operators of industrial gas turbines as well
as cogeneration power plants. Our Geysers Assets located in northern California represent the largest geothermal power generation
portfolio in the U.S. and produced approximately 18% of all renewable energy in the state of California during 2011. 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 natural gas and fuel oil as fuel for our power plants and engage in related natural gas transportation
and storage transactions. We also purchase electric transmission rights to deliver power to our customers. Additionally, consistent
with our Risk Management Policy, we enter into natural gas and power physical and financial contracts to hedge certain business
risks and optimize our portfolio of power plants.
Our portfolio, including partnership interests, consists of 92 power plants, including 4 under construction (1 new power
plant and 3 expansions of existing power plants), located throughout 20 states in the U.S. and Canada, with an aggregate generation
capacity of 27,321 MW and 1,163 MW under construction. Our fleet, including projects under construction, consists of 74
combustion turbine-based plants, 2 fossil steam-based plants, 15 geothermal turbine-based plants and 1 photovoltaic solar plant.
In 2012, our fleet of power plants produced approximately 116 billion KWh of electric power for our customers. In addition, we
are one of the largest consumers of natural gas in North America. In 2012, we consumed 867 Bcf or approximately 9% of the total
estimated natural gas consumed for power generation in the U.S. We believe that having scale and geographic diversity is important
in our business. Scale provides us the opportunity to have meaningful regulatory input, an ability to leverage our procurement
efforts for better pricing, terms and conditions on our goods and services, and allows us to develop and offer a wide array of
products and services to our customers. Geographic diversity helps us manage weather, regulatory and regional economic
differences across our markets.
The environmental profile of our power plants reflects our commitment to environmental leadership and stewardship.
We have invested the necessary capital to develop a power generation portfolio that has substantially lower air pollutant emissions
compared to our competitors’ power plants using other fossil fuels, such as coal. In addition, we strive to preserve our nation’s
valuable water and land resources. To condense steam, our combined-cycle power plants use cooling towers with a closed water
cooling system or air cooled condensers and do not employ “once-through” water cooling, which uses large quantities of water
from adjacent waterways, negatively impacting aquatic life. Since our plants are modern and efficient and utilize clean burning
natural gas, we do not require large areas of land for our power plants nor do we require large specialized landfills for the disposal
of coal ash or nuclear plant waste. We believe that we will be less adversely impacted by Cap-and-trade limits, carbon taxes or
required environmental upgrades as a result of future potential regulation or legislation addressing GHG, other air pollutant
emissions such as mercury, as well as water use or emissions, compared to our competitors who use other fossil fuels or older,
less efficient technologies.
Our principal offices are located in Houston, Texas with regional offices in Dublin, California and Wilmington, Delaware,
an engineering, construction and maintenance services office in Pasadena, Texas and government affairs offices in Washington
D.C., Sacramento, California and Austin, Texas. We operate our business through a variety of divisions, subsidiaries and affiliates.
Strategy
Our goal is to be recognized as the premier wholesale power company in the U.S. as measured by our employees,
shareholders, customers and regulators as well as the communities in which our facilities are located. We seek to achieve sustainable
3
growth through financially disciplined power plant development, construction, acquisition, operation and ownership. Our strategy
to achieve this is reflected in the four major initiatives described below:
1. Focus on Becoming the Premier Operating Company — Our objective is to be the “best-in-class” in regards to certain
operational performance metrics, such as safety, availability, reliability, efficiency and cost management.
• We produced approximately 116 billion KWh of electricity in 2012, 23% more than the same period in 2011 (includes
generation from power plants owned but not operated by us and our share of generation from our unconsolidated
power plants).
• Our entire fleet achieved a forced outage factor of 1.6% in 2012, our lowest on record and an improvement of 36%
from 2011.
• Our entire fleet achieved an impressive starting reliability of 98.3% in 2012.
• During 2012, our outage services subsidiary completed 11 major inspections and 19 hot gas path inspections.
•
For the past twelve consecutive years, our Geysers Assets have reliably generated approximately 6 million MWh
per year and, in 2012, achieved an exceptional availability factor of approximately 97%.
2. Focus on Enhancing Shareholder Value — We continue to make significant progress to deliver financially disciplined
growth, to enhance shareholder value through our capital allocation and share repurchases and to set the foundation for
continued growth and success. Given our strong cash flow from operations, we are committed to remaining financially
disciplined in our capital allocation decisions. The year ended December 31, 2012 was marked by the following
accomplishments:
• As of the filing of this Report, we have completed our previously announced $600 million share repurchase program,
having repurchased a total of 35,568,833 shares of our outstanding common stock at an average price paid of $16.87
per share. In February 2013, our Board of Directors authorized the repurchase of an additional $400 million in shares
of our common stock, bringing the cumulative authorization total to $1.0 billion.
• During the first quarter of 2012, we terminated our legacy interest rate swaps formerly hedging our First Lien Credit
Facility for a payment of approximately $156 million which eliminated our exposure from these instruments to
further declines in interest rates.
• On October 9, 2012, we issued our 2019 First Lien Term Loan and used the proceeds to reduce our overall cost of
debt and simplify our capital structure by redeeming a portion of our First Lien Notes and repaying project debt.
• On November 7, 2012, we completed the purchase of a modern, natural gas-fired, combined-cycle power plant with
a nameplate capacity of 800 MW located in Bosque County, Texas for approximately $432 million which increased
capacity in our Texas segment.
• On December 27, 2012, we, through our indirect, wholly-owned subsidiary Calpine Power Company, completed the
sale of 100% of our ownership interest in each of the Broad River Entities for approximately $423 million. This
transaction resulted in the disposition of our Broad River power plant, an 847 MW natural gas-fired, peaking power
plant located in Gaffney, South Carolina, and includes a five year consulting agreement with the buyer. We expect
to use the sale proceeds for our capital allocation activities and for general corporate purposes.
• On December 31, 2012, we completed the sale of Riverside Energy Center, LLC to WP&L for approximately $402
million. We expect to use the sale proceeds for our capital allocation activities and for general corporate purposes.
3. Focus on Leveraging our Three Scale Regions — Our goal is to continue to grow our generation presence in core markets
with an emphasis on 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 will
actively seek divestiture opportunities on our non-core assets if those opportunities meet our financial expectations. 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, organic
growth initiatives and modernization activities are discussed below.
West:
• Russell City Energy Center — Construction at our Russell City Energy Center continues to move forward. Upon
completion, this project will bring on line approximately 429 MW of net interest baseload capacity (464 MW with
peaking capacity) representing our 75% share. Construction is ongoing and COD is expected in the summer of 2013.
Upon completion, the Russell City Energy Center is contracted to deliver its full output to PG&E under a ten-year
PPA.
4
•
Los Esteros Critical Energy Facility — During 2009, we and PG&E negotiated a new PPA to replace the existing
California Department of Water Resources contract and facilitate the modernization of our Los Esteros Critical
Energy Facility from a 188 MW simple-cycle generation power plant to a 309 MW combined-cycle generation power
plant, which will also increase the efficiency and environmental performance of the power plant by lowering the
Heat Rate. Construction is ongoing and COD is expected in the summer of 2013.
Texas:
• Channel and Deer Park Expansions — In September and November 2011, we filed air permit applications with the
TCEQ and the EPA to expand the baseload capacity of the Deer Park and Channel Energy Centers by approximately
260 MW each. We received air permit approvals from the TCEQ for our Deer Park and Channel expansion projects
in September and October 2012, respectively, and from the EPA in November 2012. Construction on these expansion
projects commenced in the fourth quarter of 2012. We expect COD during the summer of 2014 for these expansions
and are currently evaluating funding sources including, but not limited to, nonrecourse financing, corporate financing
or internally generated funds.
North:
• Garrison Energy Center — We are actively permitting 618 MW of new combined-cycle capacity at a development
site secured by a long-term lease with the City of Dover. For the first phase (309 MW), we have executed the
Interconnection Services Agreement and the Interconnection Construction Services Agreement with PJM. For the
second phase (309 MW), we have completed a feasibility study and are currently conducting a system impact study.
Environmental permitting, site development planning and development engineering are underway and the first phase’s
capacity cleared PJM’s 2015/2016 base residual auction. We received the air permit and executed a preliminary
notice to proceed for the engineering, procurement and construction agreement during the first quarter of 2013. We
expect COD for the first phase by the summer of 2015 and are currently evaluating funding sources including, but
not limited to, nonrecourse financing, corporate financing or internally generated funds.
All Segments:
•
Turbine Modernization — We continue to move forward with our turbine modernization program. Through December
31, 2012, we have completed the upgrade of eleven Siemens and eight GE turbines totaling over 200 MW and have
committed to upgrade approximately three additional turbines.
4. Focus on Customer-Oriented Origination Business — We continue to focus on providing products and services that are
beneficial to our customers. A summary of certain significant contracts entered into or approved in 2012 is as follows:
• We entered into a new twenty-year PPA with Western Farmers Electric Cooperative to provide 160 MW of power
generated by our Oneta Energy Center, commencing in June 2014. The capacity under contract will increase in
increments, up to a maximum of 280 MW in years 2019 through 2035.
• We entered into a new five-year PPA with Southwestern Public Service Company, a subsidiary of Xcel Energy, to
provide an additional 200 MW of power generated by our Oneta Energy Center commencing on June 1, 2014.
• We entered into a new five-year resource adequacy contract with PG&E for approximately 280 MW of combined
heat and power capacity from our Los Medanos Energy Center commencing in the summer 2013.
• We entered into a new seven-year resource adequacy contract with Southern California Edison Company (“SCE”)
for approximately 280 MW of combined heat and power capacity from our Los Medanos Energy Center and a new
five-year resource adequacy contract with SCE for approximately 120 MW of combined heat and power capacity
from our Gilroy Cogeneration Plant, both commencing in January 2014.
• We amended an existing PPA with Dow Chemical Company for an incremental energy sale of up to approximately
158,000 MWh per year of energy from our Los Medanos Energy Center which runs through February 2025.
• We entered into a new fifteen-year PPA with American Electric Power Service Corporation, as agent for Public
Service Company of Oklahoma, to provide 260 MW of energy, capacity and ancillary services from our Oneta Energy
Center commencing in June 2016.
• We entered into a new ten-year PPA with the Tennessee Valley Authority to provide the full output of power generated
by our Decatur Energy Center, a natural gas-fired, combined-cycle power plant that can generate up to 795 MW,
commencing in January 2013.
5
THE MARKET FOR POWER
Our Power Markets and Market Fundamentals
The power industry represents one of the largest industries in the U.S. and impacts nearly every aspect of our economy,
with an estimated end-user market of approximately $364 billion in power sales in 2012 according to the EIA. Historically,
vertically integrated power utilities with monopolies over franchised territories dominated the power generation industry in the
U.S. Over the last 25 years, industry trends and regulatory initiatives, culminating with the deregulation trend of the late 1990’s
and early 2000’s, provided opportunities for wholesale power producers to compete to provide power. Although different regions
of the country have very different models and rules for competition, the markets in which we operate have some form of wholesale
market competition. California (included in our West segment), Texas and the Mid-Atlantic (included in our North segment),
which are the markets in which we have our largest presence, have emerged as among the most competitive wholesale power
markets in the U.S. We also operate, to a lesser extent, in the competitive ISO-NE, NYISO and MISO markets. We produce several
products for sale to our customers.
•
•
•
•
•
First, we are a wholesale provider of power to utilities, independent electric system operators, industrial or agricultural
companies, retail power providers, municipalities, and power marketers. Our power sales occur in several different
product categories including baseload (around the clock generation), intermediate (generation typically more
expensive than baseload and utilized during higher demand periods to meet shifting demand needs), and peaking
capacity (most expensive variable cost and utilized during the highest demand periods), for which the latter is provided
by some of our stand-alone peaking power plants/units and from our combined-cycle power plants by using
technologies such as steam injection or duct firing additional burners in the heat recovery steam generators. Many
of our units have operated more frequently as baseload units at times when low natural gas prices have driven their
production costs below those of some competing coal-fired units.
Second, we provide capacity for sale to retail power providers. In various markets, retail power providers are required
to demonstrate adequate resources to meet their power sales commitments. To meet this obligation, they procure a
market product known as capacity from power plant owners or resellers. Most electricity market administrators have
acknowledged that an energy only market does not provide sufficient revenues to enable existing merchant generators
to recover all of their costs or to encourage the construction of new power plants. Capacity auctions have been
implemented in the northeast, the Mid-Atlantic and some midwest regional markets to address this issue. California
has a bilateral capacity program. Texas does not presently have a capacity market, nor a requirement for retailers to
ensure adequate resources.
Third, we sell RECs from our Geysers Assets in northern California, as well as from our small solar power plant in
New Jersey. California has an RPS that requires load serving entities to have RECs for a certain percentage of their
demand for the purpose of guaranteeing a certain level of renewable generation in the state. Because geothermal is
a renewable source of energy, we receive a REC for each MWh we produce and are able to sell our RECs to load
serving entities. New Jersey has a solar specific RPS which enables us to sell RECs from our Vineland Solar Energy
Center.
Fourth, our cogeneration power plants produce steam for sale to customers for use in industrial or heating, ventilation
and air conditioning operations.
Fifth, we provide ancillary service products to wholesale power markets. These products include the right for the
purchaser to call on our generation to provide flexibility to the market and support operation of the electric grid. As
an example, we are sometimes paid to reserve a portion of capacity at some of our power plants that could be deployed
quickly should there be an unexpected increase in load or to assure reliability due to fluctuations in the supply of
power from variable renewable resources such as wind and solar generation. These ramping characteristics are
becoming increasingly necessary in markets where intermittent renewables have large penetrations.
In addition to the five products above, we are buyers and sellers of environmental allowances and credits, including those
under RGGI, the federal Acid Rain and CAIR programs and emission reduction credits under the federal Nonattainment New
Source Review program. We also participate in CO2 emissions credit markets related to California’s AB 32 GHG reduction program.
Although all of the products mentioned above contribute to our financial performance and are the primary components
of our Commodity Margin, the most important is our sale of wholesale power. We utilize long-term customer contracts for our
power and steam sales where possible. For power that is not sold under customer contracts, we use our hedging program throughout
the markets in which we participate.
6
For sales of power from our natural gas-fired fleet into the short-term or spot markets, we attempt to maximize our
operations when the market Spark Spread is positive. Assuming economic behavior by market participants, generating units
generally are dispatched in order of their variable costs, with lower cost units being dispatched first and units with higher costs
dispatched as demand, or “load,” grows beyond the capacity of the lower cost units. For this reason, in a competitive market, the
price of power typically is related to the variable operating costs of the marginal generator, which is the last unit to be dispatched
in order to meet demand. The market factors that most significantly impact our operations are reserve margins, the price and supply
of natural gas and competing fuels such as coal and oil, weather patterns and natural events, our operating Heat Rate, availability
factors, and regulatory and environmental pressures as further discussed below.
Reserve Margins
Reserve margin, a measure of excess generation capacity in a market, is a key indicator of the competitive conditions in
the markets in which we operate. For example, a reserve margin of 15% indicates that supply is 115% of expected peak power
demand under normal weather conditions. Holding other factors constant, lower reserve margins typically lead to higher power
prices because the less efficient capacity in the region is needed more often to satisfy power demand or voluntary or involuntary
load shedding measures are taken. Markets with tight demand and supply conditions often display price spikes and improved
bilateral contracting opportunities. Typically, the market price impact of reserve margins, as well as other supply/demand factors,
is reflected in the Market Heat Rate, calculated as the local market power price divided by the local natural gas price.
During the last decade, the supply and demand fundamentals in many regional markets have been negatively impacted
by the combination of new generation coming on line and a general decline in weather normalized load growth rates due to the
economic recession. Although uncertainty exists and there are key regional differences at a macro level, continued economic
recovery and thus, corresponding load recovery, with the lack of broad new power plant investments in our key markets should
lead to lower reserve margins and higher Market Heat Rates. Reserve margins by NERC regional assessment area for each of our
segments are listed below:
West:
WECC.............................................................................................................................................................
Texas:
TRE.................................................................................................................................................................
North:
NPCC..............................................................................................................................................................
MISO ..............................................................................................................................................................
PJM .................................................................................................................................................................
Southeast:
SERC ..............................................................................................................................................................
SPP..................................................................................................................................................................
FRCC ..............................................................................................................................................................
(1)
2012
19.7%
13.5%
21.5%
28.7%
30.6%
32.2%
22.7%
27.8%
___________
(1) Data source is NERC weather-normalized estimates for 2012
The Price and Supply of Natural Gas
Approximately 95% of our generating capability’s fuel requirements are met with natural gas. We have approximately
725 MW of baseload capacity from our Geysers Assets and our expectation is that the steam reservoir at our Geysers Assets will
be able to supply economic quantities of steam for the foreseeable future as our steam flow decline rates have become very small
over the past several years. We also have approximately 596 MW of capacity from power plants where we purchase fuel oil to
meet these generation requirements, but do not expect fuel oil requirements to be material to our portfolio of power plant assets.
Additionally, we have 4 MW of capacity from solar power generation technology with no fuel requirement.
We procure natural gas from multiple suppliers and transportation and storage sources. Although availability is generally
not an issue, localized shortages (especially in extreme weather conditions in and around the population centers), transportation
availability and supplier financial stability issues can and do occur.
Lower gas prices over the past four years have had a significant impact on power markets. Beginning in 2009, there was
a significant decrease in NYMEX Henry Hub natural gas prices from a range of $6/MMBtu — $13/MMBtu during 2008 to an
7
average natural gas price of $4.38/MMBtu, $4.03/MMBtu, and $2.83/MMBtu during 2010, 2011 and 2012, respectively. Natural
gas prices in some parts of the country for parts of 2010, 2011 and 2012 were low enough that modern, combined-cycle, natural
gas-fired generation became less expensive on a marginal basis than coal-fired generation. The result was that natural gas displaced
coal as a less expensive generation resource resulting in what the industry describes as coal-to-gas switching, the effects of which
can be seen in our increased generation volumes in 2012.
The availability of non-conventional natural gas supplies, in particular shale natural gas, has been the primary driver of
reduced natural gas prices in the last few years. Access to significant deposits of shale natural gas has altered the natural gas supply
landscape in the U.S. and could have a longer-term and profound impact on both the outright price of natural gas and the historical
regional natural gas price relationships (basis differentials). The U.S. Department of Energy estimates that shale natural gas
production has the potential of 3 trillion to 4 trillion cubic feet per year and may be sustainable for decades with enough natural
gas to supply the U.S. for the next 90 years. Accordingly, there is an emerging view that lower priced natural gas will be available
for the medium to long-term future.
The price of natural gas, economic growth and environmental regulations affect our Commodity Margin and liquidity.
The impact of changes in natural gas prices differs according to the time horizon and regional market conditions and depends on
our hedge levels and other factors discussed below.
Much of our generating capacity is located in California (included in our West segment), Texas and the Mid-Atlantic
(included in our North segment) where natural gas-fired units set power prices during many hours. When natural gas is the price-
setting fuel, increases in natural gas prices may increase our unhedged Commodity Margin because our combined-cycle power
plants in those markets are more fuel-efficient than conventional natural gas-fired technologies and peaking power plants.
Conversely, decreases in natural gas prices may decrease our unhedged Commodity Margin. In these instances, our cost of
production advantage relative to less efficient natural gas-fired generation is diminished on an absolute basis.
In 2012, given very low natural gas prices, natural gas-fired, combined-cycle units in many markets were frequently
cheaper to dispatch than coal-fired power plants. When coal-fired electricity production costs exceed natural gas-fired production
costs, coal-fired units tend to set power prices. In these hours, lower natural gas prices tend to increase our Commodity Margin,
since our production costs fall while power prices remain constant (depending on our hedge levels and holding other factors
constant).
Where we operate under long-term contracts, changes in natural gas prices can have a neutral impact on us in the short-
term. This tends to be the case where we have entered into tolling agreements under which the customer provides the natural gas
and we convert it to power for a fee, or where we enter into indexed-based agreements with a contractual Heat Rate at or near our
actual Heat Rate for a monthly payment.
Changes in natural gas prices or power prices may also affect our liquidity. During periods of high or volatile natural gas
prices, we could be required to post additional cash collateral or letters of credit.
Despite these short-term dynamics, over the long-term, we expect lower natural gas prices to encourage new combined-
cycle gas turbine power plant investment, thus enhancing the competitiveness of our modern, natural gas-fired fleet by making
investment in other technologies such as coal, nuclear, or renewables less economic.
Weather Patterns and Natural Events
Weather generally has a significant short-term impact on supply and demand for power and natural gas. Historically,
demand for and the price of power is higher in the summer and winter seasons when temperatures are more extreme, and therefore,
our unhedged revenues and Commodity Margin could be negatively impacted by relatively cool summers or mild winters.
Additionally, a disproportionate amount of our total revenue is usually realized during the summer months of our third fiscal
quarter. We expect this trend to continue in the future as U.S. demand for power generally peaks during this time.
Operating Heat Rate and Availability
Our fleet is modern and more efficient than the average generation fleet; accordingly, we run more and earn incremental
margin in markets where less efficient natural gas units frequently set the power price. In such cases, our unhedged Commodity
Margin is positively correlated with how much more efficient our fleet is than our competitors’ fleets and with higher natural gas
prices. Efficient operation of our fleet creates the opportunity to capture Commodity Margin. However, unplanned outages during
periods when Commodity Margin is positive can result in a loss of that opportunity. We measure our fleet performance based on
our operating Heat Rate and availability factors. The higher our availability factor, the better positioned we are to capture Commodity
Margin. The lower our operating Heat Rate compared to the Market Heat Rate, the more favorable the impact on our Commodity
Margin.
8
Regulatory and Environmental Pressures
We believe that, on a net basis, we will be favorably impacted by current regulatory and environmental trends, including
those described below, given the characteristics of our power plant portfolio:
• Environmental pressures continue to increase for coal-fired power generation as state and federal agencies enact
rules to reduce air emissions of certain pollutants such as SO2, NOX, GHG, Hg and acid gases, restrict the use of
once-through cooling, and provide for stricter standards for managing coal combustion residuals. Some of the regions
in which we operate include older, less efficient fossil-fuel power plants that emit much higher amounts of GHG,
SO2, NOX, Hg and acid gases, which we anticipate will be negatively impacted by current and future air emissions,
water and waste regulations and legislation both at the state and federal levels. The estimated capacity for fossil-
fueled plants which are older than 50 years and the total estimated capacity for fossil-fueled plants by NERC region
are as follows:
Generating
Capacity Older
Than 50 years
Total Generating
Capacity
West:
WECC ........................................................................................................................
8,450 MW 132,258 MW
Texas:
TRE ............................................................................................................................
2,801 MW
82,552 MW
North:
NPCC .........................................................................................................................
MRO ..........................................................................................................................
RFC ............................................................................................................................
57,559 MW
6,445 MW
4,489 MW
45,869 MW
25,034 MW 197,354 MW
Southeast:
SERC .........................................................................................................................
SPP.............................................................................................................................
FRCC .........................................................................................................................
Total.......................................................................................................................
27,935 MW 235,483 MW
4,811 MW
59,961 MW
59,569 MW
1,233 MW
81,198 MW 870,605 MW
• An increase in power generated from renewable sources could lead to an increased need for flexible power that many
of our power plants provide to protect the reliability of the grid and premium compensation for that flexibility;
however, risks also exist that renewables have the ability to lower overall wholesale prices which could negatively
impact us. Significant economic and reliability concerns for renewable generation have been raised, but we expect
that renewable market penetration will continue to be assisted by state-level renewable portfolio standards and federal
tax incentives.
• The regulators in our core markets remain committed to the competitive wholesale power model, particularly in
Texas and PJM where they continue to focus on market design and rules to assure the long-term viability of competition
and the benefits to customers that justify competition.
• Utilities are increasingly focused on demand side management – managing the level and timing of power usage
through load curtailment, dispatching generators located at commercial or industrial sites, and “smart grid”
technologies that may improve the efficiencies, dispatch usage and reliability of electric grids. Scrutiny of demand
side resources has increased in recent months as system operators evaluate their reliability (especially at high levels
of penetration) and environmental authorities deal with the implications of relying on smaller, less environmentally
efficient generation sources during periods of peak demand when air quality is already challenged.
• Environmental permitting requirements for new power plants and transmission lines are becoming increasingly
onerous.
We believe these trends are positive for our fleet. For a discussion of federal, state and regional legislative and regulatory
initiatives and how they might affect us, see “— Governmental and Regulatory Matters.”
It is very difficult to predict the continued evolution of our markets due to the uncertainty of the following:
•
•
number of market participants, both in terms of physical presence as well as contribution toward financial market
liquidity;
amount of power available in the market;
9
•
•
•
•
•
•
•
•
•
•
•
fluctuations in power supply due to planned and unplanned outages of generators;
fluctuations in power demand due to weather and other factors;
cost of fuel, which could be impacted by the efficiency of generation technology and fluctuations in fuel supply or
interruptions in natural gas transportation;
relative ease or difficulty of developing, permitting and constructing new power plants;
availability and cost of power transmission;
potential growth of demand side management;
creditworthiness and other risks associated with counterparties;
bidding behavior of market participants;
regulatory and ISO guidelines and rules;
structure of commercial products; and
ability to optimize the market’s mix of alternative sources of power such as renewable and hydroelectric power.
Competition
Wholesale power generation is a capital-intensive, commodity-driven business with numerous industry participants. We
compete against other independent power producers, power marketers and trading companies, including those owned by financial
institutions, retail load aggregators, municipalities, retail power providers, cooperatives and regulated utilities to supply power
and power-related products to our customers in major markets in the U.S. and Canada. In addition, in some markets, we compete
against some of our customers.
In markets with centralized ISOs, such as California, Texas and the Mid-Atlantic, our natural gas-fired power plants
compete directly with all other sources of power. The EIA estimates that in 2012, 30% of the power generated in the U.S. was
fueled by natural gas and that approximately 56% of power generated in the U.S. was produced by coal and nuclear facilities,
which generated approximately 37% and 19%, respectively. The EIA estimates that the remaining 14% of power generated in the
U.S. was fueled by hydroelectric, fuel oil and other energy sources. We are subject to complex and stringent energy, environmental
and other governmental laws and regulations at the federal, state and local levels in connection with the development, ownership
and operation of our power plants. Federal and state legislative and regulatory actions continue to change. The federal government
is continuing to take further action on many air pollutant emissions such as NOX, SO2, Hg and acid gases as well as on once-
through cooling and coal ash disposal. Although we cannot predict the ultimate effect any future environmental legislation or
regulations will have on our business, as a clean energy provider, we believe that we are well positioned for almost any increase
in environmental rule stringency. We are actively participating in these debates at the federal, regional and state levels. For a further
discussion of the environmental and other governmental regulations that affect us, see “— Governmental and Regulatory Matters.”
With new environmental regulations, the proportion of power generated by natural gas and other low emissions resources
is expected to increase because older coal-fired power plants will be required to install costly emissions control devices, limit their
operations or be retired. Meanwhile, the federal government and many states are considering or have already mandated that certain
percentages of power delivered to end users in their jurisdictions be produced from renewable resources, such as geothermal, wind
and solar energy.
Competition from other sources of power, such as nuclear energy and renewables, could increase in the future, but likely
at a lower rate than had been previously expected. The nuclear incident in March 2011 at the Fukushima Daiichi nuclear power
plant introduced substantial uncertainties around new nuclear power plant development in the U.S. In addition, the combination
of emerging air emissions regulations, federal and state financial incentives and RPS requirements for renewables and their impact
of expected increased investment in cleaner sources of generation will be somewhat counteracted by a lower natural gas price
environment, which, should it persist, makes new investment in these types of power generation generally uneconomical. Thus,
it is doubtful that generation from new nuclear power plants and renewable sources will be available in the quantities needed to
meet future energy demand. Beyond economic issues, there are concerns over the reliability and adequacy of transmission
infrastructure to transmit certain renewable generation from its source to where it is needed. Consequently, long-term, natural gas
units are likely still needed as baseload and “back-up” generation.
We believe our ability to compete will be driven by the extent to which we are able to accomplish the following:
•
provide affordable, reliable services to our customers;
• maintain excellence in operations;
•
achieve and maintain a lower cost of production, primarily by maintaining unit availability and efficiency;
10
•
•
accurately assess and effectively manage our risks; and
benefit from future environmental regulation and legislation.
MARKETING, HEDGING AND OPTIMIZATION ACTIVITIES
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. Additionally, we seek strong bilateral
relationships with load serving entities that can benefit us and our customers.
The majority of our risk exposures arise from our ownership and operation of power plants. Our primary risk exposures
are Spark Spread, power prices, natural gas prices, capacity prices, locational price differences in both power and natural gas,
natural gas transportation, electric transmission, REC prices, carbon prices in California and other emissions credit prices. In
addition to the direct risk exposure to commodity prices, we also have general market risks such as risk related to performance of
our counterparties and customers and plant operating performance risk. We also have a small exposure to Canadian exchange rates
due to our partial ownership of Greenfield LP and Whitby located in Canada, which are under long term contracts, and minimal
fuel oil exposure which are not currently material to our operations. As such, we have currently elected not to hedge our Canadian
exchange rate or fuel oil exposure.
We produced approximately 116 billion KWh of electricity in 2012 across North America (primarily in the U.S.). We
are one of the largest consumers of natural gas in North America having consumed approximately 867 Bcf during 2012. The four
primary power markets in which we conduct our operations are Texas, California, PJM and the Southeast. The Texas, California
and PJM markets have a centralized market for which power demand and prices are determined on a spot basis (day ahead and
real time), and the Southeast market is a bilateral market. Most of the power generated by our power plants is sold to entities such
as independent electric system operators, utilities, municipalities and cooperatives, as well as to retail power providers, commercial
and industrial end users, financial institutions, power trading and marketing companies and other third parties.
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, 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.
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.
Historically, 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 2013 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 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 measurement 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.
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. For control purposes, we have VAR limits that govern the
overall risk of our portfolio of power plants, energy contracts, financial hedging transactions and other contracts. Our VAR limits,
transaction approval limits and other risk related controls, are dictated by our Risk Management Policy which is approved by our
Board of Directors and by a committee comprised of members of our senior management and administered by our Chief Risk
Officer's organization. The Chief Risk Officer's organization is segregated from the commercial operations unit and reports directly
to our Audit Committee and Chief Financial Officer. Our Risk Management Policy is primarily designed to provide us with a
degree of protection from significant downside commodity price risk exposure to our cash flows.
In order to simplify our reporting, we elected to discontinue the application of hedge accounting treatment during the
first quarter of 2012 for all commodity derivatives, including the remaining commodity derivatives previously accounted for as
cash flow hedges. Accordingly, prospective changes in fair value from the date of this election are reflected in unrealized mark-
to-market activity on our Consolidated Statements of Operations and could create more volatility in our earnings. The fair value
of our commodity derivative instruments residing in AOCI during the previous application of hedge accounting was reclassified
11
to earnings during 2012 as the related economic transactions affected earnings or the forecasted transaction became probable of
not occurring.
We have historically used interest rate swaps to adjust the mix between our fixed and variable rate debt. To the extent
eligible, our interest rate swaps 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. The reclassification of unrealized losses from AOCI into earnings and the changes in fair value and
settlements subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility is
presented separately from interest expense as loss on interest rate derivatives on our Consolidated Statements of Operations. See
Note 8 of the Notes to Consolidated Financial Statements for further discussion of our derivative instruments.
Seasonality and weather can have a significant impact on our results of operations and are also considered in our hedging
and optimization activities. Most of our power plants are located in regional power markets where the greatest demand for power
occurs during the summer months, which coincides with our third fiscal quarter. Depending on existing contract obligations and
forecasted weather and power demands, we may maintain either a larger or smaller open position on fuel supply and committed
generation during the summer months in order to protect and enhance our Commodity Margin accordingly.
SEGMENT AND SIGNIFICANT CUSTOMER INFORMATION
See Note 16 of the Notes to Consolidated Financial Statements for a discussion of financial information by reportable
segment and sales in excess of 10% of our annual consolidated revenues to one of our customers.
12
DESCRIPTION OF OUR POWER PLANTS
Geographic Diversity
Dispatch Technology
13
Power Plants in Operation at December 31, 2012
We own 92 power plants, including 4 under construction (1 new power plant and 3 expansions of existing power plants),
with an aggregate generation capacity of approximately 27,321 MW and 1,163 MW under construction.
Natural Gas-Fired Fleet
Our natural gas-fired power plants primarily utilize two types of designs: 2,465 MW of simple-cycle combustion turbines
and 23,244 MW of combined-cycle combustion turbines and a small portion from conventional natural gas/oil-fired boilers with
steam turbines. Simple-cycle combustion turbines burn natural gas or oil to spin an electric generator to produce power. A combined-
cycle unit combusts fuel like a simple-cycle combustion turbine and the exhaust heat is captured by a heat recovery boiler to create
steam which can then spin a steam turbine. Simple-cycle turbines are easier to maintain, but combined-cycle turbines operate with
much higher efficiency. Our “all in” Steam Adjusted Heat Rate for 2012 for the power plants we operate was 7,361 Btu/KWh
which results in a power conversion efficiency of approximately 46%. The power conversion efficiency is a measure of how
efficiently a fossil fuel power plant converts thermal energy to electrical energy. Our “all in” Steam Adjusted Heat Rate includes
all fuel required to dispatch our power plants including “start-up” and “shut-down” fuel, as well as all non-steady state operations.
Once our power plants achieve steady state operations, our combined-cycle power plants achieve an average power conversion
efficiency of approximately 50%. Additionally, we also sell steam from our combined heat and power plants, which improves our
power conversion efficiency in steady state operations from these power plants to an average of approximately 53%. Due to our
modern combustion turbine fleet, our power conversion efficiency is significantly better than that of older technology natural gas-
fired power plants and coal-fired power plants, which typically have power conversion efficiencies that range from 28% to 36%.
Each of our power plants currently in operation is capable of producing power for sale to a utility, another third-party
end user or an intermediary such as a marketing company. At 19 of our power plants we also produce thermal energy (primarily
steam and chilled water), which can be sold to industrial and governmental users. These plants are called combined heat and power
facilities.
Our natural gas fleet is relatively young with a weighted average age, based upon MW capacities in operation, of
approximately thirteen years. Taken as a portfolio, our natural gas power plants are among the most efficient in converting natural
gas to power and emit far fewer pollutants than most typical utility fleets. The age, scale, efficiency and cleanliness of our power
plants is a unique profile in the wholesale power sector.
The majority of the combustion turbines in our fleet are one of four technologies: GE 7FA, GE LM6000, Siemens 501FD
or Siemens V84.2 turbines. We maintain our fleet through a regular and rigorous maintenance program. As units reach certain
operating targets, which are typically based upon service hours or number of starts, we perform the maintenance that is required
for that unit at that stage in its life cycle. Our large fleet of similar technologies has enabled us to build significant technical and
engineering experience with these units and minimize the number of replacement parts in inventory. We leverage this experience
by performing much of our major maintenance ourselves with our outage services subsidiary.
Geothermal Fleet
Our Geysers Assets are a 725 MW fleet of 15 operating power plants in northern California. Geothermal power is
considered a renewable energy because the steam harnessed to power our turbines is produced inside the Earth and does not require
burning fuel. The steam is produced below the Earth’s surface from reservoirs of hot water, both naturally occurring and injected.
The steam is piped directly from the underground production wells to the power plants and used to spin turbines to make power.
For the past twelve consecutive years, our Geysers Assets have continued to generate approximately 6 million MWh per year.
Unlike other renewable resources such as wind or sunlight, which depend on intermittent sources to generate power, making them
less reliable, geothermal power provides a consistent source of energy as evidenced by our Geysers Assets’ availability record of
approximately 97% in 2012.
We inject water back into the steam reservoir, which extends the useful life of the resource and helps to maintain the
output of our Geysers Assets. The water we inject comes from the condensate associated with the steam extracted to generate
power, wells and creeks, as well as water purchase agreements for reclaimed water. We receive and inject an average of
approximately 16 million gallons of reclaimed water per day into the geothermal steam reservoir at The Geysers where the water
is naturally heated by the Earth, creating additional steam to fuel our Geysers Assets. Approximately 12 million gallons per day
are received from the Santa Rosa Geysers Recharge Project, which we developed jointly with the City of Santa Rosa, and we
receive, on average, approximately 4 million gallons a day from The Lake County Recharge Project from Lake County. As a result
of these recharge projects, MWh production has been relatively constant. We expect that, as a result of the water injection program,
the reservoir at our Geysers Assets will be able to supply economic quantities of steam for the foreseeable future.
14
We periodically review our geothermal studies to help us assess the economic life of our geothermal reserves. Our most
recent geothermal reserve study was conducted in 2011. Our evaluation of our geothermal reserves, including our review of any
applicable independent studies conducted, indicates that our Geysers Assets should continue to supply sufficient steam to generate
positive cash flows at least through 2068. In reaching this conclusion, our evaluation, consistent with the due diligence study of
2011, assumes that defined “proved reserves” are those quantities of geothermal energy which, by analysis of geological and
engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from
known reservoirs and under current economic conditions, operating methods, and government regulations.
We lease the geothermal steam fields from which we extract steam for our Geysers Assets. We have leasehold mineral
interests in 110 leases comprising approximately 29,019 acres of federal, state and private geothermal resource lands in The Geysers
region of northern California. Our leases cover one contiguous area of property that comprises approximately 45 square miles in
the northwest corner of Sonoma County and southeast corner of Lake County. The approximate breakout by volume of steam
removed under the above leases for the year ended 2012 is:
•
•
•
29% related to leases with the federal government via the Office of Natural Resources Revenue (formerly, the Minerals
Management Service),
28% related to leases with the California State Lands Commission, and
43% related to leases with private landowners/leaseholders.
In general, our geothermal leases grant us the exclusive right to drill for, produce and sell geothermal resources from
these properties and the right to use the surface for all related purposes. Each lease requires the payment of annual rent until
commercial quantities of geothermal resources are established. After such time, the leases require the payment of minimum advance
royalties or other payments until production commences, at which time production royalties are payable on a monthly basis from
10 to 31 days (depending upon the lease terms) following the close of the production month. Such royalties and other payments
are payable to landowners, state and federal agencies and others, and vary widely as to the particular lease. In general, royalties
payable are calculated based upon a percentage of total gross revenue received by us associated with our geothermal leases. Each
lease’s royalty calculation is based upon its percentage of revenue as calculated by its steam generated to the total steam generated
by our Geysers Assets as a whole.
Our geothermal leases are generally for initial terms varying from 10 to 20 years or for so long as geothermal resources
are produced and sold. A few of our geothermal leases were signed in excess of 30 years ago. Our federal leases are, in general,
for an initial 10-year period with renewal clauses for an additional 40 years for a maximum of 50 years. The 50-year term expires
in 2024 for the majority of our federal leases. However, our federal leases allow for a preferential right to renewal for a second
40-year term on such terms and conditions as the lessor deems appropriate if, at the end of the initial 40-year term, geothermal
steam is being produced or utilized in commercial quantities. The majority of our other leases run through the economic life of
our Geysers Assets and provide for renewals so long as geothermal resources are being produced or utilized, or are capable of
being produced or utilized, in commercial quantities from the leased land or from land unitized with the leased land. Although we
believe that we will be able to renew our leases through the economic life of our Geysers Assets on terms that are acceptable to
us, it is possible that certain of our leases may not be renewed, or may be renewable only on less favorable terms.
In addition, we hold 40 geothermal leases comprising approximately 43,840 acres of federal geothermal resource lands
in the Glass Mountain area in northern California, which is separate from The Geysers region. Four test production wells were
drilled prior to our acquisition of these leases and we have drilled one test well since their acquisition, which produced commercial
quantities of steam during flow tests. However, the properties subject to these leases have not been developed and there can be
no assurance that these leases will ultimately be developed.
Other Power Generation Technologies
Across the fleet, we also have a variety of older, less efficient technologies including approximately 883 MW of capacity
from power plants which have conventional steam turbine technology. We also have approximately 4 MW of capacity from solar
power generation technology at our Vineland Solar Energy Center in New Jersey.
15
Table of Operating Power Plants and Projects Under Construction and Advanced Development
Set forth below is certain information regarding our operating power plants and projects under construction and advanced
development at December 31, 2012.
NERC
Region
U.S. State or
Canadian
Province
Technology
Calpine
Interest
Percentage
Calpine Net
Interest
Baseload
(MW)(1)(3)
Calpine Net
Interest
With
Peaking
(MW)(2)(3)
2012
Total MWh
Generated(4)
SEGMENT / Power Plant
WEST
Geothermal
McCabe #5 & #6 .................................. WECC
Ridge Line #7 & #8 .............................. WECC
Calistoga............................................... WECC
Eagle Rock ........................................... WECC
Quicksilver ........................................... WECC
Cobb Creek........................................... WECC
Lake View............................................. WECC
Sulphur Springs .................................... WECC
Socrates ................................................ WECC
Big Geysers .......................................... WECC
Grant..................................................... WECC
Sonoma................................................. WECC
West Ford Flat ...................................... WECC
Aidlin.................................................... WECC
Bear Canyon ......................................... WECC
Natural Gas-Fired
Delta Energy Center ............................. WECC
Pastoria Energy Center......................... WECC
Hermiston Power Project...................... WECC
Otay Mesa Energy Center .................... WECC
Metcalf Energy Center ......................... WECC
Sutter Energy Center ............................ WECC
Los Medanos Energy Center ................ WECC
South Point Energy Center ................... WECC
Gilroy Energy Center ........................... WECC
Gilroy Cogeneration Plant.................... WECC
King City Cogeneration Plant .............. WECC
Greenleaf 1 Power Plant....................... WECC
Greenleaf 2 Power Plant....................... WECC
Wolfskill Energy Center....................... WECC
Yuba City Energy Center...................... WECC
Feather River Energy Center................ WECC
Creed Energy Center ............................ WECC
Lambie Energy Center.......................... WECC
Goose Haven Energy Center ................ WECC
Riverview Energy Center ..................... WECC
King City Peaking Energy Center ........ WECC
Agnews Power Plant ............................ WECC
Subtotal...........................................
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
OR
CA
CA
CA
CA
AZ
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
Renewable
Renewable
Renewable
Renewable
Renewable
Renewable
Renewable
Renewable
Renewable
Renewable
Renewable
Renewable
Renewable
Renewable
Renewable
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Cogen
Combined Cycle
Simple Cycle
Cogen
Cogen
Combined Cycle
Cogen
Simple Cycle
Simple Cycle
Simple Cycle
Simple Cycle
Simple Cycle
Simple Cycle
Simple Cycle
Simple Cycle
Combined Cycle
16
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
78
69
66
66
53
52
52
51
50
48
43
42
24
17
14
835
770
566
513
564
542
518
520
—
109
120
50
49
—
—
—
—
—
—
—
—
28
78
69
66
66
53
52
52
51
50
48
43
42
24
17
14
857
749
635
608
605
578
572
530
141
130
120
50
49
48
47
47
47
47
47
47
44
28
690,435
627,748
536,435
601,883
393,048
433,795
508,540
388,902
339,550
483,630
346,996
324,759
221,400
119,471
98,335
5,704,956
4,371,891
2,888,861
3,852,390
2,778,933
1,273,920
3,588,525
1,364,070
67,181
241,850
499,483
60,273
279,760
16,549
45,663
36,633
10,130
9,371
9,801
19,048
11,772
143,775
5,909
6,751
33,389,762
NERC
Region
U.S. State or
Canadian
Province
Technology
Calpine
Interest
Percentage
Calpine Net
Interest
Baseload
(MW)(1)(3)
Calpine Net
Interest
With Peaking
(MW)(2)(3)
2012
Total MWh
Generated(4)
SEGMENT / Power Plant
TEXAS
Deer Park Energy Center.......................
Baytown Energy Center ........................
Pasadena Power Plant(5).........................
Bosque Energy Center(6)........................
Freestone Energy Center .......................
Magic Valley Generating Station...........
Channel Energy Center..........................
Brazos Valley Power Plant....................
Corpus Christi Energy Center ...............
Texas City Power Plant .........................
Clear Lake Power Plant.........................
Hidalgo Energy Center..........................
Freeport Energy Center(7) ......................
Subtotal............................................
NORTH
Bethlehem Energy Center......................
Hay Road Energy Center.......................
Edge Moor Energy Center.....................
York Energy Center...............................
Westbrook Energy Center......................
Greenfield Energy Centre(8)...................
RockGen Energy Center........................
Zion Energy Center ...............................
Mankato Power Plant ............................
Cumberland Energy Center ...................
Deepwater Energy Center(9)...................
Kennedy International Airport
Power Plant............................................
TRE
TRE
TRE
TRE
TRE
TRE
TRE
TRE
TRE
TRE
TRE
TRE
TRE
RFC
RFC
RFC
RFC
NPCC
NPCC
MRO
RFC
MRO
RFC
RFC
NPCC
Sherman Avenue Energy Center............
RFC
Bethpage Energy Center 3.....................
Middle Energy Center(9) ........................
Carll’s Corner Energy Center................
Cedar Energy Center(9) ..........................
Mickleton Energy Center ......................
Missouri Avenue Energy Center(9).........
Bethpage Power Plant ...........................
NPCC
RFC
RFC
RFC
RFC
RFC
NPCC
Christiana Energy Center ......................
RFC
Bethpage Peaker ....................................
Stony Brook Power Plant ......................
Tasley Energy Center ............................
Whitby Cogeneration(10) ........................
Delaware City Energy Center................
West Energy Center...............................
Bayview Energy Center.........................
Crisfield Energy Center.........................
Vineland Solar Energy Center...............
Subtotal............................................
NPCC
NPCC
RFC
NPCC
RFC
RFC
RFC
RFC
RFC
100%
100%
100%
100%
75%
100%
100%
100%
100%
100%
100%
78.5%
100%
100%
100%
100%
100%
100%
50%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
50%
100%
100%
100%
100%
100%
843
782
763
740
779
662
463
520
426
400
344
392
210
1,014
842
781
762
746
692
608
606
500
453
400
374
236
6,164,077
4,510,187
4,638,034
301,167
3,987,727
4,290,913
2,501,611
3,384,971
2,287,273
1,230,745
515,663
2,133,709
1,436,720
7,324
8,014
37,382,797
1,037
1,030
1,130
1,130
—
519
552
422
—
—
280
—
—
110
—
60
—
—
—
—
—
55
—
—
45
—
25
—
—
—
—
—
725
565
552
519
503
503
375
191
158
121
92
80
77
73
68
67
60
56
53
48
47
33
25
23
20
12
10
4
5,811,693
5,179,087
1,077,342
3,484,727
2,446,074
1,645,699
260,064
133,143
495,871
43,623
96,860
664,482
30,757
204,385
475
23,151
1,659
3,932
685
197,899
159
106,552
309,901
164
205,417
68
42
1,772
451
8,960
4,135
7,320
22,435,094
TX
TX
TX
TX
TX
TX
TX
TX
TX
TX
TX
TX
TX
PA
DE
DE
PA
ME
ON
WI
IL
MN
NJ
NJ
NY
NJ
NY
NJ
NJ
NJ
NJ
NJ
NY
DE
NY
NY
VA
ON
DE
DE
VA
MD
NJ
Cogen
Cogen
Cogen/
Combined Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Cogen
Combined Cycle
Cogen
Cogen
Cogen
Combined Cycle
Cogen
Combined Cycle
Combined Cycle
Steam Cycle
Combined Cycle
Combined Cycle
Combined Cycle
Simple Cycle
Simple Cycle
Combined Cycle
Simple Cycle
Steam Cycle
Cogen
Simple Cycle
Combined Cycle
Simple Cycle
Simple Cycle
Simple Cycle
Simple Cycle
Simple Cycle
Combined Cycle
Simple Cycle
Simple Cycle
Cogen
Simple Cycle
Cogen
Simple Cycle
Simple Cycle
Simple Cycle
Simple Cycle
Renewable
17
SEGMENT / Power Plant
SOUTHEAST
NERC
Region
U.S. State or
Canadian
Province
Technology
Calpine
Interest
Percentage
Calpine Net
Interest
Baseload
(MW)(1)(3)
Calpine Net
Interest
With Peaking
(MW)(2)(3)
2012
Total MWh
Generated(4)
Oneta Energy Center.........................
SPP
Morgan Energy Center......................
Decatur Energy Center......................
Columbia Energy Center...................
Osprey Energy Center.......................
Carville Energy Center .....................
Hog Bayou Energy Center ................
Santa Rosa Energy Center ................
Pine Bluff Energy Center..................
Auburndale Peaking Energy Center..
Subtotal .......................................
SERC
SERC
SERC
FRCC
SERC
SERC
SERC
SERC
FRCC
Total operating power plants......
90
Power plants sold during 2012
OK
AL
AL
SC
FL
LA
AL
FL
AR
FL
Combined Cycle
Cogen
Combined Cycle
Cogen
Combined Cycle
Cogen
Combined Cycle
Combined Cycle
Cogen
Simple Cycle
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
980
720
782
455
537
449
235
235
184
—
1,134
807
795
606
599
501
237
225
215
117
3,320,995
4,062,128
3,176,398
51,561
3,127,895
2,855,396
1,113,720
850,178
1,489,526
27,080
4,577
21,945
5,236
27,321
20,074,877
113,282,530
Riverside Energy Center ...................
Broad River Energy Center...............
MRO
SERC
WI
SC
Combined Cycle
Simple Cycle
100%
100%
n/a
n/a
n/a
n/a
Subtotal .......................................
Total operating and sold power
plants .............................................
Projects Under Construction and Advanced Development
Projects under construction
Russell City Energy Center............ WECC
Los Esteros Critical Energy
Facility(11) ....................................... WECC
TRE
Channel Energy Center Expansion
Deer Park Energy Center
Expansion.......................................
TRE
Projects under advanced development
Garrison Energy Center .................
RFC
Total operating power plants
and projects ...............................
___________
CA
CA
TX
TX
DE
Combined Cycle
Combined Cycle
Cogen
Cogen
75%
100%
100%
100%
Combined Cycle
100%
429
243
260
260
273
464
309
200
190
309
23,410
28,793
1,148,198
1,073,303
2,221,501
115,504,031
n/a
n/a
n/a
n/a
n/a
(1) Natural gas-fired fleet capacities are generally derived on as-built as-designed outputs, including upgrades, based on site
specific annual average temperatures and average process steam flows for cogeneration power plants, as applicable.
Geothermal capacities are derived from historical generation output and steam reservoir modeling under average ambient
conditions (temperatures and rainfall).
(2) Natural gas-fired fleet peaking capacities are primarily derived on as-built as-designed peaking outputs based on site specific
average summer temperatures and include power enhancement features such as heat recovery steam generator duct-firing,
gas turbine power augmentation, and/or other power augmentation features. For certain power plants with definitive
contracts, capacities at contract conditions have been included. Oil-fired capacities reflect capacity test results.
(3)
These outputs do not factor in the typical MW loss and recovery profiles over time, which natural gas-fired turbine power
plants display associated with their planned major maintenance schedules.
(4) MWh generation is shown here as our net operating interest.
(5)
Pasadena is comprised of 260 MW of cogen technology and 521 MW of combined cycle (non-cogen) technology.
(6) Bosque Energy Center was acquired on November 7, 2012.
(7)
Freeport Energy Center is owned by Calpine; however, it is contracted and operated by The Dow Chemical Company.
(8) Calpine holds a 50% partnership interest in Greenfield LP through its subsidiaries; however, it is operated by a third party.
(9) We have provided notice to PJM that we plan to retire these units before commencement of the PJM Reliability Pricing
Model 2015/2016 delivery year.
18
(10) Calpine holds a 50% partnership interest in Whitby Cogeneration through its subsidiaries; however, it is operated by Atlantic
Packaging Products Ltd.
(11) Los Esteros Critical Energy Facility is currently under construction to upgrade from a 188 MW simple-cycle generation
power plant to a 309 MW combined-cycle generation power plant.
We provide operations and maintenance services for all but three of the power plants in which we have an interest. Such
services include the operation of power plants, geothermal steam fields, wells and well pumps and natural gas pipelines. We also
supervise maintenance, materials purchasing and inventory control, manage cash flow, train staff and prepare operations and
maintenance manuals for each power plant that we operate. As a power plant develops an operating history, we analyze its operation
and may modify or upgrade equipment, or adjust operating procedures or maintenance measures to enhance the power plant’s
reliability or profitability. Although we do not operate the Freeport Energy Center, our outage services subsidiary performs all
major maintenance services for this plant under a contract with The Dow Chemical Company through April 2032.
Certain power plants in which we have an interest have been financed primarily with project financing that is structured
to be serviced out of the cash flows derived from the sale of power (and, if applicable, thermal energy and capacity) produced by
such power plants and generally provide that the obligations to pay interest and principal on the loans are secured solely by the
capital stock or partnership interests, physical assets, contracts and/or cash flows attributable to the entities that own the power
plants. The lenders under these project financings generally have no recourse for repayment against us or any of our assets or the
assets of any other entity other than foreclosure on pledges of stock or partnership interests and the assets attributable to the entities
that own the power plants. However, defaults under some project financings may result in cross-defaults to certain of our other
debt and debt instruments, including our First Lien Notes, First Lien Term Loans, and Corporate Revolving Facility. Acceleration
of the maturity of a project financing following a default may also result in a cross-acceleration of such other debt.
Substantially all of the power plants in which we have an interest are located on sites which we own or lease on a long-
term basis.
EMISSIONS AND OUR ENVIRONMENTAL PROFILE
Our environmental record has been widely recognized. We were an EPA Climate Leaders Partner with a stated goal to
reduce GHG emissions, and we became the first power producer to earn the distinction of Climate Action LeaderTM. We have
certified our GHG emissions inventory with the California Climate Action Registry every year since 2003. In 2011, our emissions
of GHG amounted to about 41 million tons.
Natural Gas-Fired Generation
Our natural gas-fired, primarily combined-cycle fleet consumes significantly less fuel to generate power than conventional
boiler/steam turbine power plants and emits fewer air pollutants per MWh of power produced as compared to coal-fired or oil-
fired power plants. All of our power plants have air emissions controls and most have selective catalytic reduction to further reduce
emissions of nitrogen oxides, a precursor of atmospheric ozone. In addition, we have implemented a program of proprietary
operating procedures to reduce natural gas consumption and further lower air pollutant emissions per MWh of power generated.
The table below summarizes approximate air pollutant emission rates from our natural gas-fired, combined-cycle power plants
compared to the average emission rates from U.S. coal-, oil- and natural gas-fired power plants as a group, based on the most
recent statistics available to us.
Air Pollutant Emission Rates —
Pounds of Pollutant Emitted
Per MWh of Power Generated
Average U.S. Coal-, Oil-,
and Natural Gas-Fired
Power Plant
1.92
(1)
Calpine
Natural Gas-Fired,
Combined-Cycle
(2)
Power Plant
0.14
Advantage Compared to
Average U.S. Coal-, Oil-,
and Natural Gas-Fired
Power Plant
92.7%
3.87
0.0058
Air Pollutants
Nitrogen Oxides, NOx .......................................
Acid rain, smog and fine particulate formation
Sulfur Dioxide, SO2 ......................................................
Acid rain and fine particulate formation
Mercury Compounds(3) .....................................
0.00002
Neurotoxin
Carbon Dioxide, CO2 ..................................................
Principal GHG—contributor to climate change
1,825
19
—
876
99.9%
100%
52%
___________
(1)
The average U.S. coal-, oil- and natural gas-fired power plants’ emission rates were obtained from the U.S. Department of
Energy’s Electric Power Annual Report for 2011. Emission rates are based on 2011 emissions and net generation. The U.S.
Department of Energy has not yet released 2012 information.
(2) Our natural gas-fired, combined-cycle power plant estimated emission rates are based on our 2011 emissions and power
generation data from our natural gas-fired, combined-cycle power plants (excluding combined heat power plants) as
measured under the EPA reporting requirements.
(3)
The U.S. coal-, oil- and natural gas-fired power plant air emissions of mercury compounds were obtained from the EPA
Toxics Release Inventory for 2011. Emission rates are based on 2011 emissions and net generation from U.S. Department
of Energy’s Electric Power Annual Report for 2011.
Geothermal Generation
Our 725 MW fleet of geothermal turbine-based power plants utilizes a natural, renewable energy source, steam from the
Earth’s interior, to generate power. Since these power plants do not burn fossil fuel, they are able to produce power with negligible
CO2 (the principal GHG), NOX and SO2 emissions. Compared to the average U.S. coal-, oil- and natural gas-fired power plant,
our Geysers Assets emit 99.9% less NOX, 100% less SO2 and 96.9% less CO2. There are 18 active geothermal power plants located
in The Geysers region of northern California. We own and operate 15 of them. We recognize the importance of our Geysers Assets
and we are committed to extending and expanding this renewable geothermal resource through the addition of new steam wells
and wastewater recharge projects where clean, reclaimed water from local municipalities is recycled into the geothermal resource
where it is converted by the Earth’s heat into steam for power production.
Water Conservation and Reclamation
We have also invested substantially in technologies and systems that reduce the impact of our operations on water as a
natural resource:
• We receive and inject an average of approximately 16 million gallons of reclaimed water per day into the geothermal
steam reservoir at The Geysers where the water is naturally heated by the Earth, creating additional steam to fuel our
Geysers Assets. Approximately 12 million gallons per day are received from the Santa Rosa Geysers Recharge Project,
which we developed jointly with the City of Santa Rosa, and we receive, on average, approximately 4 million gallons a
day from The Lake County Recharge Project from Lake County.
•
•
In our combined-cycle power plants, we use mechanical draft cooling towers, which use up to 90% less water than
conventional once-through cooling systems. Two of our combined-cycle power plants employ air-cooled condensers,
which consume virtually no water for cooling.
In eleven of our operating power plants and one power plant under construction equipped with cooling towers, we reuse
treated water from municipal treatment systems for cooling. By reusing water in these cooling towers, we avoid the usage
of as much as 35 million gallons per day of valuable surface and/or groundwater for cooling.
• Our Russell City Energy Center will use 100% reclaimed water from the City of Hayward’s Water Pollution Control
Facility for cooling and boiler makeup, which will prevent nearly four million gallons of wastewater per day from being
discharged into the San Francisco Bay.
GOVERNMENTAL AND REGULATORY MATTERS
We are subject to complex and stringent energy, environmental and other laws and regulations at the federal, state and
local levels as well as within the RTO and ISO markets in which we participate in connection with the development, ownership
and operation of our power plants. Federal and state legislative and regulatory actions continue to change how our business is
regulated.
Environmental Matters
Federal Regulation of Air Emissions
The CAA provides for the regulation of air quality and air emissions, largely through state implementation of federal
requirements. We believe that all of our operating power plants comply with existing federal and state performance standards
mandated under the CAA. We continue to monitor and actively participate in EPA initiatives where we anticipate an impact on
our business. Some of the more significant governmental and regulatory matters that affect our business are discussed below.
20
Criteria Pollutants and Hazardous Air Pollutants
The CAA requires the EPA to regulate emissions of pollutants considered harmful to public health and the environment.
The EPA has set NAAQS for six “criteria” pollutants: carbon monoxide, lead, NO2, particulate matter (“PM”), ozone and SO2.
In addition, the CAA regulates a large number of air pollutants that are known to cause or may reasonably be anticipated to cause
adverse effects to human health or adverse environmental effects, known as hazardous air pollutants (“HAPs”). The EPA is required
to issue technology-based national emissions standards for hazardous air pollutants (“NESHAPs”) to limit the release of specified
HAPs from specific industrial sectors.
Mercury and Air Toxics Standards
On December 21, 2011, the EPA issued the National Emission Standards for Hazardous Air Pollutants from Coal- and
Oil-fired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, Industrial-
Commercial-Institutional, and Small Industrial-Commercial-Institutional Steam Generating Units, otherwise known as the
Mercury and Air Toxics Standards (“MATS”). MATS will reduce emissions of all hazardous air pollutants emitted by coal- and
oil-fired electric generating units, including mercury (Hg), arsenic (As), chromium (Cr), nickel (Ni) and acid gases.
The EPA estimates that there are approximately 1,400 units affected by MATS, consisting of approximately 1,100 existing
coal-fired units and 300 oil-fired units at approximately 600 power plants. The CAA provides existing units three years from the
effective date of MATS to achieve compliance. As a result, existing coal-fired units without emissions controls will need to retire
or install controls on acid gases, mercury and particulate matter emissions by April 16, 2015. State enforcement authorities also
have discretion under the CAA to provide an additional year for technology installation. Further, the EPA issued a policy
memorandum which indicates that the EPA may provide, in limited circumstances due to delays in the installation of controls, an
additional year extension for MATS compliance where necessary to maintain electric system reliability. Accordingly, although
the EPA’s analysis indicates that it should take no longer than three years for most existing units to comply, they may have up to
five years, or until April 16, 2017, to install controls and comply with MATS.
We are not directly affected by MATS because it does not apply to natural gas-fired units, peaking units or units that use
fuel oil as a backup fuel. We believe that the emission standards are sufficiently stringent to force existing coal-fired units without
emissions controls to retire or to install the necessary controls by April 16, 2015 (unless an extension is granted), which could
benefit our competitive position.
Prior to the April 16, 2012 filing deadline, a total of 30 petitions for review challenging MATS were filed in the U.S.
Court of Appeals for the D.C. Circuit (“D.C. Circuit”) and subsequently consolidated under the case White Stallion Energy Center
v. EPA. On March 19, 2012, Calpine, along with other energy companies, filed a motion for leave to intervene in the consolidated
case in support of the EPA. Petitioners are expected to argue that the rule is arbitrary and capricious because the EPA failed to
adequately demonstrate its threshold finding that the rule is “appropriate and necessary”; the EPA failed to address their concerns
that MATS could damage electricity grid reliability; and the standards for new sources are not achievable.
Several petitioners moved to sever the issues specific to the standards for new coal-fired power plants and expedite
briefing on those issues. On June 28, 2012, the D.C. Circuit granted the motion to sever and expedite briefing, and the new unit
case is being considered under a separate docket number. However, on July 20, 2012, the EPA granted partial administrative
reconsideration of certain issues affecting new units, namely, measurement issues related to mercury and the data underlying
particulate matter and hydrogen chloride emissions standards. The EPA stayed the effectiveness of MATS with respect to the new
unit issues under reconsideration.
As a consequence, on September 12, 2012, the D.C. Circuit stayed the severed case addressing standards for new units
and held that case in abeyance pending the EPA’s administrative reconsideration of the new unit standards. In response to the
petition for reconsideration, the EPA issued a proposed rule reconsidering MATS for new sources on November 30, 2012. The
proposed rule would, among other things, amend certain new source standards and the requirements applicable during periods of
startup and shut down. The public comment period on the proposed rule for new units closed on January 7, 2013. The EPA will
issue a final reconsideration in March 2013.
The D.C. Circuit is being briefed on the remaining challenges to MATS that are not being held in abeyance (e.g., challenges
to existing unit standards). Oral argument has not been scheduled for the remaining consolidated challenges to MATS.
Cross-State Air Pollution Rule
On July 6, 2011, the EPA finalized the Cross-State Air Pollution Rule (“CSAPR”) which would require a total of 28
states, primarily in the eastern U.S., to reduce annual SO2 emissions, annual NOx emissions and/or ozone season NOx emissions
21
to assist in attaining three NAAQS: the 1997 annual PM2.5 NAAQS, the 1997 8-hour ozone NAAQS, and the 2006 24-hour
PM2.5 NAAQS.
CSAPR established an unlimited intrastate and limited interstate trading program with allowances allocated to sources
based on historic heat input but capped at maximum annual emissions from 2003 to 2010. At current capacity factors, Calpine
would have been allocated sufficient allowances; thus, CSAPR was not expected to have a negative impact on our operations. We
expected the overall impact of CSAPR to be positive for Calpine because the significant emissions reduction requirements would
require coal-fired electric generating units to either purchase allowances, switch to more expensive fuels, install air pollution
controls, or reduce or discontinue operations, thereby incenting the increased utilization of existing, and development of new,
natural gas-fired power plants.
A number of power generation companies, states and other groups filed petitions for review in the D.C. Circuit challenging
CSAPR, and these cases were consolidated under EME Homer City Generation v. EPA. Calpine, other power generation companies,
states, cities, and public health groups were granted intervenor status on behalf of respondent EPA.
On August 21, 2012, the D.C. Circuit vacated CSAPR. The D.C. Circuit ordered the EPA to continue administering CAIR,
which the EPA has been implementing since the D.C. Circuit stayed CSAPR in December 2011 and which CSAPR was designed
to replace due to the flaws in CAIR identified by the D.C. Circuit in North Carolina v. EPA.
The EPA petitioned for en banc rehearing (i.e., by all active judges on the D.C. Circuit) on October 5, 2012. Intervenors
supporting the EPA also submitted three petitions for en banc rehearing upon similar grounds, including one submitted by a
coalition of environmental and public health organizations, one by a group of cities and states (including the states of North
Carolina, Connecticut, Delaware, Illinois, Maryland, Massachusetts, New York, Rhode Island and Vermont) and one jointly filed
by Calpine and Exelon Corporation. On January 24, 2013, the D.C. Circuit denied en banc rehearing in this case. A petition for a
writ of certiorari to appeal this decision to the Supreme Court may still be filed by the EPA or any other party. Assuming the
decision is not reversed by the U.S. Supreme Court upon a petition for writ of certiorari, the EPA must continue to implement
CAIR while it creates a replacement for CSAPR.
CAIR and Multi-Pollutant Program
Pursuant to authority granted under the CAA, the EPA promulgated the Clean Air Interstate Rule, or CAIR, regulations
in March 2005, applicable to 28 eastern states and the District of Columbia, to facilitate attainment of its ozone and fine particulates
NAAQS issued in 1997. CAIR’s goal is to reduce SO2 emissions in these states by over 70%, and NOX emissions by over 60%
from 2003 levels by 2015. CAIR established annual Cap-and-trade programs for SO2 and NOX as well as a seasonal program for
NOX. On July 11, 2008, the D.C. Circuit invalidated CAIR, stating that the “EPA’s approach – region-wide caps with no state
specific quantitative contribution determinations or emission requirements – is fundamentally flawed.” The court did not overturn
the existing Cap-and-trade program for SO2 reductions under the Acid Rain Program or the existing ozone season Cap-and-trade
program under the NOX State Implementation Plan Call. On September 25, 2008, the EPA petitioned the court for rehearing. On
December 23, 2008, the court remanded CAIR without vacatur for the EPA to conduct further proceedings consistent with the
July 11, 2008 opinion. As a result of the court’s decision, CAIR was left intact and went into effect as planned on January 1, 2009,
for many of our power plants located throughout the eastern and central U.S. Due to favorable allowance allocations, particularly
in Texas, we have a net surplus of annual NOX allowances and the net financial impact of the program to our operations is positive.
As a result of CSAPR being vacated in August 2012, the D.C. Circuit reinstated CAIR until the EPA creates a replacement for
CSAPR.
GHG Emissions
On April 2, 2007, the U.S. Supreme Court in Massachusetts v. EPA ruled that the EPA has the authority to regulate GHG
emissions under the CAA. In response to Massachusetts, the EPA issued an endangerment finding for GHGs on December 7,
2009, determining that concentrations of six GHGs endanger the public health and welfare. Further, pursuant to the CAA’s
requirement that the EPA establish motor-vehicle emission standards for “any air pollutant . . . which may reasonably be anticipated
to endanger public health or welfare,” the EPA promulgated the so-called “Tailpipe Rule” for GHGs, which set GHG emission
standards for cars and light trucks.
Under the EPA’s longstanding interpretation of the CAA, the Tailpipe Rule automatically triggered regulation of stationary
sources of GHG emissions under the Prevention of Significant Deterioration (“PSD”) program (which requires state-issued
construction permits for stationary sources that have the potential to emit over 100 or 250 tons per year (“tpy”), the applicable
threshold depending on the type of source, of “any air pollutant”) and Title V (which requires state-issued operating permits for
stationary sources that have the potential to emit at least 100 tpy of “any air pollutant”). Accordingly, the EPA issued two rules
phasing in stationary source GHG regulation. In the Timing Rule, the EPA delayed when major stationary sources of GHGs would
otherwise be subject to PSD and Title V permitting, concluding that these requirements would commence on January 2, 2011, the
22
date on which the Tailpipe Rule became effective. In the Tailoring Rule, the EPA departed from the CAA’s 100/250 tpy emissions
thresholds and provided that only the largest sources, those exceeding 75,000 or 100,000 tpy carbon dioxide equivalent (“CO2e”),
depending on the program and project, would initially be subject to GHG permitting.
Under Step 1 of the Tailoring Rule (beginning in January 2011), new or modified sources already required to obtain a
PSD permit due to their emissions of conventional regulated pollutants must satisfy best available control technology (“BACT”)
requirements for GHGs if they emit or have the potential to emit at least 75,000 tpy CO2e. Under Step 2 of the Tailoring Rule
(beginning in July 2011), new sources that emit or have the potential to emit at least 100,000 tpy CO2e and existing sources that
emit at that level and that undertake modifications that increase emissions by at least 75,000 tpy CO2e must obtain a PSD permit
and satisfy BACT requirements for GHGs, regardless of their emissions of any conventional pollutants. Step 3 of the Tailoring
Rule was finalized in July 2012 and maintained the GHG PSD and Title V permitting thresholds specified under Step 2.
The EPA has issued guidance to permitting authorities on the implementation of GHG BACT that focuses on energy
efficiency. We believe that the impact of the Tailoring Rule will be neutral to us because we expect that our efficient power plants
would be found to meet BACT for GHGs if required to undergo PSD review. Calpine’s Russell City Energy Center, a 619 MW
combined-cycle power plant (Calpine’s 75% net interest is 464 MW) being constructed in Hayward, California, voluntarily accepted
GHG BACT limits in its PSD permit before such limits were required by law.
More than sixty petitions for review of these EPA rules were filed by industry and states, which were subsequently
consolidated in the D.C. Circuit case Coalition for Responsible Regulation v. EPA. On June 26, 2012, the D.C. Circuit, in an
unsigned per curiam opinion, upheld all of the challenged GHG regulations. Specifically, the D.C. Circuit denied the petitions
relating to the Endangerment Finding and the Tailpipe Rule on the merits, while dismissing the petitions for review of the Timing
Rule and the Tailoring Rule on constitutional standing grounds.
On August 10, 2012, industry groups requested rehearing en banc of the D.C. Circuit’s decision in Coalition for
Responsible Regulation. On October 12, 2012, the EPA filed its response in opposition to the rehearing petition. The D.C. Circuit
denied en banc review on December 20, 2012. The petitioners can still petition for a writ of certiorari to the U.S. Supreme Court,
which must be done by March 20, 2013.
In light of the rehearing petition, on October 9, 2012, the D.C. Circuit decided to hold in abeyance a related case regarding
Step 3 of the EPA’s Tailoring Rule (American Petroleum Institute v. EPA). The parties were directed to file motions to govern
future proceedings in American Petroleum Institute within 30 days of the D.C. Circuit’s decision regarding en banc review in
Coalition for Responsible Regulation. The case is still being held in abeyance and no motion has been filed seeking to release the
case from abeyance.
In a related development, the EPA published a proposed New Source Performance Standard (“NSPS”) for GHG emissions
from new electric generating units on April 13, 2012. The proposed rule would establish an output-based CO2 emissions standard
of 1,000 lbs/MWh gross for new fossil fuel-fired generating units, which include boilers, integrated gasification combined-cycle
units and stationary combined-cycle turbine units greater than 25 MW. The emissions standard is based on the performance of
natural gas combined-cycle technology. The proposed NSPS would not apply to simple-cycle plants, plants that burn biomass,
existing sources, sources being modified, or so-called “transitional sources” (i.e., coal-fired plants that received PSD permits by
the publication date of the proposed rule (April 13, 2012) and commence construction within 12 months of the publication date
of the proposal).
The proposed NSPS would have no impact on Calpine’s fleet or development plans. According to the EPA, the proposed
NSPS would result in no notable compliance costs because, even in its absence, the electric sector would choose to build natural
gas-fired electric generating units that already comply with the proposed standard.
The comment period on the proposed NSPS rule closed on June 25, 2012. Although the proposal is not yet final, several
developers of permitted coal-fired power plants that could not meet the proposed NSPS without installation of carbon capture and
storage technology filed suit in the D.C. Circuit, challenging the EPA’s proposal. On December 13, 2012, the D.C. Circuit dismissed
the industry challenge to the proposed NSPS because the proposed rule is not “final agency action” subject to judicial review.
The EPA expects to finalize the proposed NSPS in March 2013.
Fees on Permissible Emissions
Section 185 of the CAA requires major stationary sources of NOX and volatile organic compounds (“VOCs”), such as
power plants and refineries, in areas that fail to attain the NAAQS for ozone by the attainment date to pay a fee to the state or, if
the state fails to collect the fee, the EPA. The fee is set in the CAA at $5,000 per ton of NOX or VOC (adjusted for inflation or
approximately $9,000 per ton in 2011) and is payable on emissions that exceed 80% of each individual power plant’s baseline
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emissions, which are established in the year before the attainment date; however, the EPA has provided guidance for the calculation
of alternative baselines. The fee will remain in effect until the designated area achieves attainment.
We operate seven power plants in Texas and one in California that are located within a designated nonattainment area
subject to Section 185. On January 5, 2010, the EPA issued guidance on developing fee programs required under Section 185, but
that guidance was vacated by the D.C. Circuit in 2011 due to the EPA’s failure to follow notice-and-comment rulemaking procedures
in its publication. On August 20, 2012, the EPA finalized approval of San Joaquin Valley Unified Air Pollution Control District’s
(“SJVUAPCD”) fee-equivalent program, which the EPA determined is not less stringent than the program required by Section
185, and, therefore, is approvable as an equivalent alternative program. Environmentalists have challenged EPA’s approval of this
program in the U.S. Court of Appeals for the Ninth Circuit. The lawsuit is currently pending.
The TCEQ proposed a rule in November 2012 to create a Section 185 program, using an approach similar to that used
in the approved SJVUAPCD program. We estimate that compliance with this fee could result in additional costs to us of up to $4
million on an annual basis and our financial statements include accruals for our estimated Section 185 fees. In addition to this
annual fee, we have accrued our estimate for Section 185 fees that may be applied retroactively, although it is unclear whether the
EPA intends to require such retroactive fees to be collected. Our estimates are dependent upon a number of factors that could
change in the future dependent upon, among other things: the EPA approval of state rulemakings, the designation of nonattainment
status, the outcome of pending and potential litigation challenging the EPA’s approvals, the number of our operational power plants
located in these areas and our emissions of NOX and VOC.
On June 18, 2012, the EPA determined that the New York-Northern New Jersey-Long Island (“NY-NJ-CT”) one-hour
ozone attainment area failed to achieve the one-hour NAAQS by the applicable deadline, but also that it is currently attaining the
one-hour standard. As a result of this action, our facilities in New York and New Jersey will not incur Section 185 fees as of the
date of that determination. The EPA has not taken a firm position on retroactive collection of Section185 fees.
Acid Rain Program
As a result of the 1990 CAA amendments, the EPA established a Cap-and-trade program for SO2 emissions from power
plants throughout the U.S. Starting with Phase II of the program in 2000, a permanent ceiling (or cap) was set at 10 million tons
per year, declining to 8.95 million tons per year by 2010. The EPA allocated SO2 allowances to power plants. Each allowance
permits a unit to emit one ton of SO2 during or after a specified year, and allowances may be bought, sold or banked. All but a
small percentage of allowances were allocated to power plants placed into service before 1990. Our power plants currently receive
sufficient free SO2 allowances; therefore, we will have no compliance expense for this program.
Regional and State Air Emissions Activities
Several states and regional organizations are developing, or already have developed, state-specific or regional initiatives
to reduce GHG emissions through mandatory programs. The most advanced programs include the RGGI in the northeast states
and California’s suite of GHG policies promulgated pursuant to AB 32, including its Cap-and-trade program. The evolution of
these programs could have a material impact on our business.
California: GHG — Cap-and-Trade Regulation
California’s AB 32 requires the state to return to 1990 GHG emissions levels by 2020. To meet these levels, CARB has
promulgated a number of regulations, including the Cap-and-trade regulation. In late 2011, CARB finalized its Cap-and-trade
regulation and mandatory reporting regulation, which took effect on January 1, 2012. These regulations were further amended by
CARB in 2012.
Under the Cap-and-trade regulation, the first compliance period for covered entities like Calpine began on January 1,
2013 and runs through the end of 2014. The second and third compliance periods cover 2015 through 2017 and 2018 through
2020, respectively. Covered entities must hold compliance instruments, which include allowances and offsets, in an amount
equivalent to their emissions from sources of GHG located in California and from power imported into California. The first auction
of GHG allowances was held on November 14, 2012 and included the sale of 2013 and 2015 vintage allowances. Quarterly auctions
will be held every year from 2013 to 2020 with the next auction scheduled for February 19, 2013. The emissions market is currently
functioning and the cost of the emissions permits is reflected in market pricing.
Currently, there are two pending lawsuits challenging the Cap-and-trade regulation. On March 28, 2012, two
environmental organizations filed a lawsuit in San Francisco Superior Court seeking to invalidate the four protocols published by
CARB for issuing offsets. On January 25, 2013, the court rejected the petitioners’ claims, holding that CARB’s development of
the protocols was consistent with AB 32. The petitioners have until May 26, 2013 to appeal the decision in the California Court
of Appeals. Additionally, on November 13, 2012, the California Chamber of Commerce filed a complaint in the Sacramento
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Superior Court challenging CARB’s authority to auction allowances. The Sacramento Superior Court is scheduled to hold a hearing
on the merits in that case on May 31, 2013. We cannot predict the ultimate success of either of these lawsuits nor can we predict
whether there will be any additional legal challenges filed against the regulation or what the associated impacts of any such
litigation would be.
In September 2012, the CARB Board directed its staff, by mid-2013, to propose amendments to the Cap-and-trade
regulation that would, among other things, increase the auction purchase limit for covered entities and provide allowances to
covered entities that have long-term contracts that do not allow the costs of compliance to be passed through to their customers.
On January 8, 2013, CARB published a notice for a 15-day rulemaking concerning linkage of California’s and Quebec’s Cap-
and-trade programs (“Linkage Notice”). The Linkage Notice provides background for CARB’s expected request that the California
Governor make certain findings under Senate Bill (“SB”) 1018, which are required before California links with any other
jurisdiction’s Cap-and-trade program. If the Governor makes these findings and CARB approves the proposed amendments,
California and Quebec could hold their first joint auction of GHG allowances in August 2013. CARB’s economic analysis estimates
that linkage between California and Quebec has the potential to increase California’s GHG allowance prices by 5% to 15%.
Overall, we support AB 32 and expect the net impact of the Cap-and-trade regulation to be beneficial to Calpine. We also
believe we are positioned to comply with these regulations.
Northeast and Mid-Atlantic States: CO2 – RGGI
On January 1, 2009, ten northeast and Mid-Atlantic states implemented a Cap-and-trade program, RGGI, which affects
our power plants in Maine, New York and Delaware (together emitting about 3.9 million tons of CO2 annually). In 2011, New
Jersey announced its withdrawal from the RGGI program effective as of the 2012 compliance year.
RGGI caps regional CO2 emissions and requires generators to acquire one allowance for every ton of CO2 emitted over
a three-year compliance period. Apart from state-specific set-asides and other factors, the vast majority of the region’s CO2
allowances are distributed to the market via quarterly public auctions. The most recent RGGI auction, conducted on December 5,
2012, cleared at the program’s floor price of $1.93 per allowance.
We are required to purchase allowances by buying them in RGGI public auctions or via the secondary market, or by
investment in qualified offsets, to cover CO2 emissions from our power plants in the RGGI region. We have also received annual
allocations from New York’s long-term contract set-aside pool to cover some of the CO2 emissions attributable to our PPAs at
both the Kennedy International Airport Power Plant and Stony Brook Power Plant. We do not anticipate any significant business
or financial impact from RGGI, given the efficiency of our power plants in RGGI states.
The original memorandum of understanding under which the states created RGGI envisioned a review of the program
after the first compliance period, which ended in 2011. The intent of the review is to assess the need for modifications to the RGGI
program design. The program review has incorporated input from the states, regulated industry, and other stakeholders, including
environmental advocacy groups. Calpine is actively participating in the process. As a result of the program review, a model rule
was issued on February 7, 2013, with a significantly lower regional emission cap. To enact this change, RGGI states must promulgate
the model rule or something substantially similar at the state level. The RGGI states have indicated a desire to incorporate the
model rule into state regulations by the end of 2013, with a new emission cap taking effect in 2014. We do not expect any material
impact to our business from this change in regulations.
Texas: NOX
Pursuant to authority granted under the CAA, regulations adopted by the TCEQ to attain the one-hour and eight-hour
NAAQS for ozone included the establishment of a Cap-and-trade program for NOX emitted by power plants in the Houston-
Galveston-Brazoria ozone nonattainment area. We own and operate seven power plants that participate in this program, all of
which received free NOX allowances based on historical operating profiles. At this time, our Houston-area power plants have
sufficient NOX allowances to meet forecasted obligations under the program.
New Jersey: NOX
New Jersey’s High Electric Demand Day (“HEDD”) Rule limits NOx emissions from turbines and boilers. Beginning in
2015, Phase 2 of the HEDD Rule will require investments in emissions controls on some of our peaking power plants. We have
provided notice to PJM that our 158 MW Deepwater Energy Center, 68 MW Cedar Energy Center and 60 MW Missouri Avenue
Energy Center will be physically unable to perform in the delivery year 2015 as a result of the HEDD Rule and that we plan to
retire the units before the commencement of the PJM Reliability Pricing Model 2015/2016 delivery year. We received PJM’s
response in May 2012 in which PJM indicated its agreement with our deactivation request provided certain planned transmission
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upgrades are completed as scheduled. In the event the transmission upgrades are not completed as planned, PJM may require one
or more of the plants to continue to operate for a period of time, but we would be entitled to full cost recovery.
We plan to install emissions controls equipment at our 73 MW Carll’s Corner Energy Center and 67 MW Mickleton
Energy Center as these power plants cleared PJM’s 2015/2016 base residual auction. Our 77 MW Middle Energy Center did not
clear PJM’s 2015/2016 base residual auction and we have provided notice to PJM of our intent to retire this unit before the
commencement of the PJM Reliability Pricing Model 2015/2016 delivery year. All six of our power plants impacted by the HEDD
Rule will be fully depreciated by June 2015. We expect that the retirement of these power plants or installation of emissions
controls will not have a material impact on our financial condition, results of operations or cash flows.
Renewable Portfolio Standards
Policymakers have been considering variations of an RPS at the federal and state level. Generally, an RPS requires each
retail seller of electricity to include in its resource portfolio (the resources procured by the retail seller to supply its retail customers)
a certain amount of power generated from renewable or clean energy resources by a certain date.
Federal RPS
Although there is currently no national RPS, President Obama has stated his goal is to have 80% of the nation’s electricity
provided from clean energy resources, which includes natural gas resources, by 2035, and some U.S. Congressional members
have expressed interest in national renewable or clean energy standard legislation. It is too early to determine whether or not the
enactment of a national RPS will have a positive or negative impact on us. Depending on the RPS structure, an RPS could enhance
the value of our existing Geysers Assets. However, an RPS would likely initially drive up the number of wind and solar resources,
which could negatively impact the dispatch of our natural gas-fired power plants, primarily in Texas and California. Conversely,
our natural gas power plants could benefit by providing complementary/back-up service for these intermittent renewable resources
or by being included in a clean energy standard.
California RPS
On April 12, 2011, California’s Governor signed into law legislation establishing a new and higher RPS. The new law
requires implementation of a 33% RPS by 2020, with intermediate targets between 2010 and 2020. The previous RPS legislation
required certain retail power providers to generate or procure 20% of the power they sell to retail customers from renewable
resources beginning in 2010. The new standard applies to all load-serving entities, including entities such as large municipal
utilities that are not subject to CPUC jurisdiction. Under the new law, there are limits on different “buckets” of procurement that
can be used to satisfy the RPS. Load-serving entities must satisfy at least a fraction of their compliance obligations with renewable
power from resources located in California or delivered into California within the hour. Similarly, the legislation places limits on
the use of “firmed and shaped” transactions and unbundled RECs – claims to the renewable aspect of the power produced by a
renewable resource that can be traded separately from the underlying power. In general, the ability to use “firmed and shaped”
transactions and unbundled RECs becomes more limited over the course of the implementation period. On December 1, 2011, the
CPUC issued a decision on intermediate RPS procurement targets between the present and 2020. On December 15, 2011, the
CPUC issued a decision clarifying exactly what transactions will fall into which bucket. In our role as an energy service provider,
we are subject to the RPS requirements and continue to meet our compliance obligations. The increase in solar and wind generation
on the state’s electrical grid has increased the need for flexible thermal generation which may be beneficial to Calpine.
Other
A number of additional states have an RPS in place. Existing state-specific RPS requirements may change due to regulatory
and/or legislative initiatives, and other states may consider implementing enforceable RPS in the future.
Other Environmental Regulations
In addition to controls on air emissions, our power plants and the equipment necessary to support them are subject to
other extensive federal, state and local laws and regulations adopted for the protection of the environment and to regulate land
use. The laws and regulations applicable to us primarily involve the discharge of emissions into the water and the use of water,
but can also include wetlands protection and preservation, endangered species, hazardous materials handling and disposal, waste
disposal and noise regulations. Noncompliance with environmental laws and regulations can result in the imposition of civil or
criminal fines or penalties. In some instances, environmental laws may also impose clean-up or other remedial obligations in the
event of a release of pollutants or contaminants into the environment. The following federal laws are among the more significant
environmental laws that apply to us. In most cases, analogous state laws also exist that may impose similar and, in some cases,
more stringent requirements on us than those discussed below. In general, our relatively clean portfolio as compared to our
competitors affords us some advantage in complying with these laws.
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Clean Water Act and Water Intake Rule
The federal Clean Water Act establishes requirements relating to the discharge of pollutants into waters of the U.S. We
are required to obtain wastewater and storm water discharge permits for wastewater and runoff, respectively, for some of our
power plants. In addition, we are required to maintain a spill prevention control and countermeasure plan with respect to some of
our natural gas-fired power plants. We believe that we are in material compliance with applicable discharge requirements of the
Clean Water Act.
Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of cooling water intake
structures reflect the best technology available for minimizing adverse environmental impact. The EPA finalized the Phase I Rule
in 2001, which applies to new facilities. The EPA initially promulgated the Phase II Rule, applying to large existing facilities, in
2004. However, the Phase II Rule was subsequently suspended and the EPA is required to finalize an updated rule applying to
existing facilities by June 27, 2013. Calpine continues to participate in the rulemaking process; however, while the Section 316
(b) rule will likely affect our competitors, we do not expect these rules to have a material impact on our operations because only
two peaking power plants we own employ once-through cooling systems, one of which (Deepwater Energy Center) is scheduled
to retire in 2015.
Additionally, the EPA is bound by a consent decree to issue a final rule to establish revised effluent limitation guidelines
for the steam electric point source category by January 31, 2014. This rule is unlikely to have a material impact on our operations.
In California, the EPA delegates the implementation of Section 316(b) to the California State Water Resources Control
Board (“SWRCB”). SWRCB has promulgated its own once-through cooling policy that establishes a schedule for once-through
cooling units to install cooling towers or reduce entrainment and impingement to comparable levels as would be achieved with a
cooling tower, or be retired. The compliance dates for approximately 12,000 MW of once-through cooling capacity in California
occur between 2012 and 2020. We do not anticipate that the SWRCB’s policy will have a negative impact on our operations, as
none of our power plants in California utilize once-through cooling systems.
Safe Drinking Water Act
Part C of the Safe Drinking Water Act establishes the underground injection control program that regulates the disposal
of wastes by means of deep well injection. Although geothermal production wells, which are wells that bring steam to the surface,
are exempt under the Energy Policy Act of 2005 (“EPAct 2005”), we use geothermal re-injection wells to inject reclaimed wastewater
back into the steam reservoir, which are subject to the underground injection control program. We believe that we are in material
compliance with Part C of the Safe Drinking Water Act.
Resource Conservation and Recovery Act
The Resource Conservation and Recovery Act (“RCRA”), regulates the management of solid and hazardous waste. With
respect to our solid waste disposal practices at our power plants and steam fields located in The Geysers region of northern
California, we are also subject to certain solid waste requirements under applicable California laws. We believe that our operations
are in material compliance with RCRA and related state laws.
On June 21, 2010, the EPA proposed a rule to regulate coal combustion residuals (“CCRs”) under RCRA. A Notice of
Data Availability (“NODA”) was issued on October 12, 2011; but, there has not been any public movement on the rule since then.
The EPA seeks to establish more stringent dam safety requirements to enhance performance surface impoundments used to manage
CCRs. The EPA also seeks to regulate disposal of CCRs and has proposed to either regulate them as hazardous waste under Subtitle
C of RCRA, or as nonhazardous waste under Subtitle D of RCRA. Both options will impose additional waste management costs
on our competitors who rely on coal as a fuel. The EPA estimates a net present value cost of $3 billion to $21 billion to coal plants.
We do not use coal so the CCRs rule, when finalized, will have no direct impact on our financial condition, results of operations
or cash flows.
Comprehensive Environmental Response, Compensation and Liability Act
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also referred to as the
Superfund, requires cleanup of sites from which there has been a release or threatened release of hazardous substances, and
authorizes the EPA to take any necessary response action at Superfund sites, including ordering potentially responsible parties
liable for the release to pay for such actions. Potentially responsible parties are broadly defined under CERCLA to include past
and present owners and operators of, as well as generators of, wastes sent to a site. As of the filing of this Report, we are not subject
to any material liability for any Superfund matters. However, we generate certain wastes, including hazardous wastes, and send
certain of our wastes to third party waste disposal sites. As a result, there can be no assurance that we will not incur a liability
under CERCLA in the future.
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Federal Litigation regarding Liability for GHG Emissions
Litigation relating to common law tort liability for GHG emissions is working its way through the federal courts. While
the U.S. Supreme Court has established that, in light of the EPA regulation of GHGs under the CAA, companies cannot be sued
under federal common law theories of nuisance and negligence for their contribution to climate change, questions remain as to
the viability of related state-law claims.
On September 21, 2009, the U.S. Court of Appeals for the Second Circuit (“Second Circuit”) issued a ruling in State of
Connecticut v. American Electric Power Company Inc., reversing a lower court’s dismissal of two public nuisance claims filed
by various states, municipalities and private entities against operators of coal-fired power plants. Plaintiffs argued that the power
plant defendants contribute to global warming by emitting 650 million tons of CO2 per year and these emissions are causing and
will continue to cause serious harm affecting human health and natural resources. The lower court held that plaintiffs’ claims
presented a non-legal political question and dismissed the complaints. The Second Circuit vacated the lower court’s decision,
ruling in favor of the plaintiffs.
The Second Circuit’s decision was appealed to the U.S. Supreme Court. On June 20, 2011, the Supreme Court issued a
decision rejecting the plaintiffs’ federal common law claim. The Court found that even if a federal common law claim could be
made by plaintiffs, the CAA essentially “displaced” that claim. The case was remanded to the Second Circuit for further
consideration of whether the plaintiffs may raise their claims under state common law or whether those claims are also preempted
by federal law. The Second Circuit remanded to the district court for additional fact-finding. On December 6, 2011, the case was
voluntarily dismissed. We cannot predict what impact the precedent of this case could have on our business.
The Supreme Court’s decision in the above matter has had significant consequences for other climate change cases,
including Native Village of Kivalina v. ExxonMobil. In Kivalina, a federal district court in California sided with the defendants
(multiple oil, energy and utility companies) against the Village of Kivalina, a small, self-governing tribe of Inupiat people who
reside north of the Arctic Circle. The residents of Kivalina had sued the defendants for damages under federal nuisance law arguing
that, as a result of global warming to which the defendants allegedly contributed, Kivalina is subject to coastal storm waves and
surges. On September 30, 2009, the court ruled in favor of the defendants, finding that the political question doctrine precluded
the court from considering the plaintiff’s federal public nuisance claim. On September 21, 2012, the U.S. Court of Appeals for
the Ninth Circuit affirmed, holding that the intervening U.S. Supreme Court case in American Electric Power militated against
judicial review of Kivalina’s claim because the CAA displaces federal common law addressing domestic GHG emissions. We
cannot predict what impact the precedent of this case could have on our business.
Power and Natural Gas Matters
Federal Regulation of Power
FERC Jurisdiction
Electric utilities have been highly regulated by the federal government since the 1930s, principally under the Federal
Power Act (“FPA”), and the U.S. Public Utility Holding Company Act of 1935. These statutes have been amended and supplemented
by subsequent legislation, including PURPA, EPAct 2005, and PUHCA 2005. These particular statutes and regulations are discussed
in more detail below.
The FPA grants the federal government broad authority over electric utilities and independent power producers, and vests
its authority in FERC. Unless otherwise exempt, any person that owns or operates facilities used for the wholesale sale or
transmission of power in interstate commerce is a public utility subject to FERC’s jurisdiction. FERC governs, among other things,
the disposition of certain utility property, the issuance of securities by public utilities, the rates, the terms and conditions for the
transmission or wholesale sale of power in interstate commerce, the interlocking directorates, and the uniform system of accounts
and reporting requirements for public utilities.
The majority of our power plants are subject to FERC’s jurisdiction; however, certain power plants qualify for available
exemptions. FERC’s jurisdiction over EWGs under the FPA applies to the majority of our power plants because they are EWGs
or are owned by EWGs, except our EWGs located in ERCOT. Power plants located in ERCOT are exempt from many FERC
regulations under the FPA. Many of our power plants that are not EWGs are operated as QFs under PURPA. Several of our affiliates
have been granted authority to engage in sales at market-based rates and blanket authority to issue securities, and have also been
granted certain waivers of FERC reporting and accounting regulations available to non-traditional public utilities; however, we
cannot assure that such authorities or waivers will not be revoked for these affiliates or will be granted in the future to other
affiliates.
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FERC has the right to review books and records of “holding companies,” as defined in PUHCA 2005, that are determined
by FERC to be relevant to the companies’ respective FERC-jurisdictional rates. We are considered a holding company, as defined
in PUHCA 2005, by virtue of our control of the outstanding voting securities of our subsidiaries that own or operate power plants
used for the generation of power for sale, or that are themselves holding companies. However, we are exempt from FERC’s books
and records inspection rights pursuant to one of the limited exemptions under PUHCA 2005 as we are a holding company due
solely to our owning one or more QFs, EWGs and Foreign Utility Companies (“FUCOs”). If any of our entities were not a QF,
EWG or FUCO, then we and our holding company subsidiaries would be subject to the books and records access requirement.
FERC’s policies and rules will continue to evolve, and FERC may amend or revise them, or may introduce new policies
or rules in the future. The impact of such policies and rules on our business is uncertain and cannot be predicted at this time.
FERC Regulation of Market-Based Rates
Under the FPA and FERC’s regulations, the wholesale sale of power at market-based or cost-based rates requires that
the seller have authorization issued by FERC to sell power at wholesale pursuant to a FERC-accepted rate schedule. FERC grants
market-based rate authorization based on several criteria, including a showing that the seller and its affiliates lack market power
in generation and transmission, that the seller and its affiliates cannot erect other barriers to market entry and that there is no
opportunity for abusive transactions involving regulated affiliates of the seller. All of our affiliates that own domestic power plants,
except for certain of those power plants that are QFs under PURPA or that are located in ERCOT, as well as our market-based
rate companies, are currently authorized by FERC to make wholesale sales of power at market-based rates.
Market-based rate authorization could possibly be revoked for any of our market-based rate companies if they fail to
continue to satisfy FERC’s current or future criteria, or if FERC eliminates or restricts the ability of wholesale sellers of power to
make sales at market-based rates. If market-based rate authority was revoked or restricted, affected power plants could be required
to make wholesale sales of power based on cost-of-service rates, which could negatively impact their revenues.
FERC’s regulations specifically prohibit the manipulation of the power markets by making it unlawful for any entity in
connection with the purchase or sale of power, or the purchase or sale of power transmission service under FERC’s jurisdiction,
to engage in fraudulent or deceptive practices.
To ward against market manipulation, FERC requires us and other sellers making sales pursuant to their market-based
rate authority to file certain reports, including quarterly reports of contract and transaction data, notices of any change in status
and triennial updated market power analyses. If a seller does not timely file these reports or notices, FERC can revoke the seller’s
market-based rate authority. FERC’s regulations also contain four market behavior rules that apply to sellers with market-based
rate authority. These rules address such matters as compliance with organized RTO or ISO market rules, communication of accurate
information, price reporting to publishers of power or natural gas price indices, and record retention. Failure to comply with these
regulations can lead to sanctions by FERC, including penalties and suspension or revocation of market-based rate authority.
FERC Regulation of Transfers of Jurisdictional Facilities
Dispositions of our jurisdictional facilities or certain types of financing arrangements may require prior FERC approval,
which could result in revised terms or impose additional costs, or cause a transaction to be delayed or terminated. Pursuant to
Section 203 of the FPA, as amended by EPAct 2005, a public utility must obtain authorization from FERC before the public utility
is permitted to: sell, lease or dispose of FERC-jurisdictional facilities with a value in excess of $10 million; merge or consolidate
facilities with those of another entity; or acquire any security or securities with a value in excess of $10 million issued by another
public utility. FERC’s prior approval is also required for transactions involving certain transfers of existing generation facilities
and certain holding companies’ acquisitions of facilities with a value in excess of $10 million. FERC’s regulations implementing
Section 203 of the FPA provide blanket authorizations for certain types of transactions, including acquisitions by holding companies
that are holding companies solely due to their ownership, directly or indirectly, of one or more QFs, EWGs and FUCOs, to acquire
additional QFs, EWGs or FUCOs, or the securities of additional QFs, EWGs and FUCOs without prior FERC approval.
FERC Regulation of Qualifying Facilities
Cogeneration and certain small power production facilities are eligible to be QFs under PURPA, provided that they meet
certain power and thermal energy production requirements, and efficiency standards. QF status provides an exemption from
PUHCA 2005 and grants certain other benefits to the QF, including, in some cases, the right to sell power to utilities at the utilities’
avoided cost (“PURPA put”). Certain types of sales by QFs are also exempt from FERC regulation of wholesale sales of the QFs’
power output. QFs are also exempt from most state laws and regulations. To be a QF, a cogeneration power plant must produce
power and useful thermal energy for an industrial or commercial process, or heating or cooling applications in certain proportions
to the power plant’s total energy output, and must meet certain efficiency standards.
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An electric utility may be relieved of the mandatory purchase obligation under the PURPA put if FERC determines that
such QFs have access to a competitive wholesale power market.
Station Power Ruling
On August 30, 2010, FERC issued an order reversing its prior rulings relating to a generator’s self-supply of station power
in the markets administered by CAISO. In the August 2010 order, the FERC concluded that it does not have jurisdiction to determine
when a generator self-supplies station power and when the generator purchases its power needs through a retail sale. The FERC
found that its jurisdiction covers only the transmission of station power and the states have exclusive jurisdiction to determine
when the use of station power results in a retail sale. Calpine and several other generators filed an appeal of the FERC’s decision.
On December 18, 2012, the D.C. Circuit issued a decision in favor of the FERC. Although the decision concerns CAISO’s treatment
of station power, the decision is applicable to all ISOs and RTOs and could result in our power plants paying more for station
power service in the future.
FERC Enforcement Authority
FERC has civil penalty authority over violations of any provision of Part II of the FPA, as well as any rule or order issued
thereunder. FERC is authorized to assess a maximum civil penalty of $1 million per violation for each day that the violation
continues. The FPA also provides for the assessment of criminal fines and imprisonment for violations under Part II of the FPA.
This penalty authority was enhanced in EPAct 2005. With this expanded enforcement authority, violations of the FPA and FERC’s
regulations could potentially have more serious consequences than in the past.
NERC Compliance Requirements
Pursuant to EPAct 2005, NERC has been certified by FERC as the Electric Reliability Organization to develop and
oversee the enforcement of electric system reliability standards applicable throughout the U.S., which are subject to FERC review
and approval. FERC-approved reliability standards may be enforced by FERC independently, or, alternatively, by NERC and the
regional reliability organizations with frontline responsibility for auditing, investigating and otherwise ensuring compliance with
reliability standards, subject to FERC oversight. Monetary penalties of up to $1 million per day per violation may be assessed for
violations of the reliability standards. Certain electric reliability standards which apply to us as a generator owner, generator
operator or marketer of power (purchasing and selling entity) are effective and mandatory. In addition, the regional reliability
organizations have the ability to formulate supplemental reliability standards to apply in their specific regions, which may be more
stringent than the NERC reliability standards. We comply with different reliability standards, requirements and procedural rules
in each region in which we operate. FERC has approved many NERC and regional reliability standards. It is expected that additional
or modified reliability standards will be approved by FERC in the coming years, requiring us to take additional steps to remain
fully compliant.
Regional and State Regulation of Power
The following summaries of the regional rules and regulations affecting our business focus on the West, Texas and North
because these are the regions in which we have the most significant portfolios of power plants. While we provide a brief overview
of the primary regional rules and regulations affecting our power plants located in other regions of the country, we do not provide
an in-depth discussion of these rules and regulations because our asset portfolio in those regions is not as significant. All power
plant and MW data is reported as of December 31, 2012.
West
We have 24 natural gas-fired power plants, including 2 under construction (1 new power plant and 1 expansion of an
existing power plant), with the capacity to generate a total of 6,026 MW in the WECC NERC region, which extends from the
Rocky Mountains westward. In addition, we own and operate 15 geothermal turbine-based power plants located in The Geysers
region of northern California capable of producing a total of 725 MW. The majority of these power plants are located in California,
in the CAISO region; however, we also own one power plant in both Arizona and Oregon.
CAISO is responsible for ensuring the safe and reliable operation of the transmission grid within the bulk of California
and providing open, nondiscriminatory transmission services. Pursuant to a FERC-approved tariff, CAISO has certain abilities to
impose penalties on market participants for violations of its rules. CAISO maintains various markets for wholesale sales of power,
differentiated by time and type of electrical service, into which our subsidiaries may sell power from time to time. These markets
are subject to various controls, such as price caps and mitigation of bids when transmission constraints arise. The controls and the
markets themselves are subject to regulatory change at any time. CAISO runs integrated day-ahead and real-time markets for
energy and ancillary services. The energy markets include centralized, day-ahead and real-time markets for energy, a nodal
transmission congestion management model that results in locational marginal pricing at each generation location, financial
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congestion hedging instruments, a centralized day-ahead commitment process and an energy bid cap of $1,000 per MWh. The
locational marginal pricing market design is intended to reward and encourage generation resources on favorable grid locations,
such as some of the locations of our power plants.
Prior to May 7, 2012, our Sutter power plant, which is a 578 MW natural gas-fired, combined-cycle power plant, had no
contracts for its output in 2012. In late 2011, we determined that the power plant will be uneconomic and may have to be shut
down absent incremental compensation. Consequently, on November 22, 2011, we submitted a request to the CAISO to compensate
us for our Sutter power plant under a provision of CAISO’s current tariff that is intended to avoid retirement of needed generating
units. Under this tariff provision, the Capacity Procurement Mechanism (“CPM”) allows the CAISO to compensate assets that
are needed in the future, but are not currently receiving sufficient revenues to sustain operation. On March 29, 2012, the CPUC
issued a resolution ordering California’s three IOUs to negotiate to enter into contracts with us and on May 7, 2012, we announced
that contracts were executed with California’s three IOUs for the purchase of resource adequacy from our Sutter power plant for
the period from July through December 2012.
The CPUC and CAISO continue to evaluate long-term capacity procurement policies and products for the California
power market. With the expectation of significant increases in renewables, both agencies are evaluating the need for generation
flexibility attributes such as dispatchability, ramping and load following. In addition, both agencies may consider forward
procurement mechanisms or obligations. In this light, the CAISO filed a request at the FERC for a backstop mechanism on
December 12, 2012, which, if approved by FERC, will allow the CAISO to look forward five years and compensate generation
units that are needed for capacity or generation attributes, but would otherwise retire. This proposal is similar to that which was
filed by the CAISO with the FERC early in 2012 in an attempt to retain our Sutter power plant. In January 2013, we protested the
CAISO filing, raising concerns with the CAISO’s approach and suggesting that a forward procurement obligation and central
capacity clearing mechanism would be superior to the CAISO’s proposal. The CPUC continues to review its resource adequacy
and long-term procurement planning and may include forward procurement in the coming months.
A recently implemented CPUC settlement changes significant aspects of policy towards California QFs, including our
non-renewable QF facilities. The settlement resolves issues related to QFs under existing QF contracts and establishes new energy
pricing options for QFs under QF contracts, including the option to shed QF host and efficiency obligations and become dispatchable,
and specifies mechanisms for the California IOUs to procure both existing combined heat and power (“CHP”) that is not otherwise
under contract and new CHP. Pursuant to the QF Settlement, we have converted two of our former QFs to dispatchable non-QF
units, and we offered some of our resources into the IOUs’ recent CHP solicitations. The IOUs selected our CHP offers for our
Los Medanos Energy Center and Gilroy Cogeneration Plant and the transactions are now awaiting regulatory approval. The impact
of the larger CHP settlement has been positive to Calpine.
Our power plants located outside of California either sell power into the markets administered by CAISO or sell power
through bilateral transactions outside CAISO. Those transactions occurring outside CAISO are subject to FERC regulation and
oversight, but they are not subject to CAISO rules and regulations.
Texas
We have 13 natural gas-fired power plants in the TRE NERC region with the capacity to generate a total of 8,014 MW,
all of which are physically located in the ERCOT market. ERCOT is the ISO that manages approximately 85% of Texas’ load and
an electric grid covering about 75% of the state, overseeing transactions associated with Texas’ competitive wholesale and retail
power markets. FERC does not regulate wholesale sales of power in ERCOT. The PUCT exercises regulatory jurisdiction over
the rates and services of any electric utility conducting business within Texas. Our subsidiaries that own power plants in Texas
have power generation company status at the PUCT, and are either EWGs or QFs and are exempt from PUCT rate regulation.
ERCOT ensures resource adequacy through an energy-only model rather than the capacity-based resource adequacy model that
is more common among RTOs or ISOs in the Eastern Interconnect. In ERCOT, there is a market price cap for energy and capacity
purchased by ERCOT. Under certain market conditions, the offer cap could be lower. Our subsidiaries are subject to the offer cap
rules, but only for sales of power and capacity services to ERCOT.
The PUCT continues its very deliberative approach of considering design changes aimed at improving the ERCOT
market’s scarcity pricing signals. Of the two rulemakings undertaken in April 2012, the project dealing with near term system-
wide offer cap (“SWOC”) resulted in the offer cap being raised from $3,000/MWh to $4,500/MWh and took effect on August 1,
2012. In October 2012, the PUCT approved other changes including raising the SWOC beginning June 1, 2013 to $5,000/MWh,
to $7,000/MWh on June 1, 2014 and finally to $9,000/MWh on June 1, 2015. In addition, the Peaker Net Margin (“PNM”) will
increase from $262,500 to $300,000 and in subsequent years it will be calculated at three-times the cost of new entry based on a
simple-cycle natural gas turbine. If the PNM is exceeded in any given year, the SWOC is automatically lowered for the remainder
of the year to the Low System Offer Cap (“LCAP”). The LCAP will change to the higher of $2,000/MWh, an increase from $500/
MWh, or 50 times the daily Houston Ship Channel natural gas price index. Given the potential liquidity impacts of possibly higher
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offer caps, ERCOT stakeholders are considering the associated market credit and collateralization design changes in an effort to
keep pace with the potential increase in the market’s risk exposure. With these changes and proposed changes, we expect higher
prices when scarcity pricing conditions occur which could have a positive impact on our Commodity Margin.
The Brattle Group’s (“Brattle”) June 1, 2012 release of its report on investment incentives and resource adequacy in the
ERCOT market laid a solid foundation for continuing deliberation by the PUCT, ERCOT and market participants on two threshold
issues. The first is whether the ERCOT region should have a mandated annual planning reserve margin or simply a reliability
reserve margin target that is allowed to float in concert with the dynamics of the current energy-only market construct. The second
threshold issue for the PUCT is to decide the best one of the five resource adequacy policy options offered by Brattle. At the
request of the PUCT, Brattle prepared two separate resource adequacy proposals for its consideration: a modified energy-only
proposal and the Texas Capacity Market, a centralized forward capacity market mechanism similar to PJM’s. Calpine filed
comments with the PUCT in support of the Texas Capacity Market concept. In addition, Brattle provided a demand response
analysis that shows how much and how quickly price responsive demand can penetrate the ERCOT market. On October 25, 2012,
the PUCT held a workshop to discuss the two Brattle proposals and received Brattle’s demand response analysis. The PUCT has
not voted on either proposal or established a timetable for further consideration of the proposals or whether to adopt a reserve
margin requirement versus continuing with the current reserve margin target. A decision from the PUCT is expected in 2013. We
continue to support the development of a centralized forward capacity market, which, depending on implementation, we view as
superior to any energy-only mechanism, to ensure ERCOT meets its reliability objective under any market conditions. As these
proceedings are ongoing, we cannot predict what the ultimate impact may be nor the impact on our financial condition, results of
operations or cash flows.
The PUCT continues to consider other proposals to improve proper wholesale price formation. At the request of the
PUCT, ERCOT has been working to develop a proposal for an operating reserves demand curve for PUCT and ERCOT stakeholder
consideration. The key feature of the proposal is a pricing methodology based on the Value of Lost Load (“VOLL”) and Loss of
Load Probability (“LOLP”). The result of this calculation is a value that is dependent on the amount of available operating reserves,
but added to the system-wide clearing price, without regard to whether the system is in scarcity conditions. It is possible some
type of operating reserves demand curve proposal could be in place by summer 2013. We support the evaluation of this concept,
but unlike a centralized forward capacity market, we do not view this concept as a solution for long-term resource adequacy in
ERCOT. We cannot predict, at this time, all of the details of a prospective proposal or the ultimate impact on our financial condition,
results of operations or cash flows.
ERCOT’s planning function has undertaken two very significant study efforts, both of which may have important
implications for the region’s resource adequacy metrics and ultimately the value of power in the ERCOT market. A Loss of Load
Expectation (“LOLE”) study has been conducted by a vendor and the final draft was delivered to stakeholders on January 18,
2013. The study will show for one occurrence of the loss of firm load in a 10-year period what annual planning reserve margin
percentage is required for resource planning. The study shows that a planning reserve margin is required that is materially greater
than the currently approved 13.75% if the experienced weather and loading patterns of the summer of 2011 are included in the
study’s model runs. Initial stakeholder reaction was to endorse the study’s methodology as well as to include the weather impacts
of summer 2011. The range of possible annual planning reserve values supported by the study that the ERCOT Board of Directors
might consider is from 15.8% to 18.9%. The study results will be further vetted with stakeholders and it is expected that the ERCOT
Board of Directors could take action in changing the annual planning reserve margin at its March 2013 meeting. The second study
effort will estimate the VOLL. That study is expected to be completed in mid-2013 and should provide meaningful estimates for
the value of firm customer load in the various load categories when firm load shedding is necessary in emergency conditions. The
current SWOC is $4,500/MWh and will escalate to $9,000/MWh in 2015, as discussed above, and the VOLL study may shed
some light on whether the SWOC is high enough to approximate the VOLL.
ERCOT implemented a nodal market structure on December 1, 2010. A nodal market structure results in locational
marginal pricing at each generation location rather than establishing pricing in four zones as was done prior to December 1, 2010.
The implementation costs for the ERCOT central operating systems for nodal were paid by generating resources through a MWh-
based surcharge. The Nodal Implementation Surcharge was levied at a rate of $0.375/MWh of all energy generated and was
terminated in January 2013 with the retirement of the debt coverage of ERCOT’s nodal costs.
The Sunset Review Process, implemented by the Texas Legislature in 1977, is the regular assessment of the need for a
state agency to exist and to consider new and innovative changes to improve each agency’s operations and activities. The Sunset
Review Process works by setting a date on which an agency will be abolished unless legislation is passed to continue its functions.
While significant changes were proposed by the Sunset Advisory Commission, the legislation did not become law. Therefore, the
Sunset Advisory Commission has undertaken another review of these agencies and any resulting legislation will be considered in
the 2013 legislative session. We cannot predict which changes, if any, will be placed into legislation and ultimately reach final
passage. We will continue to participate in these processes where we anticipate any potential impact on our business.
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North
regions.
We have a total of 30 power plants with 7,320 MW of peaking capacity located in the RFC, NPCC and MRO NERC
We have 19 operating power plants with the capacity to generate a total of 4,491 MW in Eastern PJM. In addition, we
have one operating power plant, with the capacity to generate 503 MW, located in Western PJM. Eastern PJM and Western PJM
are both located in the RFC NERC region. PJM operates wholesale power markets, a locationally based capacity market, a forward
capacity market and ancillary service markets. PJM also performs transmission planning for the region.
Certain states in the PJM market region, particularly New Jersey and Maryland, have taken actions that could impact the
PJM capacity market. In New Jersey, legislation enacted in 2011 required the New Jersey Board of Public Utilities (“BPU”) to
issue a request for proposals (“RFP”) for new generation. As a result of the RFP, the BPU directed New Jersey’s four public utilities
to enter into standard offer capacity agreements with the winning generators for new capacity to be built in New Jersey. Several
entities have appealed the BPU’s order directing the public utilities to enter into long-term contracts with those generators. The
appeal process is continuing. Also, on February 9, 2011, we joined a group of generators and utilities in filing a complaint in
federal district court challenging the constitutionality of the New Jersey legislation. On September 28, 2012, the judge in the
proceeding denied all Motions for Summary Judgment. Discovery is continuing with a trial expected to be held in late March to
early April 2013.
On September 29, 2011, the Maryland Public Service Commission (“MPSC”) issued a “Notice of Approval of Request
for Proposals for New Generation to be Issued by Maryland Electric Distribution Companies” (the “Notice”). The Notice required
the state’s IOUs to issue RFPs for up to 1,500 MW of capacity. The Notice specifies that proposals must be for new natural gas-
fired capacity capable of delivery into the PJM Southwest Mid-Atlantic Area Council (“SWMAAC”) delivery area. On April 12,
2012, the MPSC issued a further order in this proceeding directing certain Maryland IOUs located in the SWMAAC area to enter
into a contract for differences with CPV Maryland, LLC (“CPV”), a generation developer that is currently developing a 661 MW
natural gas-fired, combined-cycle generation plant in SWMAAC. The facility’s scheduled COD is June 1, 2015. In May 2012,
we filed with the Circuit Court of Baltimore County, Maryland a Petition for Review of the MPSC’s order, asking the court to
review the order and declare it invalid. Several other parties filed similar appeals. The appeals have been consolidated, but the
case has been suspended pending resolution of certain terms in the contracts between the IOUs and CPV. In a separate action,
several generators have filed a complaint in federal district court challenging the constitutionality of the MPSC’s actions. That
case is expected to go to trial in late February 2013.
At the FERC level, PJM has taken action to strengthen the Minimum Offer Price Rule (“MOPR”) in its tariff. PJM’s
tariff changes are intended to address the negative implications from these state actions. The FERC issued an order in April 2011
approving amendments to PJM’s MOPR tariff provisions. The FERC order is currently on appeal before the U.S. Court of Appeals
for the Third Circuit. In December 2012, PJM filed further amendments to the MOPR that are intended to make the MOPR process
more transparent and objective. On February 5, 2013, the FERC asked PJM to provide additional information about its proposal.
While unclear, given the current timing of PJM’s response and a subsequent FERC decision, it is still possible for the changes to
be in effect for the 2016/2017 PJM Reliability Pricing Model base residual auction, to be held on May 13-17, 2013.
We have a total of eight natural gas-fired power plants with the capacity to generate a total of 1,448 MW in the NPCC
NERC region. Five of these power plants are located in New York. NYISO manages the transmission system in New York and
operates the state’s wholesale power markets. NYISO manages both day-ahead and real-time energy markets using a locationally
based marginal pricing mechanism that pays each generator the zonal marginally accepted bid price for the energy it produces.
Our remaining U.S.-based power plant in the NPCC NERC region is located in Maine. ISO-NE is the RTO for Connecticut,
Maine, Massachusetts, New Hampshire, Rhode Island and Vermont. ISO-NE has broad authority over the day-to-day operation
of the transmission system and operates a day-ahead and real-time wholesale energy market, a forward capacity market and
ancillary services markets. ISO-NE also provides for regional transmission planning.
We also have 50% ownership interests in two Canadian power plants, with the total capacity to generate 1,088 MW (544
MW net attributable to Calpine), located in the NPCC NERC region in Ontario, Canada. The Whitby cogeneration facility is a 50
MW facility located in Whitby, Ontario and the Greenfield Energy Centre is a 1,038 MW facility located in Courtright, Ontario.
The Independent Electricity System Operator (“IESO”) of Ontario operates the Province’s wholesale power markets and directs
the operation and ensures reliability of the IESO controlled grid. Hydro-One owns and operates the transmission system in Ontario,
which is regulated by the Ontario Energy Board.
We have two natural gas-fired power plants with the capacity to generate a total of 878 MW operating within the MRO
NERC region. MISO manages competitive locationally based wholesale day-ahead, real-time energy and ancillary services markets.
MISO’s Resource Adequacy model requires load serving entities to account for capacity obligations under Module E of the MISO
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tariff. MISO currently conducts a monthly voluntary capacity auction to help purchasers find suppliers with capacity to meet their
incremental capacity needs. In 2013, MISO will complete a transition to a new capacity market design. Among other things, the
new design will move MISO from a monthly capacity product to an annual capacity product, and implement annual auctions,
although market participation will remain voluntary for all load-serving entities. We do not believe that this new market design
will have a material impact on our business.
Southeast
We have one operating natural gas-fired power plant with the capacity to generate 1,134 MW located in the SPP NERC
region. SPP is an RTO approved by FERC that provides independent administration of the electric power grid. SPP currently
manages an energy-only location based real-time wholesale energy market. This market provides both nominal load-following
and transmission constraint relief. In October 2012, the FERC approved tariff changes to enact SPP’s proposed “Day 2” wholesale
energy markets. SPP, which currently conducts a basic real-time nodal balancing market, will expand its market to a suite of new
markets that will include centralized, security-constrained economic unit commitment with both a financially-binding, day-ahead
nodal energy market and a physically-binding, real-time nodal energy market, a congestion management market using Transmission
Congestion Rights, consolidate existing Balancing Areas and implement ancillary services markets for regulation and reserves.
SPP will also have the authority to commit generation for reliability purposes and guarantee cost recovery for such units that are
otherwise uneconomic. SPP will also have virtual load and generation markets that will permit hedging and speculation and plans
to accommodate demand-side resource market participation. SPP did not propose any type of resource adequacy or capacity market
in its new market design. We believe the market structure is generally beneficial to our Oneta Energy Center which is located in
the SPP region.
We have nine natural gas-fired power plants with the capacity to generate a total of 4,102 MW operating within the SERC
and the FRCC NERC regions. Opportunities to negotiate bilateral, individual contracts and long-term transactions with IOUs,
municipalities and cooperatives exist within these regions. In addition to entering into bilateral transactions, there is a limited
opportunity to sell into the short-term market.
In the Entergy sub-region, MISO has replaced SPP as the designated Independent Coordinator of Transmission. In this
capacity, the Independent Coordinator of Transmission provides oversight of the Entergy transmission system. Entergy and MISO
continue to move forward with their proposal to transfer functional control of Entergy’s transmission system to MISO by December
2013. Entergy has received conditional approvals for change of control applications filed with the Arkansas Public Service
Commission, the City of New Orleans, the Louisiana Public Service Commission, the Mississippi Public Service Commission,
and the PUCT. We support Entergy membership in an RTO as soon as possible.
Other State Regulation of Power
State Public Utility Commissions, or PUC(s), have historically had broad authority to regulate both the rates charged by,
and the financial activities of, electric utilities operating in their states and to promulgate regulation for implementation of PURPA.
Since all of our affiliates are either QFs or EWGs, none of our affiliates are currently subject to direct rate regulation by a state
PUC. However, states may assert jurisdiction over the siting and construction of power generating facilities including QFs and
EWGs and, with the exception of QFs, over the issuance of securities and the sale or other transfer of assets by these facilities. In
California, for example, the CPUC was required by statute to adopt and enforce maintenance and operation standards for power
plants “located in the state,” including EWGs but excluding QFs, for the purpose of ensuring their reliable operation. As the owner
and operator of power plants in California, our subsidiaries are subject to the power plant maintenance and operation standards
and the general duty standards that are enforced by the CPUC.
State PUCs also maintain extensive control over the procurement of wholesale power by the utilities that they regulate.
Many of these utilities are our customers, and agreements between us and these counterparties often require approval by state
PUCs. For example, in California, the CPUC determines how much new generation can be purchased by the IOUs, and shapes
the rules of the IOUs’ requests for offers. In addition, the CPUC determines the rules of California’s Resource Adequacy program.
The Resource Adequacy program is currently based on a loosely structured year- and month-ahead bilateral capacity market.
Regulation of Transportation and Sale of Natural Gas
Since the majority of our power generating capacity is derived from natural gas-fired power plants, we are broadly
impacted by federal regulation of natural gas transportation and sales. Furthermore, our two natural gas transportation pipelines
in Texas are subject to dual jurisdiction by the FERC and the Texas Railroad Commission. These pipelines are intrastate pipelines
within the meaning of Section 2(16) of the Natural Gas Policy Act (“NGPA”). FERC regulates the rates charged by these pipelines
for transportation services performed under Section 311 of the NGPA, and the Texas Railroad Commission regulates the rates and
services provided by these pipelines as gas utilities in Texas.
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We also operate a proprietary pipeline system in California, which is regulated by the U.S. Department of Transportation
and the Pipeline and Hazardous Materials Safety Administration with regard to safety matters. Additionally, some of our power
plants own and operate short pipeline laterals that connect the natural gas-fired power plants to the North American natural gas
grid. Some of these laterals are subject to state and/or federal safety regulations.
Under the Natural Gas Act (“NGA”), the NGPA and the Outer Continental Shelf Lands Act, the FERC is authorized to
regulate pipeline, storage and liquefied natural gas, or LNG, facility construction; the transportation of natural gas in interstate
commerce; the abandonment of facilities; and the rates for services. The FERC is also authorized under the NGA to regulate the
sale of natural gas at wholesale.
The FERC has civil penalty authority for violations of the NGA and NGPA, as well as any rule or order issued thereunder.
The FERC’s regulations specifically prohibit the manipulation of the natural gas markets by making it unlawful for any entity in
connection with the purchase or sale of natural gas, or the purchase or sale of transportation service under the FERC’s jurisdiction,
to engage in fraudulent or deceptive practices. Similar to its penalty authority under the FPA described above, the FERC is authorized
to assess a maximum civil penalty of $1 million per violation for each day that the violation continues. The NGA and NGPA also
provide for the assessment of criminal fines and imprisonment time for violations.
Federal Regulation of Futures and Other Derivatives
CFTC Regulation of Futures Transactions
The CFTC has regulatory oversight of the futures markets, including trading on NYMEX for energy, and licensed futures
professionals such as brokers, clearing members and large traders. In connection with its oversight of the futures markets and
NYMEX, the CFTC regularly investigates market irregularities and potential manipulation of those markets. Recent laws also
give the CFTC certain powers with respect to broker-type markets referred to as “exempt commercial markets” or ECMs, including
the Intercontinental Exchange. The CFTC monitors activities in the OTC, ECM and physical markets that may be undertaken for
the purpose of influencing futures prices. With respect to ECMs, the CFTC exercises only light-handed regulation primarily related
to trade reporting, price dissemination and record retention (including retention of fraudulent claims and allegations). Thus,
transactions executed on an ECM generally are not regulated directly by the CFTC. However, the CFTC may make special calls
of market participants in the ECM and ECM transactions have come under the CFTC’s scrutiny during investigations of fraud
and manipulation in which the CFTC has broadly applied its statutory authority to punish persons who are alleged to have
manipulated, or attempted to manipulate, the price of any commodity in interstate commerce or for future delivery. Moreover,
while ECM transactions are not required to be cleared, if they are cleared, such cleared ECM transactions would be subject to
regulation by the CFTC. We also expect the CFTC’s powers and oversight to be increased by the Dodd-Frank Act. However, as
discussed below, the extent of such increased powers and oversight, and its effect on ECM transactions, if any, is not yet certain.
The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
CFTC Regulation of Derivatives Transactions
The Dodd-Frank Act, which was signed into law on July 21, 2010, contains a variety of provisions designed to regulate
financial markets, including credit and derivatives transactions. Title VII of the Dodd-Frank Act addresses regulatory reform of
the OTC derivatives market in the U.S. and significantly changes the regulatory framework of this market. Certain Title VII
regulations have been finalized and are effective though some regulations remain subject to a delayed compliance schedule. Other
key regulations have not been finalized as of this time or remain in draft form. Until all of these regulations have been finalized,
the extent to which the provisions of Title VII might affect our derivatives activities cannot be completely known. A number of
features in the legislation may impact our existing business. One of these is the requirement for central clearing of many OTC
derivative transactions with clearing organizations. Moreover, whereas our OTC transactions have traditionally been negotiated
on a bilateral basis, including the collateral arrangements thereunder, they now may be subject to the collateral and margining
procedures of the clearing organization. Certain end-users may be able to benefit from an exception which would exempt them
from mandatory clearing requirements. If the derivatives transactions which we enter into are determined to be subject to mandatory
clearing requirements, we will seek to comply with the regulatory requirements in order to benefit from the end-user exception.
Uncleared OTC derivatives transactions under the Dodd-Frank Act will also be subject to collateral and margining procedures
established by CFTC regulation. These Title VII regulations have not, as of the date of this Report, been finalized. Other features
of the Dodd-Frank Act which will have an impact on our derivative activities include trade reporting and trade execution. The
effect of the Dodd-Frank Act on traditional dealers and market-makers as well as the consequential effect on market liquidity and,
hence, pricing is uncertain. Nevertheless, we expect to be able to continue to participate in financial markets for our derivative
transactions.
Some of the key regulatory rulemakings regarding the definition of specific entity designations and the swap definition
rules for the Dodd-Frank Act were finalized in the second and third quarters of 2012. The CFTC also recently issued several no-
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action letters, interpretations and an exemptive order impacting the implementation schedule and interpretations of key provisions
in the CFTC’s Dodd-Frank Act implementation rules. We have reviewed our derivative activities over a one month survey period,
as a proxy for future activity, and our intended future activities, and have determined that we are not a swap dealer as defined
under the CFTC’s final entity definition rule and, therefore, are not required to register as a swap dealer. We have established an
internal working group for a thorough and ongoing evaluation of the impact and timing of these recent rulemakings on our operations
as a non-swap dealer; however, it is difficult to fully assess the ultimate impact of the Dodd-Frank Act on us until all rulemakings
are finalized and implemented.
While we are closely monitoring this rulemaking process from the CFTC (including related no-action relief, interpretations
and orders), we have reviewed and assessed the impact of the CFTC’s Title VII regulations on our business and related processes,
and we have adjusted our internal procedures where necessary to comply with the applicable statutory law and related Title VII
regulations which are effective at this time. We will continue to monitor all relevant developments and rulemaking initiatives, and
we expect to successfully implement any new applicable requirements. At this time, we cannot predict the impact or possible
additional costs to us related to the implementation of, or compliance with, the potential future requirements under the Dodd-
Frank Act.
Other provisions
The Dodd-Frank Act also requires regulatory agencies, including the SEC, to establish regulations for implementation
of many of the provisions of the Dodd-Frank Act. In August 2012, 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, 2013 (i.e. beginning
with our fiscal year ending December 31, 2013). For calendar year end companies, like Calpine, the initial information reporting
period runs from October 1, 2013 through December 31, 2013, and must be provided to the SEC by May 30, 2014. Our report
will include information about 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.
The Dodd-Frank Act contains provisions to improve transparency and accountability concerning the supply of certain
minerals, known as conflict minerals (namely tin, tantalum, tungsten or gold), originating from the conflict zones of the Democratic
Republic of Congo (“DRC”) and adjoining countries. In August 2012, as mandated by the Dodd-Frank Act, the SEC adopted final
rules requiring all issuers that file reports with the SEC to report, on an annual basis, supply chain and sourcing information for
companies that use conflict minerals mined from the DRC and adjoining countries in their products. These new requirements will
require due diligence efforts in fiscal 2013, with initial disclosure requirements beginning in May 2014. Based on our preliminary
analysis, we do not believe that any of our products contain conflict minerals; however, our assessment process to determine
whether conflict minerals are necessary to the functionality or production of any of our products is not complete.
Geothermal Operations
The focus on induced seismicity caused by hydro-fracturing associated with natural gas and geothermal exploration and
production could cause government entities or agencies to more stringently regulate that activity and such regulation could impact
the exploration, development and operation of geothermal power plants, including our Geysers Assets.
EMPLOYEES
At December 31, 2012, we employed 2,151 full-time employees, of whom 158 were represented by collective bargaining
agreements. We have 103 employees represented by collective bargaining agreements which expire within one year. We have
never experienced a work stoppage or strike.
Item 1A. Risk Factors
Commercial Operations
Our financial performance is impacted by price fluctuations in the wholesale power and natural gas markets and other
market factors that are beyond our control.
Market prices for power, generation capacity, ancillary services, natural gas and fuel oil are unpredictable and fluctuate
substantially. Unlike most other commodities, power can only be stored on a very limited basis and generally must be produced
concurrently with its use. As a result, power prices are subject to significant volatility due to supply and demand imbalances,
especially in the day-ahead and spot markets. Long- and short-term power and natural gas prices may also fluctuate substantially
due to other factors outside of our control, including:
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increases and decreases in generation capacity in our markets, including the addition of new supplies of power as a
result of the development of new power plants, expansion of existing power plants or additional transmission capacity;
changes in power transmission or fuel transportation capacity constraints or inefficiencies;
power supply disruptions, including power plant outages and transmission disruptions;
• Heat Rate risk;
• weather conditions;
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quarterly and seasonal fluctuations;
coal prices;
changes in the demand for power or in patterns of power usage, including the potential development of demand-side
management tools and practices;
development of new fuels or new technologies for the production or storage of power;
federal and state regulations and actions of the ISOs;
federal and state power, market and environmental regulation and legislation, including mandating an RPS or creating
financial incentives, each resulting in new renewable energy generation capacity creating oversupply;
changes in prices related to RECs; and
changes in capacity prices and capacity markets.
These factors have caused our operating results to fluctuate in the past and will continue to cause them to do so in the
future.
Our revenues and results of operations depend on market rules, regulation and other forces beyond our control.
Our revenues and results of operations are influenced by factors that are beyond our control, including:
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rate caps, price limitations and bidding rules imposed by ISOs, Regional Transmission Organizations and other
market regulators that may impair our ability to recover our costs and limit our return on our capital investments;
regulations promulgated by the FERC and the CFTC;
sufficient liquidity in the forward commodity markets to conduct our hedging activities;
some of our competitors (mainly utilities) receive entitlement-guaranteed rates of return on their capital investments,
with returns that exceed market returns and may impact our ability to sell our power at economical rates;
structure and operating characteristics of our capacity markets such as our PJM capacity auctions and our NYISO
markets; and
regulations and market rules related to our RECs.
Accounting for our hedging activities may increase the volatility in our quarterly and annual financial results.
We engage in commodity-related marketing and price-risk management activities in order to economically hedge our
exposure to market risk with respect to power sales from our power plants, fuel utilized by those assets and emission allowances.
We generally attempt to balance our fixed-price physical and financial purchases, and sales commitments in terms of contract
volumes and the timing of performance and delivery obligations through the use of financial and physical derivative contracts.
These derivatives are accounted for under U.S. GAAP, which requires us to record all derivatives on the balance sheet at fair value
unless they qualify for, and we elect, the normal purchase normal sale exemption. In order to simplify our reporting, we elected
to discontinue the application of hedge accounting treatment during the first quarter of 2012 for all commodity derivatives, including
the remaining commodity derivatives previously accounted for as cash flow hedges. Accordingly, prospective changes in fair value
from the date of this election are reflected in unrealized mark-to-market activity on our Consolidated Statements of Operations
and could create more volatility in our earnings. The fair value of our commodity derivative instruments residing in AOCI during
the previous application of hedge accounting was reclassified to earnings during 2012 as the related economic transactions affected
earnings or the forecasted transaction became probable of not occurring. As a result, we are unable to accurately predict the impact
that our risk management decisions may have on our quarterly and annual financial results.
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The use of hedging agreements may not work as planned or fully protect us and could result in financial losses.
We typically enter into hedging agreements, including contracts to purchase or sell commodities at future dates and at
fixed prices, in order to manage our commodity price risks. These activities, although intended to mitigate price volatility, expose
us to other risks. When we sell power forward, we may be required to post significant amounts of cash collateral or other credit
support to our counterparties, and we give up the opportunity to sell power at higher prices if spot prices are higher in the future.
Further, if the values of the financial contracts change in a manner that we do not anticipate, or if a counterparty fails to perform
under a contract, it could harm our financial condition, results of operations and cash flows.
We do not typically hedge the entire exposure of our operations against commodity price volatility. To the extent we do
not hedge against commodity price volatility, our financial condition, results of operations and cash flows may be diminished
based upon adverse movement in commodity prices.
Our ability to enter into hedging agreements and manage our counterparty credit risk could adversely affect us.
Our customer and supplier counterparties may experience deteriorating credit. These conditions could cause
counterparties in the natural gas and power markets, particularly in the energy commodity derivative markets that we rely on for
our hedging activities, to withdraw from participation in those markets. If multiple parties withdraw from those markets, market
liquidity may be threatened, which in turn could adversely impact our business and create more volatility in our earnings.
Additionally, these conditions may cause our counterparties to seek bankruptcy protection under Chapter 11 or liquidation under
Chapter 7 of the Bankruptcy Code. Our credit risk may be exacerbated to the extent collateral held by us cannot be realized or is
liquidated at prices not sufficient to recover the full amount of the exposure due to us. There can be no assurance that any such
losses or impairments to the carrying value of our financial assets would not materially and adversely affect our financial condition,
results of operations and cash flows.
Competition could adversely affect our performance.
The power generation industry is characterized by intense competition, and we encounter competition from utilities,
industrial companies, marketing and trading companies and other independent power producers. In addition, many states are
implementing or considering regulatory initiatives designed to increase competition in the domestic power industry. This
competition has put pressure on power utilities to lower their costs, including the cost of purchased power, and increasing
competition in the supply of power in the future could increase this pressure. In addition, construction during the last decade has
created excess power supply and higher reserve margins in the power trading markets, putting downward pressure on prices.
In certain situations, our PPAs and other contractual arrangements, including construction agreements, commodity
contracts, maintenance agreements and other arrangements, may be terminated by the counterparty and/or may allow the
counterparty to seek liquidated damages.
The situations that could allow a counterparty to terminate the contract and/or seek liquidated damages include:
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the cessation or abandonment of the development, construction, maintenance or operation of a power plant;
failure of a power plant to achieve construction milestones or commercial operation by agreed-upon deadlines;
failure of a power plant to achieve certain output or efficiency minimums;
our failure to make any of the payments owed to the counterparty or to establish, maintain, restore, extend the term
of or increase any required collateral;
failure of a power plant to obtain material permits and regulatory approvals by agreed-upon deadlines;
a material breach of a representation or warranty or our failure to observe, comply with or perform any other material
obligation under the contract; or
events of liquidation, dissolution, insolvency or bankruptcy.
Revenue may be reduced significantly upon expiration or termination of our PPAs.
Some of the capacity from our existing portfolio is sold under long-term PPAs that expire at various times. We seek to
sell any capacity not sold under long-term PPAs, on a short-term basis as market opportunities arise. Our uncontracted capacity
is generally sold on the spot market at current market prices as merchant energy. When the terms of each of our various PPAs
expire, it is possible that the price paid to us for the generation of power under subsequent arrangements or in short term markets
may be significantly less than the price that had been paid to us under the PPA. Power plants without long-term PPAs involve risk
and uncertainty in forecasting future demand load for merchant sales because they are exposed to market fluctuations for some
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or all of their generating capacity and output. A significant under- or over-estimation of load requirements may increase our
operating costs. Without the benefit of long-term PPAs, we may not be able to sell any or all of the capacity from these power
plants at commercially attractive rates and these power plants may not be able to operate profitably. Certain of our PPAs have
values in excess of current market prices. We are at risk of loss of margins to the extent that these contracts expire or are terminated
and we are unable to replace them on comparable terms. Additionally, our PPAs contain termination provisions standard to contracts
in our industry such as negligence, performance default or prolonged events of force majeure.
An economic downturn could result in a reduction in our revenue and operating cash flows or result in our customers,
counterparties, vendors or other service providers failing to perform under their contracts with us.
To the extent that an economic downturn returns and affects the markets in which we operate, demand for power and
power prices may be depressed, and our revenues and operating cash flows could be negatively impacted. In addition, challenges
affecting the economy could cause our customers, counterparties, vendors and service providers to experience deteriorating credit
and serious cash flow problems. As a result, these conditions could cause counterparties in the natural gas and power markets,
particularly in the energy commodity derivative markets that we rely on for our hedging activities, to be unable to perform under
existing contracts, or to withdraw from participation in those markets. If multiple parties withdraw from those markets, market
liquidity may be threatened, which in turn could adversely impact our business. Additionally, these conditions may cause our
counterparties to seek bankruptcy protection under Chapter 11 or liquidation under Chapter 7 of the Bankruptcy Code.
Power Operations
Our power generating operations performance involves significant risks and hazards and may be below expected levels of
output or efficiency.
The operation of power plants involves risks, including the breakdown or failure of power generation equipment,
transmission lines, pipelines or other equipment or processes, performance below expected levels of output or efficiency and risks
related to the creditworthiness of our contract counterparties and the creditworthiness of our counterparties’ customers or other
parties, such as steam hosts, with whom our counterparties have contracted. From time to time our power plants have experienced
unplanned outages, including extensions of scheduled outages due to equipment breakdowns, failures or other problems and are
an inherent risk of our business. Unplanned outages typically can result in lost revenues, increase our maintenance expenses and
may reduce our profitability, which could have a material adverse effect on our financial condition, results of operations and cash
flows.
In addition, an unplanned outage may prevent the affected power plant from performing under any applicable PPAs,
commodity contracts or other contractual arrangements. Such failure may allow a counterparty to terminate an agreement and/or
seek liquidated damages, and we could incur costs to cover our hedges. Although insurance is maintained to partially protect
against operating risks, the proceeds of insurance may not be adequate to cover lost revenues or increased expenses. As a result,
we could be unable to service principal and interest payments under, or may otherwise breach, our financing obligations, particularly
with respect to the affected power plant, which could result in losing our interest in the affected power plant or, possibly, one or
more other power plants.
We may be subject to future claims, litigation and enforcement.
Our power generating operations are inherently hazardous and may lead to catastrophic events, including loss of life,
personal injury and destruction of property, and subject us to litigation. Natural gas is highly explosive and power generation
involves hazardous activities, including acquiring, transporting and delivering fuel, operating large pieces of rotating equipment
and delivering power to transmission and distribution systems. These and other hazards can cause severe damage to and destruction
of property, plant and equipment and suspension of operations. In the worst circumstances, catastrophic events can cause significant
personal injury or loss of life. Further, the occurrence of any one of these events may result in us being named as a defendant in
lawsuits asserting claims for substantial damages. We maintain an amount of insurance protection that we consider adequate;
however, we cannot provide any assurance that the insurance will be sufficient or effective under all circumstances and against
all hazards or liabilities to which we are subject.
Additionally, we are party to various litigation matters, including regulatory and administrative proceedings arising out
of the normal course of business. 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 have determined an unfavorable outcome is
probable and is reasonably estimable, we have accrued for potential litigation losses. A successful claim against us that is not fully
insured could be material. 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. 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
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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. See also Note 15 of the Notes to Consolidated Financial Statements
for a description of our more significant litigation matters.
We rely on power transmission and fuel distribution facilities owned and operated by other companies.
We depend on facilities and assets that we do not own or control for the transmission to our customers of the power
produced by our power plants and the distribution of natural gas fuel or fuel oil to our power plants. If these transmission and
distribution systems are disrupted or capacity on those systems is inadequate, our ability to sell and deliver power products or
obtain fuel may be hindered. ISOs that oversee transmission systems in regional power markets have imposed price limitations
and other mechanisms to address volatility in their power markets. Existing congestion, as well as expansion of transmission
systems, could affect our performance, which in turn could adversely impact our business.
Our power project development and construction activities involve risk and may not be successful.
The development and construction of power plants is subject to substantial risks. In connection with the development of
a power plant, we must generally obtain:
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necessary power generation equipment;
governmental permits and approvals including environmental permits and approvals;
fuel supply and transportation agreements;
sufficient equity capital and debt financing;
power transmission agreements;
• water supply and wastewater discharge agreements or permits; and
•
site agreements and construction contracts.
To the extent that our development and construction activities continue or expand, we may be unsuccessful on a timely
and profitable basis. Although we may attempt to minimize the financial risks of these activities by securing a favorable PPA and
arranging adequate financing prior to the commencement of construction, the development of a power project may require us to
expend significant cash sums for preliminary engineering, permitting, legal and other expenses before we can determine whether
a project is feasible, economically attractive or financeable. The process for obtaining governmental permits and approvals is
complicated and lengthy, often taking more than one year, and is subject to significant uncertainties. We may be unable to obtain
all necessary licenses, permits, approvals and certificates for proposed projects, and completed power plants may not comply with
all applicable permit conditions, statutes or regulations. In addition, regulatory compliance for the construction and operation of
our power plants can be a costly and time-consuming process. Intricate and changing environmental and other regulatory
requirements may necessitate substantial expenditures to obtain and maintain permits. If a project is unable to function as planned
due to changing requirements, loss of required permits or regulatory status or local opposition, it may create expensive delays,
extended periods of non-operation or significant loss of value in a project resulting in potential impairments.
We may be unable to obtain an adequate supply of fuel in the future.
We obtain substantially all of our physical natural gas and fuel oil supply from third parties pursuant to arrangements
that vary in term, pricing structure, firmness and delivery flexibility. Our physical natural gas and fuel oil supply arrangements
must be coordinated with transportation agreements, balancing agreements, storage services, financial hedging transactions and
other contracts so that the natural gas and fuel oil is delivered to our power plants at the times, in the quantities and otherwise in
a manner that meets the needs of our generation portfolio and our customers. We must also comply with laws and regulations
governing natural gas transportation.
While adequate supplies of natural gas and fuel oil are currently available to us at prices we believe are reasonable for
each of our power plants, we are exposed to increases in the price of natural gas and fuel oil, and it is possible that sufficient
supplies to operate our portfolio profitably may not continue to be available to us. In addition, we face risks with regard to the
delivery to and the use of natural gas and fuel oil by our power plants including the following:
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transportation may be unavailable if pipeline infrastructure is damaged or disabled;
pipeline tariff changes may adversely affect our ability to, or cost to, deliver natural gas and fuel oil supply;
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third-party suppliers may default on natural gas supply obligations, and we may be unable to replace supplies currently
under contract;
• market liquidity for physical natural gas and fuel oil or availability of natural gas and fuel oil services (e.g. storage)
may be insufficient or available only at prices that are not acceptable to us;
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natural gas and fuel oil quality variation may adversely affect our power plant operations;
our natural gas and fuel oil operations capability may be compromised due to various events such as natural disaster,
loss of key personnel or loss of critical infrastructure;
fuel supplies diverted to residential heating for humanitarian reasons; and
any other reasons.
Our power plants and construction projects are subject to impairments.
If we were to experience a significant reduction in our expected revenues and operating cash flows for an extended period
of time from a prolonged economic downturn or from advances or changes in technologies, we could experience future impairments
of our power plant assets as a result. There can be no assurance that any such losses or impairments to the carrying value of our
financial assets would not have a material adverse impact our financial condition, results of operations and cash flows.
Our geothermal power reserves may be inadequate for our operations.
In connection with each geothermal power plant, we estimate the productivity of the geothermal resource and the expected
decline in productivity. The productivity of a geothermal resource may decline more than anticipated, resulting in insufficient
reserves being available for sustained generation of the power capacity desired. In addition, we may not be able to successfully
manage the development and operation of our geothermal reservoirs or accurately estimate the quantity or productivity of our
steam reserves. An incorrect estimate or inability to manage our geothermal reserves or a decline in productivity could adversely
affect our results of operations or financial condition. In addition, the development and operation of geothermal power resources
are subject to substantial risks and uncertainties. The successful exploitation of a geothermal power resource ultimately depends
upon many factors including the following:
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the heat content of the extractable steam or fluids;
the geology of the reservoir;
the total amount of recoverable reserves;
operating expenses relating to the extraction of steam or fluids;
price levels relating to the extraction of steam, fluids or power generated; and
capital expenditure requirements relating primarily to the drilling of new wells.
Significant events beyond our control, such as natural disasters or acts of terrorism, could damage our power plants or our
corporate offices and may impact us in unpredictable ways.
Certain of our geothermal and natural gas-fired power plants, particularly in the West, are subject to frequent low-level
seismic disturbances. More significant seismic disturbances are possible. In addition, other areas in which we operate, particularly
in Texas and the Southeast, experience tornados and hurricanes. Similarly, operations at our corporate offices in Houston, Texas
could be substantially affected by a hurricane. Such events could damage or shut down our power plants, power transmission or
the fuel supply facilities upon which our generation business is dependent. Our existing power plants are built to withstand relatively
significant levels of seismic and other disturbances, and we believe we maintain adequate insurance protection. However,
earthquake, property damage or business interruption insurance may be inadequate to cover all potential losses sustained in the
event of serious damages or disturbances to our power plants or our operations due to natural disasters.
In addition to physical damage to our power plants, the risk of future terrorist activity could result in adverse changes in
the insurance markets and disruptions in the power and fuel markets. These events could also adversely affect the U.S. economy,
create instability in the financial markets and, as a result, have an adverse effect on our ability to access capital on terms and
conditions acceptable to us.
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We depend on our management and employees.
Our success is largely dependent on the skills, experience and efforts of our people. The loss of the services of one or
more members of our senior management or of numerous employees with critical skills could have a negative effect on our business,
financial condition and results of operations and future growth if we were unable to replace them.
Some of our employees are represented by collective bargaining agreements.
We have 158 employees represented by collective bargaining agreements; however, the amount of employees subject to
collective bargaining agreements only represents a small percentage (approximately 7%) of our employee base. In the event that
our union employees participate in a strike, work stoppage or engage in other forms of labor disruption, we would be responsible
for procuring replacement labor and could experience reduced power generation or outages.
We depend on computer and telecommunications systems we do not own or control and failures in our systems or cyber
security attacks could significantly disrupt our business operations.
We have entered into agreements with third parties for hardware, software, telecommunications and other information
technology services in connection with the operation of our power plants. In addition, we have developed proprietary software
systems, management techniques and other information technologies incorporating software licensed from third parties. It is
possible we could incur interruptions from cyber security attacks, computer viruses or malware. We believe that we have positive
relations with our related vendors and maintain adequate anti-virus and malware software and controls; however, any interruptions
to our arrangements with third parties, to our computing and communications infrastructure, or our information systems could
significantly disrupt our business operations.
Capital Resources; Liquidity
We have substantial liquidity needs and could face liquidity pressure.
As of December 31, 2012, our consolidated debt outstanding was $10.8 billion, of which approximately $7.8 billion was
outstanding under our First Lien Notes and First Lien Term Loans. In addition we had $626 million issued in letters of credit and
our pro rata share of unconsolidated subsidiary debt was approximately $224 million. Although we significantly extended our
maturities during 2011 and 2010, we could face liquidity challenges as we continue to have substantial debt and substantial liquidity
needs in the operation of our business. Our ability to make payments on our indebtedness, to meet margin requirements and to
fund planned capital expenditures and development efforts will depend on our ability to generate cash in the future from our
operations and our ability to access the capital markets. This, to a certain extent, is dependent upon industry conditions, as well
as general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control, as discussed
further in “— Commercial Operations” above. Although we are permitted to enter into new project financing credit facilities to
fund our development and construction activities, there can be no assurance that we will not face liquidity pressure in the future.
See additional discussion regarding our capital resources and liquidity in Item 7. “Management’s Discussion and Analysis of
Financial Condition and Results of Operations — Liquidity and Capital Resources.”
Our substantial indebtedness could adversely impact our financial health and limit our operations.
Our level of indebtedness has important consequences, including:
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limiting our ability to borrow additional amounts for working capital, capital expenditures, debt service requirements,
potential growth or other purposes;
limiting our ability to use operating cash flows in other areas of our business because we must dedicate a substantial
portion of these funds to service our debt;
increasing our vulnerability to general adverse economic and industry conditions;
limiting our ability to capitalize on business opportunities and to react to competitive pressures and adverse changes
in governmental regulation;
limiting our ability or increasing the costs to refinance indebtedness or to repurchase equity issued by certain of our
subsidiaries to third parties; and
limiting our ability to enter into marketing, hedging and optimization activities by reducing the number of
counterparties with whom we can transact as well as the volume and type of those transactions.
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The soundness of financial institutions could adversely affect us.
We have exposure to many different financial institutions and counterparties including those under our First Lien Notes,
First Lien Term Loans, Corporate Revolving Facility and other credit and financing arrangements as we routinely execute
transactions in connection with our hedging and optimization activities, including brokers and dealers, commercial banks,
investment banks and other institutions and industry participants. Many of these transactions expose us to credit risk in the event
that any of our lenders or counterparties are unable to honor their commitments or otherwise defaults under a financing agreement.
We may be unable to obtain additional financing or access the credit and capital markets in the future at prices that are
beneficial to us or at all.
If our available cash, including future cash flows generated from operations, is not sufficient in the near term to finance
our operations, post collateral or satisfy our obligations as they become due, we may need to access the capital and credit markets.
Our ability to arrange financing (including any extension or refinancing) and the cost of the financing is dependent upon numerous
factors, including general economic and capital market conditions. Market disruptions such as those experienced in the U.S. and
abroad in recent years, may increase our cost of borrowing or adversely affect our ability to access capital. In addition, we believe
these conditions have and may continue to have an adverse effect on the price of our common stock, which in turn may also reduce
our ability to access capital or credit markets. Other factors include:
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low credit ratings may prevent us from obtaining any material amount of additional debt financing;
conditions in energy commodity markets;
regulatory developments;
credit availability from banks or other lenders for us and our industry peers;
investor confidence in the industry and in us;
the continued reliable operation of our current power plants; and
provisions of tax, regulatory and securities laws that are conducive to raising capital.
While we have utilized non-recourse or lease financing when appropriate, market conditions and other factors may prevent
us from completing similar financings in the future. It is possible that we may be unable to obtain the financing required to develop,
construct, acquire or expand power plants on terms satisfactory to us. We have financed our existing power plants using a variety
of leveraged financing structures, including senior secured and unsecured indebtedness, construction financing, project financing,
term loans and lease obligations. In the event of a default under a financing agreement which we do not cure, the lenders or lessors
would generally have rights to the power plant and any related assets. In the event of foreclosure after a default, we may not be
able to retain any interest in the power plant or other collateral supporting such financing. In addition, any such default or foreclosure
may trigger cross default provisions in our other financing agreements.
Our First Lien Notes, First Lien Term Loans, Corporate Revolving Facility, CCFC Notes and our other debt instruments
impose restrictions on us and any failure to comply with these restrictions could have a material adverse effect on our liquidity
and our operations.
The restrictions under our First Lien Notes, First Lien Term Loans, Corporate Revolving Facility, CCFC Notes and other
debt instruments could adversely affect us by limiting our ability to plan for or react to market conditions or to meet our capital
needs and, if we were unable to comply with these restrictions, could result in an event of default under these debt instruments.
These restrictions require us to meet certain financial performance tests on a quarterly basis and limit or prohibit our ability, subject
to certain exceptions to, among other things:
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incur or guarantee additional first lien indebtedness up to certain consolidated net tangible asset ratios;
enter into certain types of commodity hedge agreements that can be secured by first lien collateral;
enter into sale and leaseback transactions;
• make certain investments;
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create or incur liens;
consolidate or merge with or transfer all or substantially all of our assets to another entity, or allow substantially all
of our subsidiaries to do so;
lease, transfer or sell assets and use proceeds of permitted asset leases, transfers or sales;
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•
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engage in certain business activities; and
enter into certain transactions with our affiliates.
Our First Lien Notes, First Lien Term Loans, Corporate Revolving Facility, CCFC Notes and our other debt instruments
contain events of default customary for financings of their type, including a cross default to debt other than non-recourse project
financing debt, a cross-acceleration to non-recourse project financing debt and certain change of control events. If we fail to comply
with the covenants and are unable to obtain a waiver or amendment, or a default exists and is continuing under such debt, the
lenders or the holders or trustee of the First Lien Notes, as applicable, could give notice and declare outstanding borrowings and
other obligations under such debt immediately due and payable.
Our ability to comply with these covenants may be affected by events beyond our control, and any material deviations
from our forecasts could require us to seek waivers or amendments of covenants or alternative sources of financing or to reduce
expenditures. We may not be able to obtain such waivers, amendments or alternative financing, or if obtainable, it could be on
terms that are not acceptable to us. If we are unable to comply with the terms of our First Lien Notes, First Lien Term Loans,
Corporate Revolving Facility, CCFC Notes and our other debt instruments, or if we fail to generate sufficient cash flows from
operations, or if it becomes necessary to obtain such waivers, amendments or alternative financing, it could adversely impact our
financial condition, results of operations and cash flows.
Our credit status is below investment grade, which may restrict our operations, increase our liquidity requirements and
restrict financing opportunities.
Our corporate and debt credit ratings are below investment grade. There is no assurance that our credit ratings will
improve in the future, which may restrict the financing opportunities available to us or may increase the cost of any available
financing. Our current credit rating has resulted in the requirement that we provide additional collateral in the form of letters of
credit or cash for credit support obligations and may adversely impact our subsidiaries’ and our financial position and results of
operations.
Certain of our obligations are required to be secured by letters of credit or cash, which increase our costs; if we are unable
to provide such security it may restrict our ability to conduct our business.
Companies using derivatives, which include many commodity contracts, are subject to the inherent risks of such
transactions. Consequently, many such companies, including us, may be required to post cash collateral for certain commodity
transactions; and, the level of collateral will increase as a company increases its hedging activities. We use margin deposits,
prepayments and letters of credit as credit support for commodity procurement and risk management activities. Future cash
collateral requirements may increase based on the extent of our involvement in standard contracts and movements in commodity
prices, and also based on our credit ratings and general perception of creditworthiness in this market. Certain of our financing
arrangements for our power plants have required us to post letters of credit which are at risk of being drawn down in the event
we, or the applicable subsidiary, default on our obligations.
Many of our collateral agreements require that letters of credit posted as collateral must be issued by a financial institution
with a minimum credit rating of “A”. Currently the financial institutions that issue letters of credit under our Corporate Revolving
Facility and other letter of credit facilities meet or exceed the minimum credit rating criteria. However, if one or more of these
financial institutions is no longer able to meet the minimum credit rating criteria, then we could be required to post collateral
funding from our cash and cash equivalents which could negatively impact our liquidity.
Additionally, changes in market regulations can increase the use of credit support and collateral. The potential impact of
the Dodd-Frank Act is uncertain, but it is possible that future regulations, when finalized, under the Dodd-Frank Act could directly
or indirectly result in increased credit support and collateral requirements.
These letter of credit and cash collateral requirements increase our cost of doing business and could have an adverse
impact on our overall liquidity, particularly if there was a call for a large amount of additional cash or letter of credit collateral
due to an unexpectedly large movement in the market price of a commodity. As of December 31, 2012, we had $626 million issued
in letters of credit under our Corporate Revolving Facility and other facilities, with $757 million remaining available for borrowing
or for letter of credit support under our Corporate Revolving Facility. In addition, we have ratably secured our obligations under
certain of our power and natural gas agreements that qualify as eligible commodity hedge agreements under our Corporate Revolving
Facility with the assets previously subject to liens under our First Lien Credit Facility.
44
We may not have sufficient liquidity to hedge market risks effectively.
We are exposed to market risks through our sale of power, capacity and related products and the purchase and sale of
fuel, transmission services and emission allowances. These market risks include, among other risks, volatility arising from location
and timing differences that may be associated with buying and transporting fuel, converting fuel into power and delivering the
power to a buyer.
We undertake these activities through agreements with various counterparties, many of which require us to provide
guarantees, offset or netting arrangements, letters of credit, a second lien on assets and/or cash collateral to protect the counterparties
against the risk of our default or insolvency. The amount of such credit support that must be provided typically is based on the
difference between the price of the commodity in a given contract and the market price of the commodity. Significant movements
in market prices can result in our being required to provide cash collateral and letters of credit in very large amounts. The
effectiveness of our strategy may be dependent on the amount of collateral available to enter into or maintain these contracts, and
liquidity requirements may be greater than we anticipate or will be able to meet. Without a sufficient amount of working capital
to post as collateral in support of performance guarantees or as a cash margin, we may not be able to manage price volatility
effectively or to implement our strategy. An increase in the amount of letters of credit or cash collateral required to be provided
to our counterparties may negatively affect our liquidity and financial condition.
Further, if any of our power plants experience unplanned outages, we may be required to procure replacement power at
spot market prices in order to fulfill contractual commitments. Without adequate liquidity to meet margin and collateral
requirements, we may be exposed to significant losses, may miss significant opportunities and may have increased exposure to
the volatility of spot markets.
Our ability to receive future cash flows generated from the operation of our subsidiaries may be limited.
Almost all of our operations are conducted through our subsidiaries and other affiliates. As a result, we depend almost
entirely upon their earnings and cash flows to service our indebtedness, post collateral and finance our ongoing operations. Certain
of our project debt and other agreements restrict our ability to receive dividends and other distributions from our subsidiaries.
Some of these limitations are subject to a number of significant exceptions (including exceptions permitting such restrictions in
connection with certain subsidiary financings). Accordingly, the financing agreements of certain of our subsidiaries and other
affiliates generally restrict their ability to pay dividends, make distributions or otherwise transfer funds to us prior to the payment
of their other obligations, including their outstanding debt, operating expenses, lease payments and reserves or during the existence
of a default.
We may utilize project financing, preferred equity and other types of subsidiary financing transactions when appropriate
in the future, which could increase our debt and may be structurally senior to other debt such as our First Lien Notes, First
Lien Term Loans and Corporate Revolving Facility.
Our ability and the ability of our subsidiaries to incur additional indebtedness are limited in some cases by existing
indentures, debt instruments or other agreements. Our subsidiaries may incur additional construction/project financing
indebtedness, issue preferred equity to finance the acquisition and development of new power plants and engage in certain types
of non-recourse financings to the extent permitted by existing agreements, and may continue to do so in order to fund our ongoing
operations. Any such newly incurred subsidiary preferred equity would be added to our current consolidated debt levels and would
likely be structurally senior to our debt, which could also intensify the risks associated with our already existing leverage.
Our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility are effectively subordinated to certain project
indebtedness.
Certain of our subsidiaries and other affiliates are separate and distinct legal entities and, except in limited circumstances,
have no obligation to pay any amounts due with respect to our indebtedness or indebtedness of other subsidiaries or affiliates, and
do not guarantee the payment of interest on or principal of such indebtedness. In the event of our bankruptcy, liquidation or
reorganization (or the bankruptcy, liquidation or reorganization of a subsidiary or affiliate), such subsidiaries’ or other affiliates’
creditors, including trade creditors and holders of debt issued by such subsidiaries or affiliates, will generally be entitled to payment
of their claims from the assets of those subsidiaries or affiliates before any assets are made available for distribution to us or the
holders of our indebtedness. As a result, holders of our indebtedness will be effectively subordinated to all present and future debts
and other liabilities (including trade payables) of certain of our subsidiaries. As of December 31, 2012, our subsidiaries had
approximately $1.0 billion in debt from our CCFC subsidiary and approximately $1.8 billion in secured project financing from
other subsidiaries, which are effectively senior to our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility.
We may incur additional project financing indebtedness in the future, which will be effectively senior to our other secured and
unsecured debt.
45
Governmental Regulation
Existing and proposed federal and state RPS and energy efficiency, as well as economic support for renewable sources of
power under the U.S economic stimulus legislation could adversely impact our operations.
Federal policymakers have been considering imposing a national RPS on retail power providers. California already has
an RPS in effect and in 2011 signed into law legislation requiring implementation of a 33% RPS by 2020. A number of additional
states, including Maine, Minnesota, New York, Texas and Wisconsin, have an array of different RPS in place. Existing state-
specific RPS requirements may change due to regulatory and/or legislative initiatives, and other states may consider implementing
enforceable RPS in the future. A national RPS or more robust RPS in states in which we are active, coupled with economic
incentives provided under the federal stimulus package, would likely initially drive up the number of wind and solar resources,
increasing power supply to various markets which could negatively impact the dispatch of our natural gas-fired power plants,
primarily in Texas and California.
Similarly, federal legislators are considering national energy efficiency initiatives. Several states already have energy
efficiency initiatives in place while others are considering imposing them. Improved energy efficiency when mandated by law or
promoted by government sponsored incentives can decrease demand for power which could negatively impact the dispatch of our
natural gas-fired power plants, primarily in Texas and California.
State legislative and regulatory action, such as the actions taken in New Jersey and Maryland to impermissibly increase
power plant construction in those states, could adversely impact our competitive position and business.
Certain states in the PJM market region, particularly New Jersey and Maryland, have taken actions that could impact the
PJM capacity market. In New Jersey, legislation enacted in 2011 required the New Jersey Board of Public Utilities (“BPU”) to
issue a request for proposals (“RFP”) for new generation. As a result of the RFP, the BPU directed New Jersey’s four public utilities
to enter into standard offer capacity agreements with the winning generators for new capacity to be built in New Jersey. Several
entities have appealed the BPU’s order directing the public utilities to enter into long-term contracts with those generators. The
appeal process continues. Also, on February 9, 2011, we joined a group of generators and utilities in filing a complaint in federal
district court challenging the constitutionality of the New Jersey legislation. On September 28, 2012, the judge in the proceeding
denied all Motions for Summary Judgment. Discovery is continuing with a trial expected to be held in late March to early April
2013.
On September 29, 2011, the Maryland Public Service Commission (“MPSC”) issued a “Notice of Approval of Request
for Proposals for New Generation to be Issued by Maryland Electric Distribution Companies” (the “Notice”). The Notice required
the state’s IOUs to issue RFPs for up to 1,500 MW of capacity. The Notice specifies that proposals must be for new natural gas-
fired capacity capable of delivery into the PJM Southwest Mid-Atlantic Area Council (“SWMAAC”) delivery area. On April 12,
2012, the MPSC issued a further order in this proceeding directing certain Maryland IOUs located in the SWMAAC area to enter
into a contract for differences with CPV Maryland, LLC (“CPV”), a generation developer that is currently developing a 661 MW
natural gas-fired, combined-cycle generation plant in SWMAAC. The facility’s scheduled COD is June 1, 2015. In May 2012,
we filed with the Circuit Court of Baltimore County, Maryland a Petition for Review of the MPSC’s order, asking the court to
review the order and declare it invalid. Several other parties filed similar appeals. The appeals have been consolidated, but the
case has been suspended pending resolution of certain terms in the contracts between the IOUs and CPV. In a separate action,
several generators have filed a complaint in federal district court challenging the constitutionality of the MPSC’s actions. That
case is expected to go to trial in late February 2013.
At the FERC level, PJM has taken action to strengthen the Minimum Offer Price Rule (“MOPR”) in its tariff. PJM’s
tariff changes are intended to address the negative implications from these state actions. The FERC issued an order in April 2011
approving amendments to PJM’s MOPR tariff provisions. The FERC order is currently on appeal before the U.S. Court of Appeals
for the Third Circuit. In December 2012, PJM filed further amendments to the MOPR that are intended to make the MOPR process
more transparent and objective. On February 5, 2013, the FERC asked PJM to provide additional information about its proposal.
While unclear, given the current timing of PJM’s response and a subsequent FERC decision, it is still possible for the changes to
be in effect for the 2016/2017 PJM Reliability Pricing Model base residual auction, to be held on May 13-17, 2013.
Unless these anticompetitive actions in New Jersey and Maryland are overturned by the courts or mitigated by the FERC,
they could have an adverse impact on the deregulated PJM electricity markets by discouraging the construction of new generation
which in turn could have a negative impact on our business prospects and financial results.
46
Increased oversight and investigation by the CFTC relating to derivative transactions, as well as certain financial institutions,
could have an adverse impact on our ability to hedge risks associated with our business.
The CFTC has regulatory oversight of the futures markets, including trading on NYMEX for energy, and licensed futures
professionals such as brokers, clearing members and large traders. In connection with its oversight of the futures markets and
NYMEX, the CFTC regularly investigates market irregularities and potential manipulation of those markets. Recent laws also
give the CFTC certain powers with respect to broker-type markets referred to as “exempt commercial markets” or ECMs, including
the Intercontinental Exchange. The CFTC monitors activities in the OTC, ECM and physical markets that may be undertaken for
the purpose of influencing futures prices. With respect to ECMs, the CFTC exercises only light-handed regulation primarily related
to trade reporting, price dissemination and record retention (including retention of fraudulent claims and allegations). Thus,
transactions executed on an ECM generally are not regulated directly by the CFTC. However, the CFTC may make special calls
of market participants in the ECM and ECM transactions have come under the CFTC’s scrutiny during investigations of fraud
and manipulation in which the CFTC has broadly applied its statutory authority to punish persons who are alleged to have
manipulated, or attempted to manipulate, the price of any commodity in interstate commerce or for future delivery. Moreover,
while ECM transactions are not required to be cleared, if they are cleared, such cleared ECM transaction would be subject to
regulation by the CFTC. We also expect the CFTC’s powers and oversight to be increased by the Dodd-Frank Act. However, as
discussed below, the extent of such increased powers and oversight, and its effect on ECM transactions, if any, is not yet certain.
The unknown impact from the Dodd-Frank Act as well as the rules to be promulgated under it could have an adverse impact
on our ability to hedge risks associated with our business, require the implementation of additional policies and require us to
incur administrative compliance costs.
The Dodd-Frank Act contains a variety of provisions designed to regulate financial markets, including credit and
derivatives transactions. Title VII of the Dodd-Frank Act addresses regulatory reform of the OTC derivatives market in the U.S.
and significantly changes the regulatory framework of this market. Certain Title VII regulations have been finalized and are
effective though some regulations remain subject to a delayed compliance schedule. Other key regulations have not been finalized
as of this time or remain in draft form. Until all of these regulations have been finalized, the extent to which the provisions of Title
VII might affect our derivatives activities cannot be completely known. A number of features in the legislation may impact our
existing business. One of these is the requirement for central clearing of many OTC derivative transactions with clearing
organizations. Moreover, whereas our OTC transactions have traditionally been negotiated on a bilateral basis, including the
collateral arrangements thereunder, they now may be subject to the collateral and margining procedures of the clearing organization.
Certain end-users may be able to benefit from an exception which would exempt them from mandatory clearing requirements. If
the derivatives transactions which we enter into are determined to be subject to mandatory clearing requirements, we will seek to
comply with the regulatory requirements in order to benefit from the end-user exception. Uncleared OTC derivatives transactions
under the Dodd-Frank Act will also be subject to collateral and margining procedures established by CFTC regulation. These Title
VII regulations have not, as of the date of this Report, been finalized. Other features of the Dodd-Frank Act which will have an
impact on our derivative activities include trade reporting and trade execution. The effect of the Dodd-Frank Act on traditional
dealers and market-makers as well as the consequential effect on market liquidity and, hence, pricing is uncertain. Nevertheless,
we expect to be able to continue to participate in financial markets for our derivative transactions.
Some of the key regulatory rulemakings regarding the definition of specific entity designations and the swap definition
rules for the Dodd-Frank Act, which was signed into law on July 21, 2010, were finalized in the second and third quarters of 2012.
The CFTC also recently issued several no-action letters, interpretations and an exemptive order impacting the implementation
schedule and interpretations of key provisions in the CFTC’s Dodd-Frank Act implementation rules. We have reviewed our
derivative activities over a one month survey period, as a proxy for future activity, and our intended future activities, and have
determined that we are not a swap dealer as defined under the CFTC’s final entity definition rule and, therefore, are not required
to register as a swap dealer. We have established an internal working group for a thorough and ongoing evaluation of the impact
and timing of these recent rulemakings on our operations as a non-swap dealer; however, it is difficult to fully assess the ultimate
impact of the Dodd-Frank Act on us until all rulemakings are finalized and implemented.
While we are closely monitoring this rulemaking process from the CFTC (including related no-action relief, interpretations
and orders), we have reviewed and assessed the impact of the CFTC’s Title VII regulations on our business and related processes,
and we have adjusted our internal procedures where necessary to comply with the applicable statutory law and related Title VII
regulations which are effective at this time. We will continue to monitor all relevant developments and rulemaking initiatives, and
we expect to successfully implement any new applicable requirements. At this time, we cannot predict the impact or possible
additional costs to us related to the implementation of, or compliance with, the potential future requirements under the Dodd-
Frank Act.
47
The Dodd-Frank Act contains provisions to improve transparency and accountability concerning the supply of certain
minerals, known as conflict minerals (namely tin, tantalum, tungsten or gold), originating from the conflict zones of the Democratic
Republic of Congo (“DRC”) and adjoining countries. In August 2012, as mandated by the Dodd-Frank Act, the SEC adopted final
rules requiring all issuers that file reports with the SEC to report, on an annual basis, supply chain and sourcing information for
companies that use conflict minerals mined from the DRC and adjoining countries in their products. These new requirements will
require due diligence efforts in fiscal 2013, with initial disclosure requirements beginning in May 2014. Based on our preliminary
analysis, we do not believe that any of our products contain conflict minerals; however, our assessment process to determine
whether conflict minerals are necessary to the functionality or production of any of our products is not complete. Should we
conclude that we are subject to the conflict minerals reporting requirements, we will have to determine the most efficient means
of complying with the disclosure requirements, including diligence procedures to determine the sources of conflict minerals that
are necessary to the functionality or production of our products and, if applicable, potential changes to products, processes or
sources of supply as a consequence of such verification activities. It is also possible that we may face reputational harm if we
determine that certain of our products contain minerals not determined to be “conflict free” and/or we are unable to alter our
products, processes or sources of supply to avoid such materials.
Changes in the regulation of the power markets in which we operate could negatively impact us.
We have a significant presence in the major competitive power markets for California, Texas and the Mid-Atlantic region
of the U.S. While these markets are largely de-regulated, they continue to evolve. Existing regulations within the markets in which
we operate may be revised or reinterpreted and new laws or regulations may be issued. We cannot predict the future development
of regulation or legislation nor the ultimate effect such changes in these markets could have on our business; however, we could
be negatively impacted.
Existing and future anticipated GHG/Carbon and other air emissions regulations could cause us to incur significant costs
and adversely affect our operations generally or in a particular quarter when such costs are incurred.
Environmental laws and regulations have generally become more stringent over time, and this trend is likely to continue.
In particular, there is growing likelihood that carbon tax or limits on carbon, CO2 and other GHG emissions will be implemented
at the federal or expanded at the state or regional levels.
In 2009, ten states in the northeast began the compliance period of a Cap-and-trade program, RGGI, to regulate CO2
emissions from power plants. California has implemented AB 32 which places a statewide cap on GHG emissions and requires
the state to return to 1990 emission levels by 2020. In December 2010, CARB adopted a regulation establishing a GHG Cap-and
trade program which is in effect for electric utilities and other “major industrial sources,” and in 2015 for certain other GHG
sources.
In 2011, the EPA finalized regulations governing GHG emissions from major sources as well as emissions of criteria and
hazardous air pollutants from the electric generation sector. We continue to monitor and actively participate in the EPA initiatives
where we anticipate a material impact on our business.
Further, air regulations enacted in New Jersey that further limit NOX emissions from turbines and boilers beginning in
2015 will impact six of our power plants that will either need to retire or install additional NOX controls to continue operating
beyond 2015. We plan to install emissions controls equipment at two of these power plants and have provided notice to PJM of
our intent to retire the four remaining power plants before the commencement of the PJM Reliability Pricing Model 2015/2016
delivery year. We do not expect the retirement of these power plants or installation of emissions controls to have a material impact
on our financial condition, results of operations or cash flows.
We are subject to other complex governmental regulation which could adversely affect our operations.
Generally, in the U.S., we are subject to regulation by FERC regarding the terms and conditions of wholesale service
and the sale and transportation of natural gas, as well as by state agencies regarding physical aspects of the power plants. The
majority of our generation is sold at market prices under the market-based rate authority granted by the FERC. If certain conditions
are not met, FERC has the authority to withhold or rescind market-based rate authority and require sales to be made based on cost-
of-service rates. A loss of our market-based rate authority could have a materially negative impact on our generation business.
FERC could also impose fines or other restrictions or requirements on us under certain circumstances.
The construction and operation of power plants require numerous permits, approvals and certificates from the appropriate
foreign, federal, state and local governmental agencies, as well as compliance with numerous environmental laws and regulations
of federal, state and local authorities. Should we fail to comply with any environmental requirements that apply to power plant
48
construction or operations, we could be subject to administrative, civil and/or criminal liability and fines, and regulatory agencies
could take other actions to curtail our operations.
Furthermore, certain environmental laws impose strict, joint and several liability for costs required to clean up and restore
sites where hazardous substances have been disposed or otherwise released. We are generally responsible for all liabilities associated
with the environmental condition of our power plants, including any soil or groundwater contamination that may be present,
regardless of when the liabilities arose and whether the liabilities are known or unknown, or arose from the activities of predecessors
or third parties.
If we were deemed to have market power in certain markets as a result of the ownership of our stock by certain significant
shareholders, we could lose FERC authorization to sell power at wholesale at market-based rates in such markets or be required
to engage in mitigation in those markets.
Certain of our significant shareholder groups own power generating assets, or own significant equity interests in entities
with power generating assets, in markets where we currently own power plants. We could be determined to have market power if
these existing significant shareholders acquire additional significant ownership or equity interest in other entities with power
generating assets in the same markets where we generate and sell power.
If FERC makes the determination that we have market power, FERC could, among other things, revoke market-based
rate authority for the affected market-based companies or order them to mitigate that market power. If market-based rate authority
was revoked for any of our market-based rate companies, those companies would be required to make wholesale sales of power
based on cost-of-service rates, which could negatively impact their revenues. If we are required to mitigate market power, we
could be required to sell certain power plants in regions where we are determined to have market power. A loss of our market-
based rate authority or required sales of power plants, particularly if it affected several of our power plants or was in a significant
market, could have a material negative impact on our financial condition, results of operations and cash flows.
Risks Relating to Our Common Stock
Our principal shareholders own a significant amount of our common stock, giving them influence over corporate transactions
and other matters.
As of December 31, 2012, four current holders (or related groups of holders) of our common stock have made filings
with the SEC reporting beneficial ownership, directly or indirectly, individually or as members of a group, of 5% or more of the
shares of our common stock. These shareholders, who together beneficially owned approximately 40% of our common stock at
December 31, 2012, may be able to exercise substantial influence over all matters requiring shareholder approval, including the
election of directors and approval of significant corporate action, such as mergers and other business combination transactions. If
two or more of these shareholders (or groups of shareholders) vote their shares in the same manner, their combined stock ownership
may effectively give significant influence over the election of our entire Board of Directors and significant influence over our
management, operations and affairs. Currently, one member of our Board of Directors, the Chairman of our Board, is affiliated,
directly or indirectly, with SPO Advisory Corp., one of these shareholders.
Circumstances may occur in which the interests of these shareholders could be in conflict with the interests of other
shareholders. This concentration of ownership may also have the effect of delaying or preventing a change in control over us
unless it is supported by these shareholders. Accordingly, the ability of our other shareholders to influence us through voting of
their shares may be limited or the market price of our common stock may be adversely affected. Additionally, we have filed a
registration statement on Form S-3 registering the resale of the common stock held by certain members of one of the three groups
of these shareholders, which permits them to sell a large portion of their shares of common stock without being subject to the
“trickle out” or other restrictions of Rule 144 under the Securities Act. Sales by any of the four shareholders of all or a substantial
portion of their shares within a short period of time, could adversely affect the market price of our common stock or could further
concentrate holdings of our common stock in the remaining three shareholders who hold more than 5% of our common stock.
Transfers of our equity, or issuances of equity, may impair our ability to utilize our federal income tax NOL carryforwards
in the future.
Under federal income tax law, our NOL carryforwards can be utilized to reduce future taxable income subject to certain
limitations, including if we were to undergo an ownership change as defined by Section 382 of the IRC. We experienced an
ownership change on the Effective Date as a result of the cancellation of our old common stock and the distribution of our new
common stock pursuant to our Plan of Reorganization. However, this ownership change and resulting annual limitations are not
expected to result in the expiration of our NOL carryforwards if we are able to generate sufficient future taxable income within
the carryforward periods. If a subsequent ownership change were to occur as a result of future transactions in our stock, accompanied
49
by a significant reduction in our market value immediately prior to the ownership change, our ability to utilize the NOL carryforwards
may be significantly limited.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
Our principal executive offices are located in Houston, Texas. This facility is leased until 2020. We also have regional
offices in Dublin, California and Wilmington, Delaware, an engineering, construction and maintenance services office in Pasadena,
Texas and government affairs offices in Washington D.C., Sacramento, California and Austin, Texas.
We either lease or own the land upon which our power plants are built. We believe that our properties are adequate for
our current operations. A description of our power plants is included under Item 1. “Business —Description of Our Power Plants.”
Item 3. Legal Proceedings
See Note 15 of the Notes to Consolidated Financial Statements for a description of our legal proceedings.
Item 4. Mine Safety Disclosures
Not applicable.
50
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information and Stockholder Matters
Calpine Corporation common stock is traded on the NYSE under the symbol “CPN”. The following table sets forth the
high and low bid prices for our common stock for each quarter of the years 2012 and 2011, as reported on the NYSE.
2012
First Quarter ............................................................................................................................. $
Second Quarter .........................................................................................................................
Third Quarter............................................................................................................................
Fourth Quarter ..........................................................................................................................
2011
First Quarter ............................................................................................................................. $
Second Quarter .........................................................................................................................
Third Quarter............................................................................................................................
Fourth Quarter ..........................................................................................................................
As of December 31, 2012, there were 146 stockholders of record of our common stock.
High
Low
$
$
17.60
19.03
18.66
18.87
16.25
17.10
17.08
16.68
14.45
15.90
16.42
16.47
13.42
15.00
12.70
12.79
We have never paid cash dividends on our common stock. Future cash dividends, if any, will be 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. See
Item 1A. “Risk Factors,” including “— Risks Relating to Our Common Stock” for a discussion of additional risks related to an
investment in our common stock.
Repurchase of Equity Securities
(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)
(b)
Average Price
Paid Per Share
17.81
16.93
17.65
17.33
— $
$
$
$
3,933,377
5,008,039
8,941,416
173
106
18
18
(a)
Total Number of
Shares Purchased(1)
2,999
3,933,533
5,009,857
8,946,389
$
$
$
$
Period
October .............................................................
November .........................................................
December .........................................................
Total
___________
(1) Upon vesting of restricted stock awarded by us to employees, we withhold shares to cover employees' tax withholding
obligations, other than for employees who have chosen to satisfy their tax withholding obligations in cash. During the fourth
quarter of 2012, we withheld a total of 4,973 shares in the indicated months that are included in total number of shares
purchased.
(2) On August 23, 2011, we announced that our Board of Directors had authorized the repurchase of up to $300 million in shares
of our common stock. In April 2012, our Board of Directors authorized us to double the size of our share repurchase program,
increasing our permitted cumulative repurchases to $600 million in shares of our common stock. As of the filing of this
Report, we have completed our previously announced $600 million share repurchase program, having repurchased a total
of 35,568,833 shares of our outstanding common stock at an average price paid of $16.87 per share. In February 2013, our
Board of Directors authorized the repurchase of an additional $400 million in shares of our common stock, bringing the
cumulative authorization total to $1.0 billion. The shares repurchased under our share repurchase program were purchased
in open market transactions and are held as treasury stock.
51
Stock Performance Graph
The performance graph below compares cumulative return on our common stock for the period February 7, 2008 through
December 31, 2012, with the cumulative return of Standard & Poor’s 500 Index (S&P 500) and the S&P 500 Utilities Index. Since
the reorganized Calpine Corporation common stock began “regular way” trading on the NYSE on February 7, 2008, stock
performance prior to February 7, 2008 does not provide meaningful comparison and has not been provided.
The graph below compares each period assuming that $100 was invested on February 7, 2008 in our common stock and
each of above indices and that all dividends are reinvested. The returns shown below may not be indicative of future performance.
Company / Index
Calpine Corporation....
S&P 500 Index............
S&P Utilities Index.....
$
February 7,
2008
December 31,
2008
December 31,
2009
December 31,
2010
December 31,
2011
December 31,
2012
$
100
100
100
$
43.86
69.06
76.98
$
66.27
87.33
86.15
$
80.36
100.49
90.85
$
98.37
102.61
108.94
109.21
119.03
110.36
52
Item 6. Selected Financial Data
SELECTED CONSOLIDATED FINANCIAL DATA
Years Ended December 31,
2012
2011
2010
2009
2008
(in millions, except earnings (loss) per share)
Statement of Operations data:
Operating revenues ................................................................. $
Income (loss) before discontinued operations attributable to
Calpine................................................................................. $
Discontinued operations, net of tax expense, attributable to
Calpine.................................................................................
Net income (loss) attributable to Calpine ............................... $
5,478
199
—
199
$
$
$
6,800
$
6,545
$
6,463
(190) $
(162) $
—
(190) $
193
31
$
114
35
149
$
$
$
9,837
(26)
36
10
Basic earnings (loss) per common share:
Income (loss) before discontinued operations attributable to
Calpine................................................................................. $
Discontinued operations, net of tax expense, attributable to
Calpine.................................................................................
Net income (loss) per common share attributable to
Calpine .............................................................................. $
Diluted earnings (loss) per common share:
Income (loss) before discontinued operations attributable to
Calpine................................................................................. $
Discontinued operations, net of tax expense, attributable to
Calpine.................................................................................
Net income (loss) per common share attributable to
Calpine .............................................................................. $
Balance Sheet data:
0.43
$
(0.39) $
(0.33) $
0.24
$
(0.05)
—
—
0.39
0.07
0.07
0.43
$
(0.39) $
0.06
$
0.31
$
0.02
0.42
$
(0.39) $
(0.33) $
0.24
$
(0.05)
—
—
0.39
0.07
0.07
0.42
$
(0.39) $
0.06
$
0.31
$
0.02
Total assets .............................................................................. $ 16,549
115
Short-term debt and capital lease obligations ......................... $
Long-term debt and capital lease obligations.......................... $ 10,635
$ 17,371
104
$
$ 10,321
$ 17,256
152
$
$ 10,104
$ 16,650
463
$
8,996
$
$ 20,738
716
$
9,756
$
53
Item 7. 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 Financial Statements and related notes. See the cautionary statement regarding
forward-looking statements on page 1 of this Report for a description of important factors that could cause actual results to differ
from expected results. See also Item 1A. “Risk Factors.”
INTRODUCTION AND OVERVIEW
Our Business
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, Texas and the Mid-Atlantic region 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 have invested in clean power
generation to become a recognized leader in developing, constructing, owning and operating an environmentally responsible
portfolio of power plants. We purchase natural gas and fuel oil as fuel for our power plants, engage in related natural gas
transportation and storage transactions, and we purchase electric transmission rights to deliver power to our customers. We also
enter into natural gas and power physical and financial contracts to hedge certain business risks and optimize our portfolio of
power plants. Our goal is to be recognized as the premier wholesale power company in the U.S. as measured by our employees,
customers, regulators, shareholders and communities in which our facilities are located. We seek to achieve sustainable growth
through financially disciplined power plant development, construction, acquisition, operation and ownership. We will continue to
pursue opportunities to improve our fleet performance and reduce operating costs. In order to manage our various physical assets
and contractual obligations, we will continue to execute commodity agreements within the guidelines of our Risk Management
Policy.
We assess our business on a regional basis due to the impact on our financial performance of the differing characteristics
of these regions, particularly with respect to competition, regulation and other factors impacting supply and demand. Our reportable
segments are West (including geothermal), Texas, North (including Canada) and Southeast.
Our portfolio, including partnership interests, consists of 92 power plants, including 4 under construction (1 new power
plant and 3 expansions of existing power plants), located throughout 20 states in the U.S. and in Canada, with an aggregate
generation capacity of 27,321 MW and 1,163 MW under construction. Our fleet, including projects under construction, consists
of 74 combustion turbine-based plants, 2 fossil steam-based plants, 15 geothermal turbine-based plants and 1 photovoltaic solar
plant. Our segments have an aggregate generation capacity of 6,751 MW with an additional 773 MW under construction in the
West, 8,014 MW with additional 390 MW under construction in Texas, 7,320 MW in the North and 5,236 MW in the Southeast.
Our Geysers Assets are included in our West segment.
Current Year Operational Developments
Our objective is to be the “best-in-class” in regards to certain operational performance metrics, such as safety, availability,
reliability, efficiency and cost management. In addition, we continue to grow our presence in core markets with an emphasis on
expansions or modernizations of existing power plants. Our notable operational performance metrics, significant projects under
construction, organic growth initiatives and modernizations are discussed below:
• We produced approximately 116 billion KWh of electricity in 2012, 23% more than the same period in 2011 (includes
generation from power plants owned but not operated by us and our share of generation from our unconsolidated
power plants).
• Our entire fleet achieved a forced outage factor of 1.6% in 2012, our lowest on record and an improvement of 36%
from 2011.
• Our entire fleet achieved an impressive starting reliability of 98.3% in 2012.
• During 2012, our outage services subsidiary completed 11 major inspections and 19 hot gas path inspections.
• For the past twelve consecutive years, our Geysers Assets have reliably generated approximately 6 million MWh per
year and, in 2012, achieved an exceptional availability factor of approximately 97%.
54
• Construction of our Russell City Energy Center and modernization at our Los Esteros Critical Energy Facility continue
to move forward with expected completion dates during the summer of 2013.
• We continue to make progress with our turbine modernization program and have ongoing development and expansion
activities which include the advanced development of the Garrison Energy Center located in Dover, Delaware and
the expansions of our Deer Park and Channel Energy Centers in Texas which are now under construction.
Enhancing Shareholder Value
We continue to make significant progress to deliver financially disciplined growth, to enhance shareholder value through
our capital allocation and share repurchases and to set the foundation for continued growth and success. Given our strong cash
flow from operations, we are committed to remaining financially disciplined in our capital allocation decisions. The year ended
December 31, 2012 was marked by the following accomplishments:
• As of the filing of this Report, we have completed our previously announced $600 million share repurchase program,
having repurchased a total of 35,568,833 shares of our outstanding common stock at an average price paid of $16.87
per share. In February 2013, our Board of Directors authorized the repurchase of an additional $400 million in shares
of our common stock, bringing the cumulative authorization total to $1.0 billion.
• During the first quarter of 2012, we terminated our legacy interest rate swaps formerly hedging our First Lien Credit
Facility for a payment of approximately $156 million which eliminated our exposure from these instruments to
further declines in interest rates.
• On October 9, 2012, we issued our 2019 First Lien Term Loan and used the proceeds to reduce our overall cost of
debt and simplify our capital structure by redeeming a portion of our First Lien Notes and repaying project debt.
• On November 7, 2012, we completed the purchase of a modern, natural gas-fired, combined-cycle power plant with
a nameplate capacity of 800 MW located in Bosque County, Texas for approximately $432 million which increased
capacity in our Texas segment.
• On December 27, 2012, we, through our indirect, wholly-owned subsidiary Calpine Power Company, completed the
sale of 100% of our ownership interest in each of the Broad River Entities for approximately $423 million. This
transaction resulted in the disposition of our Broad River power plant, an 847 MW natural gas-fired, peaking power
plant located in Gaffney, South Carolina, and includes a five year consulting agreement with the buyer. We expect
to use the sale proceeds for our capital allocation activities and for general corporate purposes.
• On December 31, 2012, we completed the sale of Riverside Energy Center, LLC to WP&L for approximately $402
million. We expect to use the sale proceeds for our capital allocation activities and for general corporate purposes.
For a further discussion of our capital management and significant financing transactions completed in 2012, see “—
Liquidity and Capital Resources.”
Customer-Oriented Origination Business
We continue to focus on providing products and services that are beneficial to our customers. A summary of certain
significant contracts entered into in 2012 is as follows:
• We entered into a new twenty-year PPA with Western Farmers Electric Cooperative to provide 160 MW of power
generated by our Oneta Energy Center, commencing in June 2014. The capacity under contract will increase in
increments, up to a maximum of 280 MW in years 2019 through 2035.
• We entered into a new five-year PPA with Southwestern Public Service Company, a subsidiary of Xcel Energy, to
provide an additional 200 MW of power generated by our Oneta Energy Center commencing on June 1, 2014.
• We entered into a new five-year resource adequacy contract with PG&E for approximately 280 MW of combined
heat and power capacity from our Los Medanos Energy Center commencing in the summer 2013.
• We entered into a new seven-year resource adequacy contract with Southern California Edison Company (“SCE”)
for approximately 280 MW of combined heat and power capacity from our Los Medanos Energy Center and a new
five-year resource adequacy contract with SCE for approximately 120 MW of combined heat and power capacity
from our Gilroy Cogeneration Plant, both commencing in January 2014.
• We amended an existing PPA with Dow Chemical Company for an incremental energy sale of up to approximately
158,000 MWh per year of energy from our Los Medanos Energy Center which runs through February 2025.
• We entered into a new fifteen-year PPA with American Electric Power Service Corporation, as agent for Public
Service Company of Oklahoma, to provide 260 MW of energy, capacity and ancillary services from our Oneta Energy
Center commencing in June 2016.
55
• We entered into a new ten-year PPA with the Tennessee Valley Authority to provide the full output of power generated
by our Decatur Energy Center, a natural gas-fired, combined-cycle power plant that can generate up to 795 MW,
commencing in January 2013.
Our Regulatory and Environmental Profile
We are subject to complex and stringent energy, environmental and other governmental laws and regulations at the federal,
state and local levels in connection with the development, ownership and operation of our power plants. Federal and state legislative
and regulatory actions continue to change how our business is regulated. The EPA is moving forward on climate change regulation,
and has already promulgated regulations related to other air pollutant emissions, and some states and regions in the U.S. have
implemented or are considering implementing regulations to reduce GHG emissions. We are actively participating in these debates
at the federal, regional and state levels. For a further discussion of the environmental and other governmental regulations that
affect us, see “— Governmental and Regulatory Matters” in Item 1. of this Report. Although we cannot predict the ultimate effect
future climate change regulations or legislation could have on our business, we believe that we will be less adversely impacted
by potential Cap-and-trade limits, carbon taxes or required environmental upgrades as a result of future potential regulation or
legislation addressing GHG, other air emissions, as well as water use or emissions, than compared to our competitors who use
other fossil fuels or steam condensation technologies.
Since our inception in 1984, we have been a leader in environmental stewardship and have invested in clean power
generation to become a recognized leader in developing, constructing, owning and operating an environmentally responsible
portfolio of power plants. The combination of our Geysers Assets and our high efficiency portfolio of natural gas-fired power
plants results in substantially lower emissions of these gases compared to our competitors’ power plants using other fossil fuels,
such as coal. Consequently, our power generation portfolio has the lowest GHG footprint per MWh of any major wholesale power
producer in the U.S. In addition, we strive to preserve our nation’s valuable water and land resources. To condense steam, we
primarily use cooling towers with a closed water cooling system or air cooled condensers. Since our power plants are modern and
efficient and utilize clean burning natural gas, we do not require large areas of land for our power plants nor do we require large
specialized landfills for the disposal of coal ash or nuclear plant waste.
Our Market and Our Key Financial Performance Drivers
The market Spark Spread, sales of RECs, revenues from our PPAs and steam sales and the results from our marketing,
hedging and optimization activities are the primary drivers of our Commodity Margin and contribute significantly to our financial
results. The market Spark Spread is primarily impacted by fuel prices, weather and reserve margins, which impact our supply and
demand fundamentals. Those factors, plus the relationship between our operating Heat Rate compared to the Market Heat Rate,
our power plant operating performance and availability are key to our financial performance.
Fluctuations in natural gas price levels affect our Commodity Margin (depending on our hedge levels and holding other
factors constant). When less efficient, higher cost natural gas-fired units set power prices in our regional markets, higher natural
gas prices tend to increase our Commodity Margin. In these instances, while our production costs increase when natural gas prices
are higher, our competitors’ costs (and power prices) increase at a greater rate, leading to higher Commodity Margin. Similarly,
when natural gas prices decline, our Commodity Margin tends to decline.
In 2012, given very low natural gas prices, natural gas-fired, combined-cycle units in many markets were frequently
cheaper to dispatch than coal-fired power plants. When coal-fired electricity production costs exceed natural gas-fired production
costs, coal-fired units tend to set power prices. In these hours, lower natural gas prices tend to increase our Commodity Margin,
since our production costs fall while power prices remain constant (depending on our hedge levels and holding other factors
constant).
Efficient operation of our fleet creates the opportunity to capture Commodity Margin in a cost effective manner. However,
unplanned outages during periods when Commodity Margin is positive could result in a loss of that opportunity. We generally
measure our fleet performance based on our availability factors, Heat Rate and plant operating expense. The higher our availability
factor, the better positioned we are to capture Commodity Margin. The less natural gas we must consume for each MWh of power
generated, the lower our Heat Rate. The lower our operating Heat Rate compared to the Market Heat Rate, the more favorable the
impact on our Commodity Margin. Holding all other factors constant, our Commodity Margin increases when we are able to lower
our operating Heat Rate compared to the Market Heat Rate and conversely decreases when our operating Heat Rate increases
compared to the Market Heat Rate. See also “— The Market for Power — Our Power Markets and Market Fundamentals” in
Item 1. of this Report for additional information on how these factors impact our Commodity Margin.
56
RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2012 AND 2011
Below are our results of operations for the year ended December 31, 2012, as compared to the same period in 2011 (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.
2012
2011
Change % Change
Operating revenues:
Commodity revenue............................................................................ $
Unrealized mark-to-market gain.........................................................
Other revenue......................................................................................
Operating revenues ........................................................................
5,417
$
6,753
$
48
13
35
12
5,478
6,800
(1,336)
13
1
(1,322)
Operating expenses:
Fuel and purchased energy expense:
Commodity expense ...........................................................................
Unrealized mark-to-market loss .........................................................
Fuel and purchased energy expense...............................................
Plant operating expense ......................................................................
Depreciation and amortization expense..............................................
Sales, general and other administrative expense ................................
Other operating expenses ......................................................................
Total operating expenses................................................................
(Gain) on sale of assets, net ..................................................................
(Income) from unconsolidated investments in power plants ................
Income from operations......................................................................
Interest expense.....................................................................................
Loss on interest rate derivatives............................................................
Interest (income) ...................................................................................
Debt extinguishment costs ....................................................................
Other (income) expense, net .................................................................
Income (loss) before income taxes .....................................................
Income tax expense (benefit) ................................................................
Net income (loss) ...........................................................................
Net income attributable to the noncontrolling interest..........................
2,894
130
3,024
922
562
140
78
4,726
(222)
(28)
1,002
736
14
(11)
30
15
218
19
199
—
Net income (loss) attributable to Calpine ................................. $
199
$
4,299
60
4,359
904
550
131
77
6,021
—
(21)
800
760
145
(9)
94
21
(211)
(22)
(189)
(1)
(190) $
1,405
(70)
1,335
(18)
(12)
(9)
(1)
1,295
222
7
202
24
131
2
64
6
429
(41)
388
1
389
(20)
37
8
(19)
33
#
31
(2)
(2)
(7)
(1)
22
#
33
25
3
90
22
68
29
#
#
#
#
#
Operating Performance Metrics:
MWh generated (in thousands)(1) ..........................................................
Average availability ..............................................................................
Average total MW in operation(1)..........................................................
Average capacity factor, excluding peakers..........................................
Steam Adjusted Heat Rate.....................................................................
2012
2011
Change % Change
112,216
90,875
21,341
91.3%
90.1%
27,318
27,234
53.7%
7,361
44.3%
7,412
1.2%
84
9.4%
51
23
1
—
21
1
__________
#
Variance of 100% or greater
57
(1) Represents generation and capacity from power plants that we both consolidate and operate. See “— Description of Our
Power Plants – Table of Operating Power Plants and Projects Under Construction and Advanced Development” for our
total equity generation and capacities.
We evaluate our Commodity revenue and Commodity expense on a collective basis because the price of power and
natural gas tend to move together as the price for power is generally determined by the variable operating cost of the next marginal
generator to be dispatched to meet demand. The spread between our Commodity revenue and Commodity expense represents a
significant portion of our Commodity Margin. Our financial performance is correlated to how we maximize our Commodity
Margin through management of our portfolio of power plants, as well as our hedging and optimization activities. See additional
segment discussion in “Commodity Margin and Adjusted EBITDA.”
Commodity revenue, net of Commodity expense, increased $69 million for the year ended December 31, 2012, compared
to the year ended December 31, 2011, primarily due to:
•
•
•
•
•
higher contribution from hedges primarily in our Texas segment during the third quarter of 2012 compared to the
third quarter of 2011;
higher generation in our Texas and North segments due to lower natural gas prices during 2012 compared to 2011
and higher generation in our West segment due to improved market conditions, less hydroelectric generation and a
nuclear power plant outage in California during 2012; and
an extreme cold weather event in Texas that occurred on February 2, 2011, and resulted in unplanned outages at
some of our power plants, negatively impacting our revenue for the year ended December 31, 2011, which did not
reoccur in 2012; partially offset by
lower regulatory capacity revenue during 2012 compared to 2011; and
the expiration of contracts which decreased revenue during the year ended December 31, 2012 compared to the year
ended December 31, 2011.
Generation increased 23% primarily due to lower natural gas prices in our Texas segment during certain periods in the
first half of 2012 and in our North segment during certain periods throughout 2012 and improved market conditions, less
hydroelectric generation and a nuclear power plant outage in our West segment during the year ended December 31, 2012. During
the year ended December 31, 2012, generation increased as natural gas prices were low enough that during certain periods some
of our modern, natural gas-fired, combined-cycle power plants in Texas and PJM became less expensive on a marginal basis than
coal-fired generation resulting in these plants running baseload. The increase in generation also resulted in a 1% decrease in our
Steam Adjusted Heat Rate for the year ended December 31, 2012, compared to the year ended December 31, 2011, as our power
plants tend to operate more efficiently under baseload operations. Our average total MW in operation increased by 84 MW primarily
due to the acquisition of our 762 MW Bosque Energy Center, our 565 MW York Energy Center which achieved COD in March
2011 and an increase in capacity resulting from our turbine modernization program partially offset by the temporary shut down
of our Los Esteros Critical Energy Facility associated with the upgrade from simple-cycle to combined-cycle technology.
Unrealized mark-to-market gain/loss from hedging our future generation and fuel needs, for the year ended December
31, 2012, compared to the year ended December 31, 2011, had an unfavorable variance of $57 million primarily driven by the
realization of favorable natural gas hedge positions in 2012 previously reported in unrealized mark-to-market gain/loss at December
31, 2011, partially offset by settlements during 2012 of Heat Rate hedge positions that were unfavorable based on forward curves
at December 31, 2011.
Despite a 23% increase in generation, our normal, recurring plant operating expense was largely unchanged for the year
ended December 31, 2012, compared to the year ended December 31, 2011, after accounting for $20 million in reimbursements
for insurance claims from prior periods that disproportionately reduced our plant operating expense for the year ended December
31, 2011.
Depreciation and amortization expense increased by $12 million for the year ended December 31, 2012, compared to the
year ended December 31, 2011, primarily resulting from a decrease of $17 million for the year ended December 31, 2011 related
to a revision in the expected settlement dates of the asset retirement obligations related to our natural gas-fired and geothermal
power plants, partially offset by a decrease of $2 million resulting from lower depreciation associated with the sale of Broad River
in December 2012.
Gain on sale of assets, net consists of a $215 million gain related to the sale of 100% of our ownership interests in each
of the Broad River Entities, and a $7 million gain related to the sale of our Riverside Energy Center, both of which closed in
December 2012. See Note 3 of the Notes to Consolidated Financial Statements for further information.
58
Income from unconsolidated investments in power plants increased for the year ended December 31, 2012, compared
to the year ended December 31, 2011, primarily due to a $3 million favorable change in fair value related to hedging activities
associated with derivative contracts at Greenfield LP, a $2 million increase in operating income for Whitby due to the expiration
of an unfavorable natural gas transportation contract in 2011 and a $1 million increase in operating income for Greenfield LP due
to lower natural gas prices in 2012 compared to 2011.
Interest expense decreased by $24 million for the year ended December 31, 2012, compared to the year ended December
31, 2011, primarily due to a decrease in our annual effective interest rate on our consolidated debt, excluding the impacts of
capitalized interest and unrealized gains (losses) on interest rate swaps, to 7.3% for the year ended December 31, 2012, from 7.6%
for the year ended December 31, 2011. The issuance of our First Lien Term Loans in 2011 and 2012 allowed us to reduce our
overall cost of debt by replacing a portion of our First Lien Notes and variable rate project debt with corporate level term loans
carrying a lower variable interest rate. See Note 6 of the Notes to Consolidated Financial Statements for further information
regarding the issuance of our First Lien Term Loans, the repayment of the portion of our First Lien Notes and the repayment of
variable rate project debt.
Loss on interest rate derivatives had a favorable change of $131 million for the year ended December 31, 2012, compared
to the year ended December 31, 2011, primarily resulting from $91 million of historical unrealized losses previously deferred in
AOCI and reclassified into income in January 2011 in connection with the retirement of the First Lien Credit Facility term loans.
Also contributing to the year-over-year change was a favorable change of $40 million resulting from interest rate swap breakage
costs related to the repayment of project debt in June 2011 and changes in fair value and settlements subsequent to the reclassification
date of the interest rate swaps formerly hedging our First Lien Credit Facility term loans. See Note 8 of the Notes to Consolidated
Financial Statements for further discussion of our interest rate swaps formerly hedging our First Lien Credit Facility term loans.
Debt extinguishment costs for the year ended December 31, 2012, consisted of $18 million associated with the redemption
premium, the write-off of unamortized deferred financing costs and debt premium and discount related to repayment of a portion
of our First Lien Notes and variable rate project debt during the fourth quarter of 2012, and $12 million associated with the purchase
of two of the three third party interests in GEC Holdings, LLC in March 2012 that were previously recorded as preferred interests
and classified as debt under U.S. GAAP. Debt extinguishment costs for the year ended December 31, 2011, primarily consisted
of $74 million associated with the repayment of the NDH Project Debt in March 2011, $19 million associated with the retirement
of the First Lien Credit Facility term loans in January 2011 in connection with the issuance of the 2023 First Lien Notes and $5
million related to the write-off of unamortized deferred financing costs related to the repayment of project debt in June 2011.
During the year ended December 31, 2012, we recorded an income tax expense of $19 million compared to an income
tax benefit of $22 million for the year ended December 31, 2011. The unfavorable year-over-year change primarily resulted from
a one-time $76 million benefit to reduce our valuation allowance due to the election to consolidate the CCFC group with the
Calpine group for 2011 federal income tax reporting purposes. Also, contributing to the unfavorable year-over-year change was
a decrease of $14 million in income tax expense for 2011 due to the expiration of a statute of limitation related to an uncertain tax
position. The overall unfavorable year-over-year change in income tax expense was partially offset by a refund of approximately
$10 million received in October 2012 related to the IRS approval of our 2004 amended federal income tax return and a decrease
in income tax expense for 2012 of $39 million primarily related to the application of intraperiod tax allocation and a decrease in
various state and foreign jurisdiction income taxes for the year ended December 31, 2012, compared to the year ended December
31, 2011.
59
RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2011 AND 2010
Below are our results of operations for the year ended December 31, 2011, as compared to the same period in 2010 (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.
2011
2010
Change % Change
Operating revenues:
Commodity revenue............................................................................ $
Unrealized mark-to-market gain (loss)...............................................
Other revenue......................................................................................
Operating revenues ........................................................................
Operating expenses:
Fuel and purchased energy expense:
Commodity expense ...........................................................................
Unrealized mark-to-market (gain) loss...............................................
Fuel and purchased energy expense...............................................
Plant operating expense ......................................................................
Depreciation and amortization expense..............................................
Sales, general and other administrative expense ................................
Other operating expenses....................................................................
Total operating expenses................................................................
Impairment losses .................................................................................
(Gain) on sale of assets, net ..................................................................
(Income) from unconsolidated investments in power plants ................
Income from operations......................................................................
Interest expense.....................................................................................
Loss on interest rate derivatives............................................................
Interest (income) ...................................................................................
Debt extinguishment costs ....................................................................
Other (income) expense, net .................................................................
Loss before income taxes and discontinued operations......................
Income tax benefit.................................................................................
Loss before discontinued operations ..................................................
Discontinued operations, net of tax expense.........................................
Net income (loss) ...........................................................................
Net income attributable to the noncontrolling interest..........................
Net income (loss) attributable to Calpine ................................. $
6,753
$
35
12
6,800
4,299
60
4,359
904
550
131
77
$
6,578
(61)
28
6,545
4,187
(204)
3,983
868
570
151
91
6,021
5,663
—
—
(21)
800
760
145
(9)
94
21
(211)
(22)
(189)
—
(189)
(1)
(190) $
116
(119)
(16)
901
813
223
(11)
91
15
(230)
(68)
(162)
193
31
—
31
$
175
96
(16)
255
(112)
(264)
(376)
(36)
20
20
14
(358)
116
(119)
5
(101)
53
78
(2)
(3)
(6)
19
(46)
(27)
(193)
(220)
(1)
(221)
3
#
(57)
4
(3)
#
(9)
(4)
4
13
15
(6)
#
#
31
(11)
7
35
(18)
(3)
(40)
8
(68)
(17)
#
#
—
#
Operating Performance Metrics:
MWh generated (in thousands)(1) ..........................................................
Average availability ..............................................................................
Average total MW in operation(1)..........................................................
Average capacity factor, excluding peakers..........................................
Steam Adjusted Heat Rate.....................................................................
2011
2010
Change % Change
90,875
88,323
2,552
90.1%
90.4%
(0.3)%
27,234
24,993
2,241
44.3%
7,412
46.0%
7,338
(1.7)%
(74)
3
—
9
(4)
(1)
60
__________________
#
Variance of 100% or greater
(1) Represents generation and capacity from power plants that we both consolidate and operate. See “— Description of Our
Power Plants – Table of Operating Power Plants and Projects Under Construction and Advanced Development” for our
total equity generation and capacities.
We evaluate our Commodity revenue and Commodity expense on a collective basis because the price of power and
natural gas tend to move together as the price for power is generally determined by the variable operating cost of the next marginal
generator to be dispatched to meet demand. The spread between our Commodity revenue and Commodity expense represents a
significant portion of our Commodity Margin. Our financial performance is correlated to how we maximize our Commodity
Margin through management of our portfolio of power plants, as well as our hedging and optimization activities. See additional
segment discussion in “Commodity Margin and Adjusted EBITDA.”
Commodity revenue, net of Commodity expense, increased $63 million for the year ended December 31, 2011, compared
to the year ended December 31, 2010, primarily due to:
•
•
•
•
the Conectiv Acquisition which closed on July 1, 2010, and our York Energy Center which achieved COD in March
2011; partially offset by
the negative impact in Texas of unplanned outages at some of our power plants caused by an extreme cold weather
event in early February 2011, which required us to purchase physical replacement power at prices substantially above
our hedged price;
lower Spark Spreads in our West segment resulting from a significant increase in hydroelectric generation in California
in 2011 compared to 2010; and
the expiration of certain hedge contracts which benefited the year ended December 31, 2010.
Our average total MW in operation increased by 2,241 MW, or 9%, primarily due to the Conectiv Acquisition which
closed on July 1, 2010 and our York Energy Center which achieved COD in March 2011 partially offset by the sale of a 25%
undivided interest in the assets of our Freestone power plant in December 2010. Generation increased 3% due primarily to higher
generation in the North due to the Conectiv Acquisition and our York Energy Center and higher generation in Texas driven by
extreme heat and drought conditions during the third quarter of 2011. The increase in generation was partially offset by lower
generation in the West resulting from weaker price conditions which also largely contributed to a 4% decrease in our average
capacity factor, excluding peakers in 2011 compared to 2010.
Unrealized mark-to-market gain/loss from hedging our future generation and fuel needs had an unfavorable variance of
$168 million primarily driven by the realization of favorable hedge positions in 2011 reported in unrealized mark-to-market gain/
loss at December 31, 2010, resulting in an unfavorable year-over-year change partially offset by unrealized gains on fuel and
purchased energy positions reported at December 31, 2011.
Other revenue decreased for the year ended December 31, 2011, compared to the year ended December 31, 2010, due
primarily to a decrease in other revenue of $15 million due to an adjustment related to prior periods on a major maintenance
contract which resulted in higher revenue recognized in the second quarter of 2010.
Plant operating expense increased by $36 million for the year ended December 31, 2011, compared to the year ended
December 31, 2010. Our normal, recurring plant operating expense decreased $32 million and costs related to unscheduled outages
decreased $22 million, due largely to insurance recoveries for the year ended December 31, 2011, compared to the year ended
December 31, 2010. The increase in plant operating expense was primarily due to an increase of $28 million related to our Mid-
Atlantic assets acquired in the Conectiv Acquisition, an increase of $7 million related to our York Energy Center which achieved
COD in March 2011, an increase of $41 million in major maintenance expense resulting from our plant outage schedule, an increase
of $6 million in costs from scrap parts related to outages, an increase in costs of $5 million related to our voluntary departure
incentive program which was initiated in the second quarter of 2011 and an increase of $3 million in stock-based compensation
expense.
Depreciation and amortization expense decreased for the year ended December 31, 2011, compared to the year ended
December 31, 2010, primarily resulting from a decrease of $39 million due to rotable parts being fully depreciated for some of
our units, a decrease of $17 million related to a revision in the expected settlement dates of the asset retirement obligations of our
power plants and a decrease of $5 million due to the sale of a 25% undivided interest in the assets of our Freestone power plant
in December 2010. The decrease was partially offset by an increase of $24 million related to our Mid-Atlantic assets acquired in
the Conectiv Acquisition, an increase of $6 million related to York Energy Center which achieved COD in March 2011 and an
increase of $11 million related to depreciation for assets placed into service during 2011.
61
Sales, general and other administrative expense decreased for the year ended December 31, 2011, compared to the year
ended December 31, 2010, primarily resulting from $26 million in Conectiv Acquisition-related costs incurred during the year
ended December 31, 2010. The decrease was partially offset by $10 million due to the reversal of a bad debt allowance in the first
quarter of 2010 as a result of Lyondell Chemical Co.’s emergence from Chapter 11 bankruptcy and the bankruptcy court’s acceptance
of our claim in the first quarter of 2010.
Other operating expenses decreased for the year ended December 31, 2011, compared to the year ended December 31,
2010, resulting from a decrease of $10 million in operating lease expense due to our purchase from a third party of the entity that
held the lease of South Point in December 2010 and a decrease of $3 million in royalty expense due to lower revenues from our
Geysers Assets resulting from lower prices in 2011 compared to 2010.
Impairment losses for the year ended December 31, 2010 consisted of an impairment of approximately $95 million related
to South Point (see Note 3 of the Notes to Consolidated Financial Statements for further information related to our acquisition of
the South Point lease and subsequent impairment of our South Point assets) and approximately $21 million associated with two
development projects that originated prior to our Chapter 11 bankruptcy proceedings. During the third quarter of 2010, we learned
the projects would not receive PPAs that would support their continued development and made the determination that continued
development was unlikely.
Gain on sale of assets, net consists of a $119 million gain recorded in the fourth quarter of 2010 related to the sale of a
25% undivided interest in the assets of our Freestone power plant. See Note 3 of the Notes to Consolidated Financial Statements
for further information.
Income from unconsolidated investments in power plants had a favorable variance for the year ended December 31, 2011,
compared to the year ended December 31, 2010, primarily due to a $4 million year-over-year increase in operating income for
Greenfield LP related to mechanical issues which impacted plant performance during the third quarter of 2010.
Interest expense decreased for the year ended December 31, 2011, compared to the year ended December 31, 2010,
primarily due to a $45 million favorable change in unrealized mark-to-market activity related to the interest rate swaps hedging
our variable rate debt that do not qualify for hedge accounting and a decrease of $7 million due to capitalized interest related to
project debt for two of our facilities under construction. Also contributing to the favorable year-over-year change in interest expense
was a decrease in our annual effective interest rate on our consolidated debt, excluding the impacts of capitalized interest and
unrealized gains (losses) on interest rate swaps, which decreased to 7.6% for the year ended December 31, 2011, from 7.9% for
the year ended December 31, 2010.
Loss on interest rate derivatives had a favorable change of $78 million for the year ended December 31, 2011, compared
to the year ended December 31, 2010, primarily resulting from a year-over-year decrease of $115 million in historical unrealized
losses previously deferred in AOCI and reclassified into income related to interest rate swaps formerly hedging our First Lien
Credit Facility term loans. See Note 8 of the Notes to Consolidated Financial Statements for further discussion of our interest rate
swaps formerly hedging our First Lien Credit Facility term loans. The favorable change was partially offset by an unfavorable
year-over-year change of approximately $20 million due to realized interest rate swap settlements and changes in fair value
subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility term loans. Also
contributing to the unfavorable year-over-year change was an increase of $17 million resulting from interest rate swap breakage
costs related to the repayment of project debt in June 2011.
Debt extinguishment costs for the year ended December 31, 2011, primarily consisted of $74 million associated with the
repayment of the NDH Project Debt in March 2011, $19 million associated with the retirement of the First Lien Credit Facility
term loans in January 2011 in connection with the issuance of the 2023 First Lien Notes and $5 million related to the write-off of
unamortized deferred financing costs related to the repayment of project debt in June 2011. Debt extinguishment costs for the year
ended December 31, 2010, consisted of $61 million associated with the retirement of term loans under the First Lien Credit Facility
in May, July and October 2010 in connection with the issuance of the 2019, 2020 and 2021 First Lien Notes and $30 million
associated with the acquisition of the Broad River lease which was accounted for as a refinancing of existing debt under U.S.
GAAP. See Note 3 of the Notes to Consolidated Financial Statements for further information regarding our acquisition of the
Broad River lease.
During the year ended December 31, 2011, we recorded an income tax benefit of $22 million compared to $68 million
for the year ended December 31, 2010. The year-over-year change primarily resulted from an unfavorable variance in income tax
expense of $128 million related to the application of intraperiod tax allocation and an increase in various state and foreign jurisdiction
income taxes of $19 million for the year ended December 31, 2011, compared to the year ended December 31, 2010. The unfavorable
variance in income tax expense was partially offset by a decrease in federal income tax of $101 million due primarily from a one-
time $76 million benefit to reduce our valuation allowance due to the election to consolidate the CCFC group with the Calpine
group for 2011 for federal income tax reporting purposes and a decrease of $14 million due to the expiration of a statute of limitation
62
related to an uncertain tax position. See Note 10 of the Notes to Consolidated Financial Statements for further discussion of the
election to consolidate the CCFC group and the Calpine group for federal tax reporting purposes.
Income from discontinued operations for the year ended December 31, 2010, primarily consisted of $160 million associated
with the gain, net of tax, on the sale of our 100% ownership interests in Blue Spruce and Rocky Mountain in December 2010.
Also included in the income from discontinued operations for the year ended December 31, 2010, are the results of operations for
Blue Spruce and Rocky Mountain. See Note 3 of the Notes to Consolidated Financial Statements for further discussion of our
discontinued operations.
63
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, RGGI compliance and other environmental costs, and realized settlements from our marketing, hedging
and optimization activities including natural gas transactions hedging future power sales, but excludes the unrealized portion of
our 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 16 of the Notes to Consolidated Financial Statements for a
reconciliation of Commodity Margin to income (loss) from operations by segment.
Commodity Margin by Segment for the Years Ended December 31, 2012 and 2011
The following tables show our Commodity Margin and related operating performance metrics by segment for the years
ended December 31, 2012 and 2011. 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.
West:
Commodity Margin (in millions) ........................................................ $
Commodity Margin per MWh generated ............................................ $
2012
994
29.77
2011
1,061
44.54
$
$
Change
$
$
(67)
(14.77)
% Change
(6)
(33)
MWh generated (in thousands) ...........................................................
Average availability.............................................................................
Average total MW in operation...........................................................
Average capacity factor, excluding peakers ........................................
Steam Adjusted Heat Rate...................................................................
33,390
23,823
9,567
91.9%
6,742
60.6%
7,278
88.2%
6,895
43.6%
7,418
3.7%
(153)
17.0%
140
40
4
(2)
39
2
West — Commodity Margin in our West segment decreased by $67 million, or 6%, for the year ended December 31,
2012 compared to the year ended December 31, 2011, due to lower contribution from hedges, lower market power prices associated
with our Geysers Assets which are based on absolute power price and lower revenue due to the expiration of contracts. The decrease
was partially offset by an increase in Commodity Margin on our open position driven by higher market Spark Spreads and a 40%
increase in generation driven primarily by improved market conditions, less hydroelectric generation and a nuclear power plant
outage in California during 2012. Our average total MW in operation decreased 153 MW, or 2%, due primarily to the temporary
shut down of our Los Esteros Critical Energy Facility at the end of 2011 associated with the upgrade from simple-cycle to combined-
cycle technology partially offset by an increase in capacity resulting from our turbine modernization program.
64
Texas:
Commodity Margin (in millions) ........................................................ $
Commodity Margin per MWh generated ............................................ $
2012
570
15.86
$
$
469
14.41
$
$
101
1.45
2011
Change
% Change
MWh generated (in thousands) ...........................................................
Average availability.............................................................................
Average total MW in operation...........................................................
Average capacity factor, excluding peakers ........................................
Steam Adjusted Heat Rate...................................................................
35,946
32,552
3,394
91.1%
7,127
57.4%
7,147
89.0%
6,988
53.2%
7,243
2.1%
139
4.2%
96
Texas — Commodity Margin in our Texas segment increased by $101 million, or 22%, for the year ended December 31,
2012 compared to the year ended December 31, 2011, due to higher contribution from our hedging activities that secured favorable
pricing despite lower settled market prices driven by milder weather primarily in the third quarter of 2012 compared to the same
period in 2011. We also realized higher Commodity Margin from a 10% increase in generation in 2012 driven by lower natural
gas prices. Generation increased as natural gas prices were low enough during certain periods in the first half of 2012 that some
of our modern, natural gas-fired, combined-cycle power plants in Texas became less expensive on a marginal basis than coal-fired
generation resulting in these plants running baseload. Also contributing to the year-over-year increase was the negative impact to
Commodity Margin in the first quarter of 2011 due to unplanned outages at some of our power plants caused by an extreme cold
weather event which occurred on February 2, 2011. Our average total MW in operation increased 139 MW due to the acquisition
of our 762 MW Bosque Energy Center in the fourth quarter of 2012 and an increase in capacity resulting from our turbine
modernization program.
North:
Commodity Margin (in millions) ........................................................ $
Commodity Margin per MWh generated ............................................ $
2012
729
33.55
2011
704
45.37
$
$
Change
$
25
$ (11.82)
MWh generated (in thousands) ...........................................................
Average availability.............................................................................
Average total MW in operation...........................................................
Average capacity factor, excluding peakers ........................................
Steam Adjusted Heat Rate...................................................................
21,732
15,517
6,215
89.3%
7,375
48.8%
7,914
91.6%
7,268
35.9%
7,919
(2.3)%
107
12.9 %
5
% Change
4
(26)
40
(3)
1
36
—
North — Commodity Margin in our North segment increased by $25 million, or 4%, for the year ended December 31,
2012 compared to the year ended December 31, 2011, primarily due to our York Energy Center which achieved COD in March
2011, higher contribution from hedges and a 40% increase in generation resulting from lower natural gas prices. During the year
ended December 31, 2012, generation increased as natural gas prices were low enough that during certain periods some of our
Mid-Atlantic modern, natural gas-fired, combined-cycle power plants became less expensive on a marginal basis than coal-fired
generation resulting in these power plants running baseload. The increase in Commodity Margin was partially offset by lower
regulatory capacity revenues and a decline in nodal pricing in PJM during the year ended December 31, 2012 compared to 2011.
Average total MW in operation increased 107 MW, or 1%, due primarily to our 565 MW York Energy Center and an increase in
capacity resulting from our turbine modernization program.
Southeast:
Commodity Margin (in millions) ........................................................ $
Commodity Margin per MWh generated ............................................ $
2012
245
11.59
$
$
240
12.64
$
$
5
(1.05)
2011
Change
% Change
MWh generated (in thousands) ...........................................................
Average availability.............................................................................
Average total MW in operation...........................................................
Average capacity factor, excluding peakers ........................................
Steam Adjusted Heat Rate...................................................................
21,148
18,983
2,165
93.4%
6,074
44.6%
7,309
91.9%
6,083
40.6%
7,312
1.5%
(9)
4.0%
3
Southeast — Commodity Margin in our Southeast segment increased by $5 million, or 2%, for the year ended December
31, 2012 compared to the year ended December 31, 2011, primarily due to higher contribution from hedges and an 11% increase
in generation largely driven by lower natural gas prices. The increase in Commodity Margin was largely offset by the negative
impact from the expiration of a contract during the third quarter of 2012.
65
22
10
10
2
2
8
1
2
(8)
11
2
—
10
—
Commodity Margin by Segment for the Years Ended December 31, 2011 and 2010
The following tables show our Commodity Margin and related operating performance metrics by segment for the years
ended December 31, 2011 and 2010. 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 consolidated and operate.
West:
Commodity Margin (in millions) ........................................................ $
Commodity Margin per MWh generated ............................................ $
2011
1,061
44.54
2010
1,080
34.94
$
$
Change
$
$
(19)
9.60
% Change
(2)
27
MWh generated (in thousands) ...........................................................
Average availability.............................................................................
Average total MW in operation...........................................................
Average capacity factor, excluding peakers ........................................
Steam Adjusted Heat Rate...................................................................
23,823
30,909
(7,086)
88.2%
6,895
43.6%
7,418
91.5%
6,911
56.5%
7,316
(3.3)%
(16)
(12.9)%
(102)
(23)
(4)
—
(23)
(1)
West — Commodity Margin in our West segment for the year ended December 31, 2011 was comparable to the year
ended December 31, 2010. During the year ended December 31, 2011, we experienced higher Commodity Margin contribution
from hedges as well as the positive impact of origination activities in 2011 compared to 2010. These positive factors were offset
by lower Spark Spreads resulting from a significant increase in hydroelectric generation in California in 2011 compared to 2010,
and lower Commodity Margin resulting from an unscheduled outage at OMEC during the second quarter of 2011. Consistent with
weaker price conditions, generation decreased 23% for the year ended December 31, 2011 compared to 2010. Average availability
decreased by 4% due to an increase in the duration of outages during the second quarter of 2011 compared to the second quarter
of 2010, as the weaker price environment provided an opportunity to extend the duration of scheduled maintenance outages due
to limited opportunity costs. Our average total MW in operation decreased 16 MW primarily due to the retirement of our Pittsburg
power plant in March 2010 as well as the expiration of our operating lease and subsequent retirement of our Watsonville (Monterey)
cogeneration power plant in May 2010 which was partially offset by an increase related to the completion of turbine modernizations
at two of our power plants in 2011.
Texas:
Commodity Margin (in millions) ........................................................ $
Commodity Margin per MWh generated ............................................ $
2011
469
14.41
$
$
504
16.71
$
$
(35)
(2.30)
2010
Change
% Change
MWh generated (in thousands) ...........................................................
Average availability.............................................................................
Average total MW in operation...........................................................
Average capacity factor, excluding peakers ........................................
Steam Adjusted Heat Rate...................................................................
32,552
30,169
2,383
89.0%
6,988
53.2%
7,243
87.6%
7,166
48.1%
7,236
1.4%
(178)
5.1%
(7)
Texas — Commodity Margin in our Texas segment decreased by $35 million, or 7%, for the year ended December 31,
2011, compared to the year ended December 31, 2010. Despite an increase in Commodity Margin contributions from hedges,
Commodity Margin was negatively impacted by unplanned outages at some of our power plants caused by an extreme cold weather
event which occurred on February 2, 2011. Power prices increased dramatically as a result of the cold weather event and the plant
outages, which required us to purchase physical replacement power at prices substantially above our hedged prices. Also
contributing to the year-over-year decrease in Commodity Margin was the sale of a 25% undivided interest in the assets of our
Freestone power plant in December 2010 which also drove a 178 MW, or 2%, decrease in our average total MW in operation
which was partially offset by an increase related to the completion of turbine modernizations at several of our power plants in
2011 and 2010. The decrease in Commodity Margin was partially offset by significantly higher power prices driven by extreme
heat and drought conditions which increased Spark Spreads during the third quarter of 2011 on our relatively small open position.
66
(7)
(14)
8
2
(2)
11
—
North:
Commodity Margin (in millions) ........................................................ $
Commodity Margin per MWh generated ............................................ $
MWh generated (in thousands) ...........................................................
Average availability.............................................................................
Average total MW in operation...........................................................
Average capacity factor, excluding peakers ........................................
Steam Adjusted Heat Rate...................................................................
2011
704
45.37
15,517
91.6%
7,268
35.9%
7,919
2010
Change
% Change
$
$
535
57.79
$
$
169
(12.42)
9,258
90.7%
4,833
32.8%
7,819
6,259
0.9%
2,435
3.1%
(100)
32
(21)
68
1
50
9
(1)
North — Commodity Margin in our North segment increased by $169 million, or 32%, primarily due to the Conectiv
Acquisition which closed on July 1, 2010 and our York Energy Center which achieved COD in March 2011 which were both also
the primary driver of the year-over-year increase in generation as well as the 2,435 MW increase in average total MW in operation
during the year ended December 31, 2011 compared to the year ended December 31, 2010. The increase in Commodity Margin
was partially offset by lower capacity prices in the second half of 2011 compared to the same period in 2010. Average capacity
factor, excluding peakers, increased 9% primarily due to scheduled outages at two of our power plants in the fourth quarter of
2010.
Southeast:
Commodity Margin (in millions) ........................................................ $
Commodity Margin per MWh generated ............................................ $
2011
240
12.64
$
$
272
15.12
$
$
(32)
(2.48)
2010
Change
% Change
MWh generated (in thousands) ...........................................................
Average availability.............................................................................
Average total MW in operation...........................................................
Average capacity factor, excluding peakers ........................................
Steam Adjusted Heat Rate...................................................................
18,983
17,987
91.9%
6,083
40.6%
7,312
92.5%
6,083
38.0%
7,315
996
(0.6)%
—
2.6 %
3
Southeast — Commodity Margin in our Southeast segment decreased by $32 million, or 12%, for the year ended December
31, 2011 compared to the year ended December 31, 2010 largely due to the expiration of certain hedge contracts which benefited
the year ended December 31, 2010 as well as lower Commodity Margin that resulted from unscheduled outages that occurred
during the second and third quarters of 2011.
Adjusted EBITDA
We define Adjusted EBITDA 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. Our Corporate Revolving Facility
includes a similar measure as a basis for our material covenants under the debt agreement that excludes our net interest in our
unconsolidated subsidiaries and includes distributions received from unconsolidated investments. However, we believe that
inclusion of our share of the Adjusted EBITDA of our unconsolidated subsidiaries is useful in evaluating our overall performance
and therefore we include Adjusted EBITDA from our unconsolidated investments and exclude distributions received from our
unconsolidated investments in our definition of Adjusted EBITDA. 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 also used by and 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,
67
(12)
(16)
6
(1)
—
7
—
any unrealized gains or losses from accounting for derivatives, 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 or
extinguishment of debt, Conectiv Acquisition-related costs and any extraordinary, unusual or non-recurring items plus the Adjusted
EBITDA from our discontinued operations and 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 (loss) from operations on a segment basis
and to net income (loss) attributable to Calpine on a consolidated basis for years ended December 31, 2012, 2011 and 2010 (in
millions).
West
Texas
North
Southeast
Consolidation
and
Elimination
Total
2012
Net income attributable to Calpine.......
Income tax expense ..............................
Debt extinguishment costs and other
(income) expense, net...........................
Loss on interest rate derivatives ...........
Interest expense, net of interest
income ..................................................
Income from operations ....................... $
Add:
Adjustments to reconcile income
from operations to Adjusted
EBITDA:
Depreciation and amortization
expense, excluding deferred
financing costs(1) ..............................
Major maintenance expense ............
Operating lease expense ..................
Unrealized (gain) loss on
commodity derivative mark-to-
market activity .................................
(Gain) on sale of assets, net.............
Adjustments to reflect Adjusted
EBITDA from unconsolidated
investments(2)(3) ................................
Stock-based compensation expense
Loss on dispositions of assets..........
Acquired contract amortization .......
Other ................................................
$
252
$
216
$
353
$
177
$
4
$
203
67
9
104
—
—
8
3
—
1
142
64
—
(66)
—
—
8
6
—
1
135
43
25
5
(7)
31
4
3
14
3
87
26
—
39
(215)
—
5
1
—
2
(3)
—
—
—
—
—
—
(1)
—
—
199
19
45
14
725
1,002
564
200
34
82
(222)
31
25
12
14
7
Total Adjusted EBITDA............. $
647
$
371
$
609
$
122
$
— $
1,749
68
Net loss attributable to Calpine ............
Net income attributable to the
noncontrolling interest..........................
Income tax benefit ................................
Debt extinguishment costs and other
(income) expense, net...........................
Loss on interest rate derivatives ...........
Interest expense, net of interest
income ..................................................
Income (loss) from operations.............. $
Add:
Adjustments to reconcile income
(loss) from operations to Adjusted
EBITDA:
Depreciation and amortization
expense, excluding deferred
financing costs(1) ..............................
Major maintenance expense ............
Operating lease expense ..................
Unrealized (gain) loss on
commodity derivative mark-to-
market activity .................................
Adjustments to reflect Adjusted
EBITDA from unconsolidated
investments(2)(3) ................................
Stock-based compensation expense
Loss on dispositions of assets..........
Acquired contract amortization .......
Other ................................................
2011
West
Texas
North
Southeast
Consolidation
and
Elimination
Total
$
(190)
518
$
(49) $
343
$
(17) $
5
$
192
58
9
(106)
—
10
8
—
11
135
81
—
123
—
7
4
—
1
138
23
26
3
36
3
2
8
11
92
43
—
5
—
4
2
—
2
(5)
—
—
—
—
—
—
—
—
1
(22)
115
145
751
800
552
205
35
25
36
24
16
8
25
Total Adjusted EBITDA............. $
700
$
302
$
593
$
131
$
— $
1,726
69
Net income attributable to Calpine .......
Discontinued operations, net of tax
expense..................................................
Income tax benefit.................................
Debt extinguishment costs and other
(income) expense, net ...........................
Loss on interest rate derivatives............
Interest expense, net of interest income
Income from operations ........................ $
Add:
Adjustments to reconcile income
from operations to Adjusted
EBITDA:
Depreciation and amortization
expense, excluding deferred
financing costs(1)...............................
Impairment losses.............................
Major maintenance expense .............
Operating lease expense ...................
Unrealized (gain) on commodity
derivative mark-to-market activity...
(Gain) on sale of assets, net..............
Adjustments to reflect Adjusted
EBITDA from unconsolidated
investments(2)(3).................................
Stock-based compensation expense .
Loss on dispositions of assets...........
Conectiv Acquisition-related costs(4)
Other.................................................
Adjusted EBITDA from continuing
operations ..............................................
Adjusted EBITDA from discontinued
operations ..............................................
2010
West
Texas
North
Southeast
Consolidation
and
Elimination
Total
$
31
380
$
237
$
250
$
27
$
7
$
207
97
27
19
(54)
—
—
11
—
—
2
689
75
150
—
87
—
(54)
(119)
—
8
9
—
—
318
—
111
—
18
26
(17)
—
34
2
—
36
1
461
—
112
19
25
—
(18)
—
—
3
1
—
—
169
—
(7)
—
—
—
—
—
—
—
—
—
—
—
—
(193)
(68)
106
223
802
901
573
116
157
45
(143)
(119)
34
24
10
36
3
1,637
75
Total Adjusted EBITDA.............. $
764
$
318
$
461
$
169
$
— $
1,712
_____________
(1) Depreciation and amortization expense in the income (loss) from operations calculation on our Consolidated Statements
of Operations excludes amortization of other assets.
(2)
Included on our Consolidated Statements of Operations in (income) from unconsolidated investments in power plants.
(3) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include unrealized (gain) loss on mark-to-
market activity of nil, $1 million and $1 million for the years ended December 31, 2012, 2011 and 2010, respectively.
(4)
Includes $26 million included in sales, general and other administrative expense and $10 million included in plant operating
expense.
70
LIQUIDITY AND CAPITAL RESOURCES
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
At December 31, 2012, we had $1,284 million in cash and cash equivalents and $253 million of restricted cash. Amounts
available for future borrowings were $757 million under our Corporate Revolving Facility. The following table provides a summary
of our liquidity position at December 31, 2012 and 2011 (in millions):
Cash and cash equivalents, corporate(1) .............................................................................................. $
Cash and cash equivalents, non-corporate..........................................................................................
Total cash and cash equivalents........................................................................................................
Restricted cash ....................................................................................................................................
Revolving facility(ies) availability .....................................................................................................
Letter of credit availability(2) ..............................................................................................................
Total current liquidity availability............................................................................................... $
2012
2011
1,153
131
1,284
253
757
—
2,294
$
$
946
306
1,252
194
560
7
2,013
____________
(1)
(2)
Includes $11 million and $34 million of margin deposits held by us posted by our counterparties at December 31, 2012 and
2011, respectively.
Includes availability under our CDHI letter of credit facility. On January 10, 2012, we increased the CDHI letter of credit
facility to $300 million and extended the maturity date to January 2, 2016. As a result of the completion of the sale of
Riverside Energy Center, LLC, a wholly-owned subsidiary of CDHI, on December 31, 2012, we are required to cash
collateralize letters of credit issued in excess of $225 million until replacement collateral is contributed to the CDHI collateral
package which we are in the process of arranging. At December 31, 2012, we had $28 million of cash collateral posted in
support of outstanding letters of credit under our CDHI letter of credit facility. We do not believe that this change will have
a material impact on our liquidity.
Our principal source for future liquidity is cash flows generated from our operations. 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. 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.
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 accounts with
investment banks that are not FDIC insured. We place our cash, cash equivalents and restricted cash in what we believe to be
creditworthy financial institutions and 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 have never paid cash dividends on our common stock. Future cash dividends, if any, will be 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.
71
Liquidity Sensitivity
Significant changes in commodity prices and Market Heat Rates can have an impact on 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 January 18, 2013, an increase of $1/MMBtu in natural gas prices would result in an increase of collateral required by
approximately $52 million. If natural gas prices decreased by $1/MMBtu, we estimate that our collateral requirements would
increase by approximately $69 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
January 18, 2013, an increase of 500 Btu/KWh in the Market Heat Rate would result in an increase in collateral required by
approximately $30 million. If Market Heat Rates were to fall at a similar rate, we estimate that our collateral required would
decrease by $28 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, historically 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 2013 and beyond. In addition to the price of natural gas, the
future impact on 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;
the speed, strength and duration of an economic recovery;
• maintaining acceptable availability levels for our fleet;
•
•
•
•
the impact 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.
Our letters of credit, capital management, construction, upgrades and growth initiatives are further discussed below.
Letter of Credit Facilities
The Corporate Revolving Facility represents our primary revolving facility. The table below represents amounts issued
under our letter of credit facilities at December 31, 2012 and 2011 (in millions):
Corporate Revolving Facility ............................................................................................................. $
CDHI...................................................................................................................................................
Various project financing facilities.....................................................................................................
Total.................................................................................................................................................. $
2012
2011
243
253
130
626
$
$
440
193
130
763
Capital Management and Significant Financing Transactions
In connection with our goals of enhancing long-term shareholder value and leveraging our three scale regions, we have
completed, initiated or made progress toward completing the following key capital and financing transactions during 2012, as
further described below.
72
2019 First Lien Term Loan
On October 9, 2012, we entered into and borrowed $835 million under our 2019 First Lien Term Loan, which bears
interest, at our option, at either (i) the base rate, equal to the higher of the Federal Funds effective rate plus 0.5% per annum or
the Prime Rate (as such terms are defined in the 2019 First Lien Term Loan credit agreement), plus an applicable margin of 2.25%,
or (ii) LIBOR plus 3.25% per annum subject to a LIBOR floor of 1.25%. We used the net proceeds received to redeem 10% of
the aggregate principal amount of each series of our existing First Lien Notes at a redemption price of 103% of the principal
amount redeemed and to repay project debt totaling $218 million, plus accrued and unpaid interest for each. The 2019 First Lien
Term Loan allows us to reduce our overall cost of debt by replacing a portion of our First Lien Notes with fixed interest rates
ranging from 7.25% to 8.0% with a corporate level term loan carrying a lower variable interest rate currently at 4.5% and to repay
variable rate project debt. The 2019 First Lien Term Loan carries substantially the same terms as the First Lien Term Loans and
matures on October 9, 2019. The 2019 First Lien Term Loan also contains substantially similar covenants, qualifications, exceptions
and limitations as the First Lien Term Loans and First Lien Notes.
Acquisition of Bosque Energy Center
On November 7, 2012, we, through our indirect, wholly-owned subsidiary Calpine Bosque Energy Center, LLC, completed
the purchase of a power plant with a nameplate capacity of 800 MW owned by Bosque Power Co., LLC, for approximately $432
million. The modern, natural gas-fired, combined-cycle power plant increased capacity in our Texas segment and is located in
Central Texas near the unincorporated community of Laguna Park in Bosque County. The site includes a 250 MW generation
block with one natural-gas turbine, one heat recovery steam generator and one steam turbine that achieved COD in June 2001 and
a 550 MW generation block with two natural-gas turbines that went online in June 2000 as well as two heat recovery steam
generators and one steam turbine that achieved COD in June 2011. We funded the $432 million purchase price with cash on hand.
Sale of Riverside Energy Center
Our 603 MW Riverside Energy Center had a PPA that provided WP&L an option to purchase the power plant and plant-
related assets upon written notice of exercise prior to May 31, 2012. On May 18, 2012, WP&L exercised their option to purchase
Riverside Energy Center, LLC, one of our VIEs which owned Riverside Energy Center. The sale closed on December 31, 2012
for approximately $402 million, and we recorded a pre-tax gain of approximately $7 million, which is included in (gain) on sale
of assets, net on our Consolidated Statements of Operations. We expect to use the sale proceeds for our capital allocation activities
and for general corporate purposes.
Sale of Broad River
On December 27, 2012, we, through our indirect, wholly-owned subsidiary Calpine Power Company, completed the sale
of 100% of our ownership interest in each of the Broad River Entities for approximately $423 million. This transaction resulted
in the disposition of our Broad River power plant, an 847 MW natural gas-fired, peaking power plant located in Gaffney, South
Carolina, and includes a five year consulting agreement with the buyer. We recorded a pre-tax gain of approximately $215 million
in December 2012, which is included in (gain) on sale of assets, net on our Consolidated Statements of Operations.We expect to
use the sale proceeds for our capital allocation activities and for general corporate purposes.
CDHI
On January 10, 2012, we increased the CDHI letter of credit facility to $300 million and extended the maturity date to
January 2, 2016. As a result of the completion of the sale of Riverside Energy Center, LLC, a wholly-owned subsidiary of CDHI,
on December 31, 2012, we are required to cash collateralize letters of credit issued in excess of $225 million until replacement
collateral is contributed to the CDHI collateral package which we are in the process of arranging. At December 31, 2012, we had
$28 million of cash collateral posted in support of outstanding letters of credit under our CDHI letter of credit facility. We do not
believe that this change will have a material impact on our liquidity.
Share Repurchase Program
On August 23, 2011, we announced that our Board of Directors had authorized the repurchase of up to $300 million in
shares of our common stock. In April 2012, our Board of Directors authorized us to double the size of our share repurchase program,
increasing our permitted cumulative repurchases to $600 million in shares of our common stock. As of the filing of this Report,
we have completed our previously announced $600 million share repurchase program, having repurchased a total of 35,568,833
shares of our outstanding common stock at an average price paid of $16.87 per share. In February 2013, our Board of Directors
authorized the repurchase of an additional $400 million in shares of our common stock, bringing the cumulative authorization
total to $1.0 billion.
73
Construction, Modernizations and Growth Initiatives
We remain focused on our goal to continue to grow our presence in core markets with an emphasis on 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 will actively seek divestiture opportunities on our non-core assets if those opportunities
meet our financial expectations. In addition, we believe that modernizations and expansions to our current assets or using existing
equipment offer proven and financially disciplined opportunities to improve our operations, capacity and efficiencies. Our
significant projects under construction, growth initiatives and modernizations are discussed below.
West:
Russell City Energy Center — Construction at our Russell City Energy Center continues to move forward. Upon
completion, this project will bring on line approximately 429 MW of net interest baseload capacity (464 MW with peaking capacity)
representing our 75% share. Construction is ongoing and COD is expected in the summer of 2013. Upon completion, the Russell
City Energy Center is contracted to deliver its full output to PG&E under a ten-year PPA.
Los Esteros Critical Energy Facility — During 2009, we and PG&E negotiated a new PPA to replace the existing California
Department of Water Resources contract and facilitate the modernization of our Los Esteros Critical Energy Facility from a 188
MW simple-cycle generation power plant to a 309 MW combined-cycle generation power plant, which will also increase the
efficiency and environmental performance of the power plant by lowering the Heat Rate. Construction is ongoing and COD is
expected in the summer of 2013.
Texas:
Channel and Deer Park Expansions — In September and November 2011, we filed air permit applications with the
TCEQ and the EPA to expand the baseload capacity of the Deer Park and Channel Energy Centers by approximately 260 MW
each. We received air permit approvals from the TCEQ for our Deer Park and Channel expansion projects in September and
October 2012, respectively, and from the EPA in November 2012. Construction on these expansion projects commenced in the
fourth quarter of 2012. We expect COD during the summer of 2014 for these expansions and are currently evaluating funding
sources including, but not limited to, nonrecourse financing, corporate financing or internally generated funds.
North:
Garrison Energy Center — We are actively permitting 618 MW of new combined-cycle capacity at a development site
secured by a long-term lease with the City of Dover. For the first phase (309 MW), we have executed the Interconnection Services
Agreement and the Interconnection Construction Services Agreement with PJM. For the second phase (309 MW), we have
completed a feasibility study and are currently conducting a system impact study. Environmental permitting, site development
planning and development engineering are underway and the first phase’s capacity cleared PJM’s 2015/2016 base residual auction.
We received the air permit and executed a preliminary notice to proceed for the engineering, procurement and construction
agreement during the first quarter of 2013. We expect COD for the first phase by the summer of 2015 and are currently evaluating
funding sources including, but not limited to, nonrecourse financing, corporate financing or internally generated funds.
All Segments:
Turbine Modernization — We continue to move forward with our turbine modernization program. Through December 31,
2012, we have completed the upgrade of eleven Siemens and eight GE turbines totaling over 200 MW and have committed to
upgrade approximately three additional turbines.
74
Major Maintenance and Capital Spending
Our major maintenance and capital spending remains an important part of our business. Our expected expenditures for
2013 are as follows (in millions):
Major maintenance expense ....................................................................................................................................... $
Capital expenditures, operations, net .........................................................................................................................
Growth related capital expenditures...........................................................................................................................
Total major maintenance expense and capital spending..........................................................................................
Less: Amounts expected to be funded with financing(1).............................................................................................
Net major maintenance expense and capital spending ............................................................................................ $
2013
210
160
450
820
(200)
620
__________
(1) Consist of amounts to be drawn under our Russell City Project Debt and Los Esteros Project Debt.
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, 2012, our consolidated federal NOLs totaled approximately $7.3 billion. See Note
10 of the Notes to Consolidated Financial Statements for further discussion of our NOLs.
Cash Flow Activities
The following table summarizes our cash flow activities for the years ended December 31, 2012, 2011 and 2010 (in
millions):
Beginning cash and cash equivalents.......................................................................... $
Net cash provided by (used in):
2012
2011
2010
1,252
$
1,327
$
989
Operating activities...................................................................................................
Investing activities ....................................................................................................
Financing activities...................................................................................................
Net increase (decrease) in cash and cash equivalents..........................................
Ending cash and cash equivalents ................................................................... $
653
(470)
(151)
32
1,284
$
775
(836)
(14)
(75)
1,252
$
929
(831)
240
338
1,327
2012 — 2011
Net Cash Provided By Operating Activities
Cash provided by operating activities for the year ended December 31, 2012, was $653 million compared to $775 million
for the year ended December 31, 2011. The decrease in cash provided by operating activities was primarily due to:
• Working capital — Working capital employed increased by approximately $58 million for the year ended December
31, 2012 compared to 2011 after adjusting for debt related balances and non-hedging interest rate swaps which did
not impact cash provided by operating activities. The increase was primarily due to increased margin requirements
during the year ended December 31, 2012.
•
Interest paid — Cash paid for interest increased by $63 million to $719 million for the year ended December 31,
2012, as compared to $656 million for 2011. The increase was primarily due to timing of interest payments on our
First Lien Notes and First Lien Term Loans partially offset by lower payments on our NDH Project Debt and other
project debt.
• Prepayment premiums — For the year ended December 31, 2012, we paid $29 million in prepayment premiums
related to a repayment of a portion of our First Lien Notes and our variable rate project debt compared to $13 million
in prepayment premiums related to the extinguishment of the NDH Project Debt for the year ended December 31,
2011.
• Ground lease modification — For the year ended December 31, 2012, we paid $28 million related to a renegotiated
ground lease at one of our operating plants. We made no similar payments for the year ended December 31, 2011.
75
Our decrease in cash provided by operating activities was partially offset by the following:
•
Income from operations — Income from operations, adjusted for non-cash items increased by $45 million for the
year ended December 31, 2012, as compared to 2011. Non-cash items consist primarily of depreciation and
amortization, gains and losses on sales of assets, impairment losses, income and losses from unconsolidated
investments and unrealized gains and losses in mark-to-market activity.
Net Cash Used In Investing Activities
Cash flows used in investing activities for the year ended December 31, 2012, was $470 million compared to cash flows
used in investing activities of $836 million for the year ended December 31, 2011. The decrease was primarily due to:
• Capital expenditures — Payments made for capital expenditures for the year ended December 31, 2012, were
approximately $637 million, compared to payments of approximately $683 million for the year ended December 31,
2011. The year-over-year decrease was primarily due to the timing of cash payments.
• Higher proceeds from sales of power plants, interests and other — For the year ended December 31, 2012, we
received proceeds of approximately $825 million related to the sale of 100% of our ownership interests in each of
the Broad River Entities and the sale of our Riverside Energy Center, compared to proceeds of approximately $13
million from the disposition of other plant assets for the year ended December 31, 2011.
•
•
Settlement of non-hedging interest rate swaps — During the year ended December 31, 2012 we terminated our legacy
interest rate swaps formerly hedging our First Lien Credit Facility resulting in payments of $156 million, compared
to payments of $189 million during the same period in 2011.
Transmission credits — During the year ended December 31, 2012, we paid $12 million for transmission credits
related to the construction of our Russell City Energy Center compared to $31 million paid during the year ended
December 31, 2011.
The decrease in cash flows used in investing activities was partially offset by:
• Purchase of power plant — In 2012 we purchased a natural gas-fired, combined-cycle power plant located in Bosque
County, Texas for approximately $432 million. There were no acquisitions in 2011.
• Restricted cash — Restricted cash increased by $59 million for the year ended December 31, 2012, compared to a
decrease of $54 million for the same period in 2011. The increase was primarily due to additional cash collateral
requirements related to the change in capacity under the CDHI letter of credit facility associated with the completion
of the sale of the Riverside Energy Center. The decrease in restricted cash in 2011 was primarily due to the maturity
of project debt and the corresponding reduction in restricted cash requirements.
Net Cash Used In Financing Activities
Cash flows used in financing activities were $151 million for the year ended December 31, 2012, compared to $14 million
for the year ended December 31, 2011. The increase in cash flows used in financing activities was primarily due to:
•
Lower net borrowings under the First Lien Term Loans — During the year ended December 31, 2012, we received
proceeds of approximately $835 million from the issuance of the 2019 First Lien Term Loan, an $822 million decrease
compared to the $1.7 billion in proceeds received from the 2018 First Lien Term Loans issued in the year ended
December 31, 2011.
• Repayments of First Lien Term Loans — During the year ended December 31, 2012, we redeemed 10% of the
aggregate principal amount of each series of our existing First Lien Notes for approximately $590 million and made
no similar redemption during the year ended December 31, 2011. The redemption in 2012 was funded from the $835
million in proceeds received from the issuance of the 2019 First Lien Term Loan.
•
Stock repurchases — During the year ended December 31, 2012, we made payments under the share repurchase
program of approximately $463 million, compared to payments of approximately $119 million for the year ended
December 31, 2011.
• Decreased contributions from noncontrolling interest holder — During the year ended December 31, 2012, we
received no proceeds from a noncontrolling interest holder in Russell City Energy Company, LLC, compared to
approximately $33 million for the year ended December 31, 2011.
76
The increase in cash flows used in financing activities was partially offset by:
• Repayments on NDH Project Debt — During the year ended December 31, 2012, we made no repayments on the
NDH Project Debt, compared to payments of approximately $1.3 billion for the year ended December 31, 2011. This
repayment was funded by the $1.7 billion in proceeds received from the issuance of the 2018 First Lien Term Loans
during the year ended December 31, 2011.
•
•
•
Lower repayments of project debt, notes payable and other — During the year ended December 31, 2012, we made
repayments of approximately $289 million, primarily due to the retirement of the BRSP project debt. During the
year ended December 31, 2011, we made repayments of $550 million, primarily due to the repayment of the Deer
Park and Metcalf project debt.
Increased proceeds from project debt, notes payable and other — During the year ended December 31, 2012, we
received proceeds of approximately $389 million related to our Russell City Project Debt and Los Esteros Project
Debt, compared to $327 million for the same period in 2011.
Lower financing costs — During the year ended December 31, 2012, we paid financing costs of approximately $20
million compared to approximately $81 million for the year ended December 31, 2011.
2011 — 2010
Net Cash Provided By Operating Activities
Cash provided by operating activities for the year ended December 31, 2011, was $775 million compared to $929 million
for the year ended December 31, 2010. The decrease in cash provided by operating activities was primarily due to:
• Working capital — Working capital employed increased by approximately $194 million for the year ended December
31, 2011 compared to 2010 after adjusting for debt related balances and non-hedging interest rate swaps which did
not impact cash provided by operating activities. The increase was primarily due to a reduction in margin requirements
during the year ended December 31, 2010.
•
Interest paid — Cash paid for interest, inclusive of interest rate swaps in hedging relationships, increased by $21
million to $656 million for the year ended December 31, 2011, as compared to $635 million for 2010. The increase
was primarily due to timing of interest payments on our First Lien Notes and 2018 First Lien Term Loans as compared
to the previously outstanding First Lien Credit Facility and project debt.
• Prepayment premiums — For the year ended December 31, 2011, we paid $13 million of prepayment premiums
related to the extinguishment of the NDH Project Debt.
Our decrease in cash provided by operating activities was partially offset by the following:
•
Income from operations — Income from operations, adjusted for non-cash items increased by $41 million for the
year ended December 31, 2011, as compared to 2010. Non-cash items consist primarily of depreciation and
amortization, gains and losses on sales of assets, impairment losses, income and losses from unconsolidated
investments and unrealized gains and losses in mark-to-market activity.
Net Cash Used In Investing Activities
Cash flows used in investing activities for the year ended December 31, 2011, were $836 million compared to cash flows
used in investing activities of $831 million for the year ended December 31, 2010. The difference was primarily due to:
• Purchase of Conectiv assets and BRSP — We purchased the Conectiv assets and BRSP for approximately $1.7 billion
in 2010. There were no acquisitions in 2011.
• Capital expenditures — Capital expenditures increased by $314 million primarily resulting from construction activity
at the Russell City Energy Center, Los Esteros Critical Energy Facility and York Energy Center combined with our
turbine modernization program.
•
•
Lower proceeds from sales of power plants, interests and other — For the year ended December 31, 2011, we received
proceeds of approximately $13 million from the disposal of other plant assets compared to proceeds of approximately
$954 million primarily relating to the sale of Blue Spruce, Rocky Mountain and a 25% undivided interest in the
assets of our Freestone power plant for the year ended December 31, 2010.
Settlement of non-hedging interest rate swaps — During the year ended December 31, 2011 we made payments on
interest rate swap derivative instruments associated with swaps that formerly hedged variable rate debt which was
converted to fixed rate debt of $189 million compared to payments of $69 million during the same period in 2010.
77
• Restricted cash — The net decrease in restricted cash was $54 million for the year ended December 31, 2011,
compared to $322 million for the same period in 2010. The decrease in restricted cash in 2011 as compared to 2010
was primarily due to the maturity of project debt and the corresponding reduction in restricted cash requirements.
•
Transmission credits — During the year ended December 31, 2011, we paid $31 million for transmission credits
related to construction of our Russell City Energy Center.
Net Cash Provided By (Used In) Financing Activities
Cash flows used in financing activities were $14 million for the year ended December 31, 2011, compared to cash flows
provided by financing activities of $240 million for the year ended December 31, 2010. The change in cash flows provided by
(used in) financing activities was primarily related to:
•
•
Issuance of the 2018 First Lien Term Loans — During the year ended December 31, 2011, we received proceeds of
approximately $1.7 billion from the issuance of the 2018 First Lien Term Loans. We used the proceeds to repay our
NDH Project Debt of approximately $1.3 billion resulting in a net increase of $374 million.
Issuance of the First Lien Notes — We received proceeds of approximately $1.2 billion from the issuance of the
2023 First Lien Notes and used those proceeds to terminate the First Lien Credit Facility in accordance with its
repayment terms resulting in a net increase of $5 million during the year ended December 30, 2011, compared to a
net increase of $14 million during the year ended December 31, 2010.
• Reduced proceeds from project debt — During the year ended December 31, 2011, we received proceeds of
approximately $327 million related to our Russell City Project Debt and Los Esteros Project Debt. During 2010 we
received proceeds of approximately $1.3 billion to fund the Conectiv Acquisition.
•
•
Lower repayments of project debt — During the year ended December 31, 2011, we made repayments on project
debt of approximately $550 million, compared to approximately $937 million for the year ended December 31, 2010.
Increased contributions from noncontrolling interest holder — During the year ended December 31, 2011, we received
proceeds of approximately $34 million from a noncontrolling interest holder in Russell City Energy Center, compared
to contributions of approximately $17 million for the year ended December 31, 2010.
• Decreased finance costs — During the year ended December 31, 2011, primarily due to the refinancing of the First
Lien Credit Facility and the NDH Project Debt, we incurred $81 million in finance costs primarily related to the
issuance of the First Lien Notes and project debt, compared to $136 million in finance costs primarily related to the
issuance of the First Lien Notes and project debt.
•
Stock repurchases — During the year ended December 31, 2011, we made payments of approximately $119 million
under the share repurchase program announced on August 23, 2011. There were no similar repurchases during the
same period in 2010.
Counterparties and Customers
Our counterparties primarily consist of three categories of entities who participate in the wholesale energy markets:
financial institutions and trading companies; regulated utilities, municipalities, cooperatives, ISOs and other retail power suppliers;
and oil, natural gas, chemical and other energy-related industrial companies. We have exposure to trends within the energy industry,
including declines in the creditworthiness of our counterparties. We have concentrations of credit risk with a few of our commercial
customers relating to our sales of power, steam and hedging and optimization activities. Currently, certain of our counterparties
within the energy industry have below investment grade credit ratings. 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.
Credit Considerations
Our credit rating has, among other things, generally required us to post significant collateral with our hedging
counterparties. Our collateral is generally in the form of cash deposits, letters of credit or first liens on our assets. See also Note
9 of the Notes to Consolidated Financial Statements for our use of collateral. Our credit rating has also reduced the number of
hedging counterparties willing to extend credit to us and reduced our ability to negotiate more favorable terms with them. However,
we believe that we will continue to be able to work with our hedging counterparties to execute beneficial hedging transactions
and provide adequate collateral. At December 31, 2012, our First Lien Notes, First Lien Term Loans, Corporate Revolving Facility
and our corporate rating had the following ratings and commentary from Standard and Poor’s and Moody’s Investors Service:
78
First Lien Notes, First Lien Term Loans and Corporate Revolving Facility
rating..............................................................................................................
Corporate rating.............................................................................................
Commentary ..................................................................................................
BB-
B+
Stable
B1
B1
Stable
Standard and Poor’s
Moody’s Investors
Service
Off Balance Sheet Arrangements
Our power plant operating leases are not reflected on our Consolidated Balance Sheets and contain customary restrictions
on dividends up to Calpine Corporation, additional debt and further encumbrances similar to those typically found in project
finance debt instruments. See Note 15 of the Notes to Consolidated Financial Statements for the future minimum lease payments
under our power plant operating leases.
Some of our unconsolidated equity method investments have debt that is not reflected on our Consolidated Balance
Sheets. As of December 31, 2012, our equity method investees (Greenfield LP and Whitby) had aggregate debt outstanding of
$448 million. Based on our pro rata share of each of the investments, our share of such debt would be approximately $224 million.
All such debt is non-recourse to us. See Note 5 of the Notes to Consolidated Financial Statements for additional information on
our investments.
Guarantee Commitments — As part of our normal business operations, we enter into various agreements providing, or
otherwise arranging, financial or performance assurance to third parties on behalf of our subsidiaries in the ordinary course of
such subsidiaries’ respective business. Such arrangements include guarantees, standby letters of credit and surety bonds for power
and natural gas purchase and sale arrangements and contracts associated with the development, construction, operation and
maintenance of our fleet of power plants. These arrangements are entered into primarily to support or enhance the creditworthiness
otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the
subsidiaries’ intended commercial purposes. Our primary commercial obligations as of December 31, 2012, are as follows (in
millions):
Guarantee Commitments
Guarantee of subsidiary debt(1) ... $
Standby letters of credit(2)(4) ........
Surety bonds(3)(4)(5) ......................
Guarantee of subsidiary
operating lease payments(4) .....
Total............................................ $
___________
Amounts of Commitment Expiration per Period
2013
2014
2015
2016
2017
47
536
—
7
590
$
$
36
41
—
3
80
$
$
37
—
—
—
37
$
$
36
—
—
—
36
$
$
Thereafter
209
$
30
4
Total
Amounts
Committed
391
$
626
4
—
243
$
10
1,031
$
26
19
—
—
45
(1)
(2)
(3)
(4)
(5)
Represents Calpine Corporation guarantees of certain power plant capital leases and related interest. All guaranteed capital
leases are recorded on our Consolidated Balance Sheets.
The standby letters of credit disclosed above represent those disclosed in Note 6 of the Notes to Consolidated Financial
Statements.
The majority of surety bonds do not have expiration or cancellation dates.
These are contingent off balance sheet obligations.
As of December 31, 2012, $3 million of cash collateral is outstanding related to these bonds.
79
Contractual Obligations — Our contractual obligations as of December 31, 2012, are as follows (in millions):
Operating lease obligations(1)....................................... $
Purchase obligations:
Turbine commitments ............................................. $
Commodity purchase obligations(2).........................
LTSA.......................................................................
Cost to complete construction projects ...................
Other purchase obligations(3)...................................
Total purchase obligations(4) ........................................ $
Debt(5)........................................................................... $
Other contractual obligations:
Interest payments on debt(5)(6) ................................. $
Liability for uncertain tax positions ........................
Interest rate swap agreement(6)................................
Total other contractual obligations............................... $
___________
Total
568
28
3,003
68
241
1,554
4,894
10,762
4,886
60
206
5,152
$
$
$
$
$
$
Less than 1
Year
1-3 Years
3-5 Years
More than 5
Years
57
24
486
20
228
148
906
97
683
—
41
724
$
$
$
$
$
$
102
4
668
14
13
309
1,008
326
1,361
28
85
1,474
$
$
$
$
$
$
98
$
311
— $
504
34
—
247
785
2,759
1,252
—
57
1,309
$
$
$
$
—
1,345
—
—
850
2,195
7,580
1,590
32
23
1,645
(1)
(2)
(3)
Included in the total are future minimum payments for power plant, office, land and other operating leases. See Note 15 of
the Notes to Consolidated Financial Statements for more information.
The amounts presented here include contracts for the purchase, transportation, or storage of commodities accounted for as
executory contracts and therefore not recognized as liabilities on our Consolidated Balance Sheet.
The amounts presented here include water agreements, maintenance agreements, parts supply agreements and other purchase
obligations.
(4)
The amounts included above for purchase obligations represent the minimum requirements under contract.
(5) A note payable totaling $33 million associated with the sale of the PG&E note receivable to a third party is excluded from
debt for this purpose as it is a non-cash liability.
(6) Amounts are projected based upon interest rates at December 31, 2012.
Special Purpose Subsidiaries
Pursuant to applicable transaction agreements, we have established certain of our entities separate from Calpine
Corporation and our other subsidiaries. In accordance with applicable accounting standards, we consolidate these entities. As of
the date of filing of this Report, these entities included: GEC Holdings, LLC, Gilroy Energy Center, LLC, Creed, Goose Haven,
Calpine Gilroy Cogen, L.P., Calpine Gilroy 1, Inc., Calpine King City Cogen, LLC, Calpine Securities Company, L.P. (a parent
company of Calpine King City Cogen, LLC), Calpine King City, LLC (an indirect parent company of Calpine Securities Company,
L.P.), Russell City Energy Company, LLC and OMEC. The financial information provided below represents the assets and liabilities
for one of the special purpose subsidiaries as reflected on our Consolidated Balance Sheets and is provided below as required
pursuant to certain applicable agreements. These amounts may differ materially from the assets and liabilities for these entities
that present individual financial statements on a stand-alone basis to their project lenders.
GEC, a wholly-owned subsidiary of GEC Holdings, LLC, has been established as an entity with its existence separate
from us and other subsidiaries of ours. On March 2, 2012, we closed on the purchase of two of the three third party interests in
GEC Holdings, LLC pursuant to the purchase agreements that were executed in December 2011. The following table sets forth
selected financial information of GEC at December 31, 2012 (in millions):
Assets ......................................................................................................................................................................... $
Liabilities.................................................................................................................................................................... $
2012
456
9
80
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, gas transportation and storage arrangements, electric transmission service and other contracts
for the sale and purchase of power products.
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 measurement 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 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 Statements of
Operations in unrealized mark-to-market gain/loss as a component of operating revenues (for power contracts and Heat Rate swaps
and options) and fuel and purchased energy expense (for natural gas 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.
In order to simplify our reporting, we elected to discontinue the application of hedge accounting treatment during the
first quarter of 2012 for all commodity derivatives, including the remaining commodity derivatives previously accounted for as
cash flow hedges. Accordingly, prospective changes in fair value from the date of this election are reflected in unrealized mark-
to-market activity on our Consolidated Statements of Operations and could create more volatility in our earnings. The fair value
of our commodity derivative instruments residing in AOCI during the previous application of hedge accounting was reclassified
to earnings during 2012 as the related economic transactions affected earnings or the forecasted transaction became probable of
not occurring.
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.
Historically, 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 2013 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 swaps to adjust the mix between our fixed and variable rate debt. To the extent
eligible, our interest rate swaps 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. The reclassification of unrealized losses from AOCI into earnings and the changes in fair value and
settlements subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility is
presented separately from interest expense as loss on interest rate derivatives on our Consolidated Statements of Operations. See
Note 8 of the Notes to Consolidated 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 swaps. 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 $0.4 billion at December 31, 2012, when compared to approximately $1.1
billion at December 31, 2011, and our derivative liabilities have decreased to approximately $0.6 billion at December 31, 2012,
when compared to approximately $1.4 billion at December 31, 2011. At December 31, 2012, the fair value of our level 3 derivative
assets and liabilities represent only a small portion of our total assets and liabilities measured at fair value (approximately 1%).
See Note 7 of the Notes to Consolidated Financial Statements for further information related to our level 3 derivative assets and
liabilities.
81
The change in fair value of our outstanding commodity and interest rate derivative instruments from January 1, 2012,
through December 31, 2012, is summarized in the table below (in millions):
Fair value of contracts outstanding at January 1, 2012................................... $
Items recognized or otherwise settled during the period(1)(2) ........................
Fair value attributable to new contracts........................................................
Changes in fair value attributable to price movements ................................
Changes in fair value attributable to nonperformance risk...........................
Fair value of contracts outstanding at December 31, 2012(3).......................... $
(310) $
174
—
(58)
(2)
(196) $
$
51
(72)
(15)
20
(1)
(17) $
(259)
102
(15)
(38)
(3)
(213)
Interest Rate
Swaps
Commodity
Instruments
Total
__________
(1)
Interest rate settlements consist of recognized losses of $146 million related to interest rate swaps that were terminated
during 2012, $15 million related to recognition of losses from settlements of designated cash flow hedges and $13 million
in losses from settlements of undesignated interest rate swaps (represents a portion of interest expense and loss on interest
rate derivatives as reported on our Consolidated Statements of Operations).
(2) Gains on settlement of commodity contracts not designated as hedging instruments of $144 million (represents a portion
of Commodity revenue and Commodity expense as reported on our Consolidated Statements of Operations) and $72 million
related to recognition of losses from other changes in derivative assets and liabilities not reflected in OCI or earnings,
partially offset by de-designated cash flow hedges, previously reflected in AOCI.
(3) Net commodity and interest rate derivative assets and liabilities reported in Notes 7 and 8 of the Notes to Consolidated
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 Statements
of Operations as a component (gain or loss) in earnings.
The following tables detail the components of our total mark-to-market activity for both the net realized gain (loss) and
the net unrealized gain (loss) recognized from our derivative instruments in earnings and where these components were recorded
on our Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and 2010 (in millions):
Realized gain (loss)(1)
Interest rate swaps.......................................................................................... $
Commodity derivative instruments................................................................
Total realized gain (loss)........................................................................... $
Unrealized gain (loss)(2)
Interest rate swaps.......................................................................................... $
Commodity derivative instruments................................................................
Total unrealized gain (loss)....................................................................... $
Total mark-to-market activity, net........................................................ $
___________
2012
2011
2010
(157) $
387
230
$
154
(82)
72
302
$
$
$
(193) $
143
(50) $
$
55
(25)
30
$
(20) $
(31)
114
83
(199)
143
(56)
27
(1) Does not include the realized value associated with derivative instruments that settle through physical delivery.
(2)
In addition to changes in market value on derivatives not designated as hedges, changes in unrealized gain (loss) also
includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into earnings, hedge
ineffectiveness and adjustments to reflect changes in credit default risk exposure.
82
Realized and unrealized gain (loss)
Derivatives contracts included in operating revenues...................................... $
Derivatives contracts included in fuel and purchased energy expense ............
Interest rate swaps included in interest expense...............................................
Loss on interest rate derivatives .......................................................................
Total mark-to-market activity, net............................................................... $
2012
2011
2010
187
118
11
(14)
302
$
$
(20) $
138
7
(145)
(20) $
(19)
276
(7)
(223)
27
Our change in AOCI from an accumulated loss of $178 million at December 31, 2011, to an accumulated loss of $248
million at December 31, 2012, was primarily driven by $56 million in losses on interest rate swaps due to a decrease in forward
LIBOR rates, $3 million in losses related to capitalized realized losses on construction swaps hedging our Los Esteros Project
Debt and Russell City Project Debt, $38 million in gains reclassified to earnings related to the settlement of de-designated
commodity derivative cash flow hedges, and $1 million in unrealized actuarial losses recorded in 2012, partially offset by $16
million in losses on settlement of interest rate cash flow hedges reclassified to earnings, and a foreign currency translation gain
of $3 million related to our Canadian subsidiaries and a $9 million income tax benefit recorded during the year ended December
31, 2012.
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 December 31, 2012, based on price source and
the period during which the instruments will mature, are summarized in the table below (in millions):
Fair Value Source
Prices actively quoted.................................................
Prices provided by other external sources..................
Prices based on models and other valuation methods
Total fair value.........................................................
$
$
2013
2014-2015
2016-2017
After 2017
Total
(30) $
42
10
22
$
(44) $
(1)
6
(39) $
— $
—
—
— $
— $
—
—
— $
(74)
41
16
(17)
We measure the energy commodity price risks 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 market movements in comparison to internally established
thresholds. Our VAR is calculated for our entire portfolio which is comprised of energy commodity derivatives, expected generation
and natural gas consumption from our power plants, PPAs, and other physical and financial transactions. The portfolio VAR
calculation incorporates positions for the remaining portion of the current calendar year, exclusive of the current month of
measurement, plus the following two calendar years. 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 years ended December 31, 2012 and 2011
(in millions):
Year ended December 31:
2012
2011
High.................................................................................................................................................. $
Low................................................................................................................................................... $
Average............................................................................................................................................. $
As of December 31 ............................................................................................................................. $
77
34
49
63
$
$
$
$
56
20
33
41
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 impact 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 tests, scenario tests, stress tests, and daily position reports.
83
During the fourth quarter of 2012, we began to experience diminished liquidity in the forward commodity markets
resulting from a decrease in participation of counterparties in the marketplace with which to transact our hedging activities.
Although this occurrence of diminished liquidity did not negatively impact our 2012 financial results, should it persist during 2013
and beyond, it could decrease our ability to hedge our forward commodity price risk and create more volatility in our earnings.
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 9 of the Notes to Consolidated 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 impact
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 commercial customers, primarily independent electric system
operators, relating to our sales of power, steam and hedging and optimization activities. We believe that our credit policies and
portfolio of transactions adequately monitor 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 and PPAs 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 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 December 31, 2012, 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 December 31, 2012)
Investment grade ........................................................
Non-investment grade ................................................
No external ratings .....................................................
Total fair value.........................................................
$
$
2013
2014-2015
2016-2017
After 2017
Total
21
—
1
22
$
$
(39) $
—
—
(39) $
— $
—
—
— $
— $
—
—
— $
(18)
—
1
(17)
Interest Rate Risk — We are exposed to interest rate risk related to our variable rate debt. Interest rate risk represents the
potential loss in earnings arising from adverse changes in market interest rates. Our variable rate financings are indexed to base
rates, generally LIBOR. The following table summarizes the contract terms as well as the fair values of our debt instruments
exposed to interest rate risk as of December 31, 2012. All outstanding balances and fair market values are shown gross of applicable
premium or discount, if any (in millions):
2013
2014
2015
2016
2017
Thereafter
Total
Fair Value
December 31,
2012
Debt by Maturity Date:
Fixed Rate........................ $
Average Interest Rate.......
Variable Rate ................... $
Average Interest Rate(1) ...
$
$
25
9.2%
47
3.6%
$
$
24
8.6%
130
3.1%
9
5.4%
$ 1,008
$ 1,087
$ 4,291
8.0%
7.2%
7.7%
110
$
114
$
483
$ 3,082
3.4%
3.8%
4.9%
6.4%
$
$
6,444
3,966
$
$
7,077
3,949
____________
84
(1)
Projection based upon anticipated LIBOR rates.
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 swaps are validated based upon
external quotes. Our interest rate swaps are with counterparties we believe are primarily high quality institutions, and we do not
believe that our interest rate swaps 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 swaps hedging our variable rate debt
of approximately $(9) million at December 31, 2012.
85
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 believe the following
are our more critical accounting policies due to the significance, subjectivity and judgment involved in determining our estimates
used in preparing our Consolidated Financial Statements. See Note 2 of the Notes to Consolidated Financial Statements for a
discussion of the application of these and other accounting policies. We evaluate our estimates and assumptions used in preparing
our Consolidated Financial Statements on an ongoing basis utilizing historic experience, anticipated future events or trends,
consultation with third party advisors or other methods that involve judgment as determined appropriate under the circumstances.
The resulting effects of changes in our estimates are recorded in our Consolidated Financial Statements in the period in which the
facts and circumstances that give rise to the change in estimate become known.
Revenue Recognition
We routinely enter into physical commodity contracts for sales of our generated power to manage risk and capture the
value inherent in our generation. Determining the proper accounting for our power contracts can require significant judgment and
impact how we recognize revenue. In addition, we determine whether the contract should be accounted for on a gross or net basis.
Determining the proper accounting treatment involves the evaluation of quantitative, as well as qualitative factors, to determine
if the contract should be accounted for as one of the following:
•
•
•
•
a contract that qualifies as a lease;
a derivative;
a contract that meets the definition of a derivative but is eligible for the normal purchase normal sale exemption; or
a contract that is a physical or executory contract.
Lease Accounting — Revenue from contracts accounted for as operating leases, such as certain tolling agreements, with
minimum lease rentals which vary over time must be levelized. Generally, we levelize these contract revenues on a straight-line
basis over the term of the contract.
Executory and Physical Contracts Exempt from Derivative Accounting — We generally recognize revenue from the sale
of power or host steam thermal energy for sale to our customers for use in industrial or other heating operations, upon transmission
and delivery to the customer at the contractual price. In addition to revenues from power, host steam revenues and RECs from our
Geysers Assets related to generation, our operating revenues also include:
•
•
•
power and steam revenue consisting of fixed and variable capacity payments, including capacity payments received
from PJM capacity auctions which are not related to generation;
other revenues such as RMR Contracts, resource adequacy and certain ancillary service revenues; and
other service revenues.
Capacity payments, RMR Contracts, RECs, resource adequacy and other ancillary revenues are recognized when
contractually earned and consist of revenues received from our customers either at the market price or a contract price.
See “ — Accounting for Derivative Instruments” directly below for a discussion of the significant judgments and estimates
related to accounting for derivative instruments. We apply lease accounting to contracts that meet the definition of a lease and
accrual accounting treatment to those contracts that are either exempt from derivative accounting or do not meet the definition of
a derivative instrument.
Gross vs. Net Accounting — We determine whether the financial statement presentation of revenues should be on a gross
or net basis. Where we act as principal, we record settlement of our physical commodity contracts on a gross or net basis dependent
upon whether the contract results in physical delivery of the underlying product. With respect to our physical executory contracts,
where we do not take title to the commodities but receive a variable payment to convert natural gas into power and steam in a
tolling operation, we record revenues on a net basis.
Fair Value Measurements
We use fair value to measure certain of our assets, liabilities and expenses in our financial statements. Fair value is the
amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants
at the measurement date (i.e., the exit price). Generally, the determination of fair value requires the use of significant judgment
and different approaches and models under varying circumstances. Under a market based approach, we consider prices of similar
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assets, consult with brokers and experts or employ other valuation techniques. Under an income based approach, we generally
estimate future cash flows and then discount them at a risk adjusted rate.
Accordingly, the determination of fair value represents a critical accounting policy. Our most significant fair value
measurements represent the valuation of our derivative assets and liabilities, which are measured on a recurring basis (each reporting
period) and measurements of impairments and acquired assets on a nonrecurring basis. We primarily apply the market approach
and income approach for recurring fair value measurements (primarily our derivative assets and liabilities) using the best available
information. We primarily utilize the income approach for nonrecurring fair value measurements such as impairments of our assets
as market prices for similar assets may not be readily available and may not incorporate the expected future returns from our assets.
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. U.S. GAAP establishes a fair value hierarchy which
classifies fair value measurements from level 1 through level 3 based upon the inputs used to measure fair value:
Level 1 — Quoted prices (unadjusted) are available in active markets for identical assets or liabilities as of the reporting
date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide
pricing information on an ongoing basis.
Level 2 — Pricing inputs include quoted prices for similar assets and liabilities in active markets, and inputs other than
quoted prices that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial
instrument.
Level 3 — Pricing inputs include significant inputs that are generally less observable or from unobservable sources. These
inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.
Derivative Instruments and Valuation Techniques
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. Derivative contracts can be exchange-traded or OTC. For
OTC derivatives that trade in liquid markets, model inputs can generally be verified and model selection does not involve significant
management judgment. Certain OTC derivatives trade in less liquid markets with limited pricing information, and the determination
of fair value for these derivatives is inherently more difficult.
For our level 2 and level 3 derivative instruments, we utilize models to measure fair value. Where models are used, the
selection of a particular model to value an asset or liability depends upon the contractual terms and specific risks, as well as the
availability of pricing information in the market. We generally use similar models to value similar instruments. Valuation models
require a variety of inputs, including contractual terms, market prices, yield curves, credit curves and measures of volatility. These
models are primarily industry-standard models, including the Black-Scholes option-pricing model. 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. In cases where there is no corroborating
market information available to support significant model inputs, we initially use the transaction price as the best estimate of fair
value.
Our derivative instruments that are traded on the NYMEX primarily consist of natural gas swaps, futures and options
and are classified as level 1 fair value measurements.
Our derivative instruments that primarily consist of interest rate swaps and OTC power and natural gas forwards for
which market-based pricing inputs are observable are classified as level 2 fair value measurements. Generally, we obtain our
level 2 pricing inputs from market sources such as the Intercontinental Exchange and Bloomberg.
Our OTC power and natural gas forwards and options where pricing inputs are unobservable, as well as other complex
and structured transactions are classified as level 3 fair value measurements. Complex or structured transactions are tailored to
our or 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. 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.
The determination of fair value of our derivatives also includes consideration of our credit standing, the credit standing
of our counterparties and the impact of credit enhancements, if any. We assess non-performance risk by adjusting the fair value
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of our derivatives based on our credit standing or the credit standing of our counterparties involved and the impact of credit
enhancements, if any. Such valuation adjustments represent the amount of probable loss due to default either by us or a third party.
Our credit valuation methodology is based on a quantitative approach which allocates a credit adjustment to the fair value of
derivative transactions based on the net exposure of each counterparty. We develop our credit reserve based on our expectation
of the market participants’ perspective of potential credit exposure. Our calculation of the credit reserve on net asset positions is
based on available market information including credit default swap rates, credit ratings and historical default information. We
also incorporate non-performance risk in net liability positions based on an assessment of our potential risk of default.
Impairments
When we determine an impairment exists, we determine fair value using valuation techniques such as the present value
of expected future cash flows. In order to estimate future cash flows, we consider historical cash flows, existing and future contracts
and PPAs and 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 other
earnings forecasts). 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 impact of such
variations could be material.
We 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 counterparts. 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; however, actual future market prices and project costs could vary from the assumptions used in our estimates, and
the impact of such variations could be material.
Acquisitions of Assets and Liabilities
U.S. GAAP requires that the purchase price for an acquisition, such as our Bosque Energy Center and Conectiv
Acquisitions, be assigned and allocated to the individual assets and liabilities based upon their fair value. Generally, the amount
recorded in the financial statements for an acquisition is the purchase price (value of the consideration paid), but a purchase price
that exceeds the fair value of the assets acquired will result in the recognition of goodwill. In addition to the potential for the
recognition of goodwill, differing fair values will impact the allocations of the purchase price to the individual assets and liabilities
and can impact the gross amount and classification of assets and liabilities recorded on our Consolidated Balance Sheet and can
impact the timing and the amount of depreciation expense recorded in any given period. We utilize our best effort to make our
determinations and review all information available including estimated future cash flows and prices of similar assets when making
our best estimate. We also may hire independent appraisers to help us make this determination as we deem appropriate under the
circumstances.
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
Statements of Operations until the period of delivery. In order to simplify our reporting, we elected to discontinue the application
of hedge accounting treatment during the first quarter of 2012 for all commodity derivatives, including the remaining commodity
derivatives previously accounted for as cash flow hedges. Accordingly, prospective changes in fair value from the date of this
election are reflected in unrealized mark-to-market gain/loss on our Consolidated Statements of Operations and could create more
volatility in our earnings. Revenues and fuel costs 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. Although we have discontinued
the application of hedge accounting treatment for our commodity derivative instruments, prior to this change and for our interest
rate swaps, 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 or investing activities (in the case of settlements for our interest rate swaps formerly hedging
our First Lien Credit Facility term loans) on our Consolidated Statements of Cash Flows unless they contain an other-than-
insignificant financing element in which case their cash flows are classified within financing activities.
Hedge Accounting — Revenues and expenses derived from derivative instruments that qualify for hedge accounting are
recorded in the period and same financial statement line item as the hedged item. Hedge accounting requires us to formally
document, designate and assess the effectiveness of transactions that receive hedge accounting. We present the cash flows from
hedging derivatives in the same category as the item being hedged within operating activities on our Consolidated Statements of
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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 report the effective portion of the unrealized gain or loss on a derivative instrument 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 commodity
hedging instruments are recognized currently in earnings and are separately stated on our Consolidated Statements of Operations
in unrealized mark-to-market gain/loss as a component of operating revenues (for power contracts and swaps) and fuel and
purchased energy expense (for natural gas contracts and swaps). Gains and losses due to ineffectiveness on interest rate hedging
instruments are recognized currently in earnings as a component of interest expense (for interest rate swaps except as discussed
below). 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 and interest rate 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 Statements of Operations in unrealized mark-to-market gain/loss as a component of
operating revenues (for power contracts and Heat Rate swaps and options) and fuel and purchased energy expense (for natural
gas 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 (for interest rate swaps except as discussed below).
Interest Rate Swaps Formerly Hedging our First Lien Credit Facility and Other Project Debt — During 2010, we repaid
approximately $3.5 billion of our First Lien Credit Facility term loans, which had approximately $3.3 billion notional amount of
interest rate swaps hedging the scheduled variable interest payments, and in January 2011, we repaid the remaining approximately
$1.2 billion of First Lien Credit Facility term loans which had approximately $1.0 billion notional amount of interest rate swaps
hedging the scheduled variable interest payments. With the repayment of the remaining First Lien Credit Facility term loans,
unrealized losses of approximately $91 million in AOCI related to the interest rate swaps formerly hedging the First Lien Credit
Facility, were reclassified out of AOCI and into earnings as an additional loss on interest rate derivatives during 2011. In addition,
we reclassified approximately $17 million in unrealized losses in AOCI to loss on interest rate derivatives during 2011 resulting
from the repayment of project debt in 2011. During 2010, we reclassified approximately $206 million out of AOCI and into earnings
as additional loss on interest rate derivatives related to interest rate swaps formerly hedging our First Lien Credit Facility term
loans. We have presented the reclassification of unrealized losses from AOCI into earnings and the changes in fair value and
settlements subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility described
above separate from interest expense as loss on interest rate derivatives on our Consolidated Statements of Operations. On March
26, 2012, we terminated the legacy interest rate swaps formerly hedging our First Lien Credit Facility and paid the fair value of
the swaps totaling approximately $156 million. Approximately $14 million of the settlement amount was recorded as a component
of loss on interest rate derivatives on our Consolidated Statement of Operations for the year ended December 31, 2012, and
approximately $142 million reflected the realization of losses recorded in prior periods.
See Notes 7 and 8 of the Notes to Consolidated Financial Statements for further discussion of our derivative instruments
and our interest rate swaps formerly hedging our First Lien Credit Facility term loans.
Accounting for VIEs and Financial Statement Consolidation Criteria
We consolidate all VIEs where we determined that we have both the power to direct the activities of a VIE that most
significantly impact the VIE's economic performance and the obligation to absorb losses or receive benefits from the VIE. We
have determined that we hold the obligation to absorb losses and receive benefits in all of our VIEs where we hold the majority
equity interest. Therefore, our determination of whether to consolidate is based upon which variable interest holder has the power
to direct the most significant activities of the VIE (the primary beneficiary). Our analysis includes consideration of the following
primary activities which we believe to have a significant impact on a power plant's financial performance: operations and
maintenance, plant dispatch, and fuel strategy as well as our ability to control or influence contracting and overall plant strategy.
Our approach to determining which entity holds the powers and rights is based on powers held as of the balance sheet date.
Contractual terms that may change the powers held in future periods, such as a purchase or sale option, are not considered in our
analysis. Based on our analysis, we believe that we hold the power and rights to direct the most significant activities of all our
majority owned VIEs.
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Under our consolidation policy and under U.S. GAAP we also:
•
•
perform an ongoing reassessment each reporting period of whether we are the primary beneficiary of our VIEs; and
evaluate if an entity is a VIE and whether we are the primary beneficiary whenever any changes in facts and
circumstances occur such that the holders of the equity investment at risk, as a group, lose the power from voting
rights or similar rights of those investments to direct the activities of a VIE that most significantly impact the VIE's
economic performance or when there are other changes in the powers held by individual variable interest holders.
Because we are required to perform ongoing reassessments of whether we are the primary beneficiary, future changes
in our assessments of whether we are the primary beneficiary could require us to consolidate our VIEs that are currently not
consolidated or deconsolidate our VIEs that are currently consolidated based upon our reassessments in future periods. Making
these determinations can require the use of significant judgment to determine which variable interest holder has the power to direct
the most significant activities of the VIE (the primary beneficiary) and can directly impact amounts reported on our Consolidated
Financial Statements.
Disclosure Requirements
U.S. GAAP requires separate disclosure on the face of our Consolidated Balance Sheets of the significant assets of a
consolidated VIE that can be used only to settle obligations of the consolidated VIE and the significant liabilities of a consolidated
VIE for which creditors (or beneficial interest holders) do not have recourse to the general credit of the primary beneficiary. In
determining which assets of our VIEs meet the separate disclosure criteria, we consider that this separate disclosure requirement
is met where Calpine Corporation is substantially limited or prohibited from access to assets (primarily cash and cash equivalents,
restricted cash and property, plant and equipment), and where our VIEs had project financing that prohibits the VIE from providing
guarantees on the debt of others. In determining which liabilities of our VIEs meet the separate disclosure criteria, we consider
that this separate disclosure requirement is met where there are agreements that prohibit the debt holders of the VIEs from recourse
to the general credit of Calpine Corporation and where the amounts were material to our financial statements.
Unconsolidated VIEs
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. We account
for these entities under the equity method of accounting and include our net equity interest in investments on our Consolidated
Balance Sheets. Our equity interest in the net income from Greenfield LP and Whitby for the years ended December 31, 2012,
2011 and 2010, are recorded in (income) from unconsolidated investments in power plants.
We hold a call option to purchase the Inland Empire Energy Center (a 775 MW natural gas-fired power plant located in
California which achieved COD on May 3, 2010) 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.
Long-Lived Assets and Depreciation Expense
Determination of the appropriate depreciation method, proper useful lives and salvage values involves significant
judgment, estimates, assumptions and historical experience. Changes in our estimates and methods can result in a significant
impact in the amounts and timing of when we recognize depreciation expense and therefore significantly impact our financial
condition and results of operations from period to period. Different depreciation methods can impact the timing and amount of
depreciation expense affecting our results of operations and could result in different net book values of assets at a particular time
during the useful life of the asset affecting our financial position. Estimates of useful lives also significantly impact the timing
and amounts of depreciation expense and include significant estimates. If useful lives are too short, then the asset is depreciated
too quickly and depreciation expense is overstated. Estimated useful lives can significantly decrease if routine maintenance or
certain upgrades are not performed, premature mechanical failure of the asset occurs, significant increases in the planned level of
usage occur, advances in technology make the asset obsolete, or if there are adverse changes in environmental regulations. Our
depreciable cost basis of our assets are reduced by their estimated salvage values. Estimates involved with salvage values include
future estimated costs of dismantlement and repair, market prices, environmental regulations and technological advancements.
Dependent upon our ability to accurately estimate salvage values and the timing of disposal, the salvage values actually realized
for our assets could significantly increase or decrease resulting in additional gains or losses in the year of disposal.
We depreciate our assets under the straight-line method over the shorter of their estimated useful lives or lease term. For
our natural gas-fired power plants, we assume an estimated salvage value which approximates 10% of the depreciable cost basis
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where we own the land or have a favorable option to purchase the land at conclusion of the lease term and approximately 0.15%
of the depreciable costs basis for rotable equipment. For our Geysers Assets, we typically assume no salvage values. We use the
component depreciation method for our natural gas-fired power plant rotable parts and our information technology equipment and
the composite depreciation method for most of all of the other natural gas-fired power plant asset groups and Geysers Assets.
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 PP&E and turbine 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. If we determine that the undiscounted cash flows from an asset to be held and
used are less than the carrying amount of the asset, or if we have classified an asset as held for sale, we must estimate fair value
to determine the amount of any impairment loss. 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 exist on specifically identifiable 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 above in “— 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 for further discussion of our impairment evaluation of
long-lived assets.
Accounting for Income Taxes
To arrive at our consolidated income tax provision and other tax balances, significant judgment and estimates are required.
Although we believe that our estimates are reasonable, no assurance can be given that the final tax outcome of these matters will
not be different than that which is reflected in our historical tax provisions and accruals. Such differences could have a material
impact on our income tax provision, other tax accounts and net income in the period in which such determination is made.
For federal income tax reporting purposes, our historical tax reporting group was comprised primarily of two separate
groups, CCFC and its subsidiaries, which we referred to as the CCFC group, and Calpine Corporation and its subsidiaries other
than CCFC, which we referred to as the Calpine group. During the first quarter of 2011, we elected to consolidate our CCFC and
Calpine groups for federal income tax reporting purposes and Calpine filed a consolidated federal income tax return for the year
ended December 31, 2011 that included the CCFC group. As a result of the consolidation, the CCFC group deferred tax liabilities
will be eligible to offset existing Calpine group NOLs that were reserved by a valuation allowance. Accordingly, we recorded a
one-time federal deferred income tax benefit of approximately $76 million during the first quarter of 2011 to reduce our valuation
allowance. For the year ended December 31, 2010, the CCFC group was deconsolidated from the Calpine group for federal income
tax reporting purposes. See Note 10 of the Notes to Consolidated Financial Statements for additional discussion of our Calpine
and CCFC groups.
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Our NOL carryforwards consist primarily of federal NOL carryforwards of approximately $7.3 billion, which expire
between 2023 and 2031, and NOL carryforwards in 33 states and the District of Columbia totaling approximately $4.0 billion,
which expire between 2013 and 2031, substantially all of which are offset with a full valuation allowance. We also have
approximately $1.0 billion in foreign NOLs, substantially all of which are offset with a full valuation allowance. The NOL
carryforwards available are subject to limitations on their annual usage. Under federal and applicable state income tax laws, a
corporation is generally permitted to deduct from taxable income in any year NOLs carried forward from prior years subject to
certain time limitations as prescribed by the taxing authorities. Under federal income tax law, our NOL carryforwards can be
utilized to reduce future taxable income subject to certain limitations, including if we were to undergo an ownership change as
defined by Section 382 of the IRC. We experienced an ownership change on the Effective Date as a result of the cancellation of
our old common stock and the distribution of our new common stock pursuant to our Plan of Reorganization. However, this
ownership change and the resulting annual limitations are not expected to result in the expiration of our NOL carryforwards if we
are able to generate sufficient future taxable income within the carryforward periods. At December 31, 2012, approximately $2.4
billion of our $7.3 billion federal NOLs are not subject to annual Section 382 limitations. When considering our cumulative annual
Section 382 limitations, in addition to our post-Effective Date NOLs that are not limited, our total unrestricted NOLs are
approximately $7.1 billion. If a subsequent ownership change were to occur as a result of future transactions in our common stock,
accompanied by a significant reduction in our market value immediately prior to the ownership change, our ability to utilize the
NOL carryforwards may be significantly limited.
Deferred tax assets relating to tax benefits of employee stock-based compensation do not reflect stock options exercised
and restricted stock that vested in 2012. Some stock option exercises and restricted stock vestings result in tax deductions in excess
of previously recorded deferred tax benefits based on the equity award value at the grant date. Although these additional tax
benefits or “windfalls” are reflected in net operating tax carryforwards pursuant to accounting for stock-based compensation under
U.S. GAAP, the additional tax benefit associated with the windfall is not recognized until the deduction reduces taxes payable,
which will not occur for Calpine until a future period. Accordingly, since the tax benefit does not reduce our current taxes payable
in 2012 due to NOL carryforwards, these “windfall” tax benefits are not reflected in our NOL in deferred tax assets for 2012.
Windfalls included in NOL carryforwards, but not reflected in deferred tax assets as of December 31, 2012 were $10 million.
Under state income tax laws, our NOL carryforwards can be utilized to reduce future taxable income subject to certain
limitations, including if we were to undergo an ownership change as defined by Section 382 of the IRC. During 2011, we analyzed
the effect of our change in ownership on the Effective Date for each of our significant states to determine the amount of our NOL
limitation. The analysis determined that $640 million of our state NOLs are expected to expire unutilized as a result of statutory
limitations on the use of some of our pre-emergence date NOLs as of the Effective Date or the cessation of business operations
in various tax jurisdictions. We reduced our deferred tax asset for state NOLs that we are unable to utilize and made an equal
reduction in our valuation allowance in 2011. The result did not have an impact on our income tax expense in 2011. We estimate
that approximately $117 million of our state NOLs expired unutilized during 2012 as a result of statutory state limitations relating
to the time period NOLs can be carried forward, and accordingly, we reduced our deferred tax asset and made an equal reduction
in our valuation allowance. The reduction did not have an impact to our income tax expense in 2012. We will likely make future
annual adjustments to our state NOLs that have expired or are limited under Section 382 of the IRC.
In the ordinary course of business, there are many transactions and calculations where the ultimate tax outcome is
uncertain. Some of these uncertainties arise as a consequence of the treatment of capital assets, financing transactions, multistate
taxation of operations and segregation of foreign and domestic income and expense to avoid double taxation. We recognize the
financial statement effects of a tax position when it is more likely than not, based on the technical merits, that the position will be
sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest
amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. We reverse
a previously recognized tax position in the first period in which it is no longer more likely than not that the tax position would be
sustained upon examination. The determination and calculation of uncertain tax positions involves significant judgment in the
application of complex tax laws. Resolution of these uncertainties in a manner inconsistent with our expectations could have a
material impact on our financial condition or results of operations. As of December 31, 2012, we had $92 million of unrecognized
tax benefits from uncertain tax positions.
See Note 10 of the Notes to Consolidated Financial Statements for further discussion of our accounting for income taxes.
New Accounting Standards and Disclosure Requirements
See Note 2 of the Notes to Consolidated Financial Statements for a discussion of new accounting standards and disclosure
requirements.
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Item 7A. Quantitative and Qualitative Disclosures about Market Risk
The information required hereunder is set forth under Item 7. “Management’s Discussion and Analysis of Financial
Condition and Results of Operations — Risk Management and Commodity Accounting.”
Item 8. Financial Statements and Supplementary Data
The information required hereunder is set forth under “Report of Independent Registered Public Accounting Firm,”
“Consolidated Statements of Operations,” “Consolidated Statements of Comprehensive Income (Loss),” “Consolidated Balance
Sheets,” “Consolidated Statements of Stockholders’ Equity,” “Consolidated Statements of Cash Flows,” and “Notes to Consolidated
Financial Statements” included in the Consolidated Financial Statements that are a part of this Report. Other financial information
and schedules are included in the Consolidated Financial Statements that are a part of this Report.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in
our Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules
and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer
and Chief Financial Officer, as appropriate, to allow timely decisions regarding required financial disclosure.
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) or 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.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as
defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act). Our internal control over financial reporting is a process
designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements
for external purposes in accordance with U.S. GAAP.
Our internal control over financial reporting includes those policies and procedures that:
•
•
•
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of our assets;
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements
in accordance with U.S. GAAP, and that our receipts and expenditures are being made only in accordance with
authorizations of our management and directors; and
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition
of our assets that could have a material effect on our financial statements.
Management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2012. In
making its assessment of internal control over financial reporting, management used the criteria described in Internal
Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
Based on management’s assessment, management has concluded that our internal control over financial reporting was
effective as of December 31, 2012 to provide reasonable assurance regarding the reliability of financial reporting and the preparation
of consolidated financial statements for external reporting purposes in accordance with U.S. GAAP.
93
The effectiveness of our internal control over financial reporting as of December 31, 2012, has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
Changes in Internal Control Over Financial Reporting
During the fourth quarter of 2012, 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.
Item 9B. Other Information
None.
94
Item 10. Directors, Executive Officers and Corporate Governance
Identification of Executive Officers
PART III
Set forth in the table below is a list of our executive officers, together with certain biographical information, including
their ages as of the date of this Report:
Name
Jack A. Fusco .........
John B. Hill ............
Zamir Rauf .............
W. Thaddeus Miller
Jim D. Deidiker......
Age
Principal Occupation
50 Chief Executive Officer
45 President and Chief Operating Officer
53 Executive Vice President and Chief Financial Officer
62 Executive Vice President, Chief Legal Officer and Secretary
57 Senior Vice President and Chief Accounting Officer
Jack A. Fusco has served as our Chief Executive Officer and a member of our Board of Directors since August 10, 2008.
He previously served as our President from August 2008 to December 2012. From July 2004 to February 2006, Mr. Fusco served
as the Chairman and Chief Executive Officer of Texas Genco LLC. From 2002 through July 2004, Mr. Fusco was an exclusive
energy investment advisor for Texas Pacific Group. From November 1998 until February 2002, he served as President and Chief
Executive Officer of Orion Power Holdings, Inc. Prior to his founding of Orion Power Holdings, Inc., Mr. Fusco was a Vice
President at Goldman Sachs Power, an affiliate of Goldman, Sachs & Co. Prior to joining Goldman Sachs, Mr. Fusco was employed
by Pacific Gas and Electric Company or its affiliates in various engineering and management roles for approximately 13 years.
Mr. Fusco obtained a Bachelor of Science degree in Mechanical Engineering from California State University, Sacramento.
Mr. Fusco served as a director of Foster Wheeler Ltd., a global engineering and construction contractor and power equipment
supplier, until February 2009 and Graphics Packaging Holdings, a paper and packaging company, until 2008.
John B. (Thad) Hill has served as our President and Chief Operating Officer since December 21, 2012. He previously
served as our Executive Vice President and Chief Operating Officer from November 2010 to December 2012 and as our Executive
Vice President and Chief Commercial Officer from September 2008 to November 2010. Prior to joining the Company, Mr. Hill
most recently served as Executive Vice President of NRG Energy, Inc. since February 2006 and President of NRG Texas LLC
since December 2006. Prior to joining NRG Energy, Inc., Mr. Hill was Executive Vice President of Strategy and Business
Development at Texas Genco LLC from 2005 to 2006. From 1995 to 2005, Mr. Hill was with Boston Consulting Group, Inc.,
where he rose to Partner and Managing Director and led the North American energy practice, serving companies in the power and
gas sector with a focus on commercial and strategic issues. Mr. Hill received his Bachelor of Arts degree from Vanderbilt University
and a Master of Business Administration degree from the Amos Tuck School of Dartmouth College.
Zamir Rauf has served as our Executive Vice President and Chief Financial Officer since December 17, 2008, after
serving as Interim Chief Financial Officer from June 4, 2008. Previously, he served as our Senior Vice President, Finance and
Treasurer from September 2007 until his appointment as Interim Chief Financial Officer. Since joining the Company in February
2000, Mr. Rauf has served as Manager, Finance from February 2000 to April 2001, Director, Finance from April 2001 to December
2002, Vice President, Finance from December 2002 to July 2005 and Senior Vice President, Finance from July 2005 to September
2007. Prior to joining the Company, Mr. Rauf held various accounting and finance roles with Enron North America and Dynegy
Inc., as well as credit and lending roles with Comerica Bank. Mr. Rauf earned his Bachelor of Arts degree in Business and Commerce
and Masters in Business Administration – Finance degree from the University of Houston.
W. Thaddeus Miller has served as our Executive Vice President, Chief Legal Officer and Secretary since August 12, 2008.
Prior to joining the Company, Mr. Miller most recently served as Executive Vice President and Chief Legal Officer of Texas Genco
LLC from December 14, 2004 until 2006. From 2002 to 2004, Mr. Miller was a consultant to Texas Pacific Group, a private equity
firm. From 1999 to 2002, he served as Executive Vice President and Chief Legal Officer of Orion Power Holdings, Inc., an
independent power producer. From 1994 to 1999, Mr. Miller was a Vice President of Goldman Sachs & Co., where he focused
on wholesale electric and other energy commodity trading. Before joining Goldman Sachs & Co., Mr. Miller was a partner in a
New York law firm. Mr. Miller earned his Bachelor of Science degree from the U.S. Merchant Marine Academy and his Juris
Doctor degree from St. John’s School of Law. In addition, Mr. Miller was an officer in the U.S. Coast Guard from 1973 through
1976.
Jim D. Deidiker has served as our Senior Vice President and Chief Accounting Officer since November 15, 2010.
Mr. Deidiker served as the Company’s Senior Vice President and Chief Accounting Officer since joining the Company in January
95
2008 until May 2010, when he resigned as the Company’s Chief Accounting Officer due to health concerns, but remained an
employee. Mr. Deidiker returned to his role as the Company’s Senior Vice President and Chief Accounting Officer once his health
concerns were resolved. Prior to joining the Company, Mr. Deidiker most recently served as Vice President and Controller of
Texas Genco LLC from 2005 to 2006 where he was responsible for financial and public reporting as well as management of the
accounting function. From 1998 to 2005, Mr. Deidiker served as Managing Director & Vice President, Administration of AEP
Energy Services, Inc. where he was responsible for management of the accounting function, financial reporting, contract
administration and risk management for the gas pipeline and trading segment of AEP Energy Services, Inc. Mr. Deidiker obtained
a Bachelor of Science degree in Accounting from Missouri State University and a Master in Business Administration degree from
the University of Houston. In addition, Mr. Deidiker is a Certified Public Accountant and Certified Management Accountant.
The remaining information required by this Item under the captions “Board Meeting and Board Committee Information,”
“Corporate Governance Matters” and “Proposal 1 — Election of Directors” is incorporated herein by reference to our proxy
statement for the 2013 annual meeting of stockholders to be held on May 10, 2013.
Item 11. Executive Compensation
Information required by this Item is incorporated herein by reference to our proxy statement for the 2013 annual meeting
of stockholders to be held May 10, 2013.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information required by this Item is incorporated herein by reference to our proxy statement for the 2013 annual meeting
of stockholders to be held May 10, 2013.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Information required by this Item is incorporated herein by reference to our proxy statement for the 2013 annual meeting
of stockholders to be held May 10, 2013.
Item 14. Principal Accounting Fees and Services
Information required by this Item is incorporated herein by reference to our proxy statement for the 2013 annual meeting
of stockholders to be held May 10, 2013.
96
Item 15. Exhibits, Financial Statement Schedule
PART IV
(a)-1. Financial Statements and Other Information
Calpine Corporation and Subsidiaries
Report of Independent Registered Public Accounting Firm .........................................................................................
Consolidated Statements of Operations for the Years Ended December 31, 2012, 2011 and 2010..............................
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2012, 2011 and
2010...............................................................................................................................................................................
Consolidated Balance Sheets at December 31, 2012 and 2011 ....................................................................................
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2012, 2011 and 2010..............
Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010 ............................
Notes to Consolidated Financial Statements for the Years Ended December 31, 2012, 2011 and 2010 ......................
Page
108
109
111
112
113
114
116
(a)-2. Financial Statement Schedule
Calpine Corporation and Subsidiaries
Schedule II — Valuation and Qualifying Accounts ......................................................................................................
157
(b) Exhibits
97
Exhibit
Number
2.1
Description
Debtors’ Sixth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the United States Bankruptcy
Code (incorporated by reference to Exhibit 2.1 to Calpine’s Current Report on Form 8-K filed with the SEC on
December 27, 2007).
2.2
2.3
2.4
3.1
3.2
4.1
4.2
4.3
4.4
4.5
4.6
Findings of Fact, Conclusions of Law, and Order Confirming Sixth Amended Joint Plan of Reorganization Pursuant
to Chapter 11 of the Bankruptcy Code (incorporated by reference to Exhibit 2.2 to Calpine’s Current Report on
Form 8-K filed with the SEC on December 27, 2007).
Purchase and Sale Agreement by and between Riverside Energy Center, LLC and Calpine Development Holdings,
Inc., as Sellers and Public Service Company of Colorado, as Purchaser dated as of April 2, 2010 (incorporated by
reference to Exhibit 10.1 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, filed
with the SEC on July 29, 2010).**,††
Purchase Agreement by and among Pepco Holdings, Inc., Conectiv, LLC, Conectiv Energy Holding Company,
LLC and New Development Holdings, LLC dated as of April 20, 2010 (incorporated by reference to Exhibit 10.1
to Calpine’s Current Report on Form 8-K, filed with the SEC on July 8, 2010).**
Amended and Restated Certificate of Incorporation of the Company, as amended (incorporated by reference to
Exhibit 3.1 to Calpine’s Current Report on Form 8-K filed with the SEC on February 1, 2008).
Amended and Restated By-Laws of the Company (as amended through May 7, 2009) (incorporated by reference
to Exhibit 3.2 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, filed with the SEC
on July 31, 2009).
Indenture, dated as of September 30, 2003, among Gilroy Energy Center, LLC, each of Creed Energy Center, LLC
and Goose Haven Energy Center, as guarantors, and Wilmington Trust Company, as trustee and collateral agent,
including form of 4.00% senior secured notes due 2011 (incorporated by reference to Exhibit 4.6 to Calpine’s
Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, filed with the SEC on November 13,
2003).
Indenture, dated May 19, 2009, among Calpine Construction Finance Company, L.P. and CCFC Finance Corp.,
the guarantors named therein, and Wilmington Trust Company, as trustee, including form of 8.00% senior secured
notes due 2016 (incorporated by reference to Exhibit 4.1 to Calpine’s Current Report on Form 8-K filed with the
SEC on May 22, 2009).
Indenture, dated October 21, 2009, between the Company and Wilmington Trust Company, as trustee, including
form of 7.25% senior secured notes due 2017 (incorporated by reference to Exhibit 4.1 to Calpine’s Current Report
on Form 8-K filed with the SEC on October 26, 2009).
Amended and Restated Indenture, dated May 25, 2010, among Calpine Corporation, the guarantors party thereto
and Wilmington Trust Company, as trustee, including the form of the 8% Senior Secured Notes due 2019
(incorporated by reference to Exhibit 4.1 to Calpine’s Current Report on Form 8-K filed with the SEC on May 25,
2010).
Indenture, dated July 23, 2010, among Calpine Corporation, the guarantors party thereto and Wilmington Trust
Company, as trustee, including the form of the 7.875% Senior Secured Notes due 2020 (incorporated by reference
to Exhibit 4.1 to Calpine’s Current Report on Form 8-K filed with the SEC on July 23, 2010).
Indenture, dated October 22, 2010, among Calpine Corporation, the guarantors party thereto and Wilmington Trust
Company, as trustee, including the form of the 7.50% Senior Secured Notes due 2021 (incorporated by reference
to Exhibit 4.1 to Calpine’s Current Report on Form 8-K filed with the SEC on October 22, 2010).
98
Exhibit
Number
4.7
Description
Indenture, dated January 14, 2011, among Calpine Corporation, the guarantors party thereto and Wilmington Trust
Company, as trustee, including the form of the 7.875% Senior Secured Notes due 2023 (incorporated by reference
to Exhibit 4.1 to Calpine’s Current Report on Form 8-K filed with the SEC on January 14 , 2011).
4.8
4.9
4.10
4.11
4.12
4.13
4.14
Registration Rights Agreement, dated January 31, 2008, among the Company and each Participating Shareholder
named therein (incorporated by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K filed with the
SEC on February 6, 2008).
First Supplemental Indenture dated as of April 26, 2011, among each of New Development Holdings, LLC, Calpine
Mid-Atlantic Energy, LLC, Calpine Mid-Atlantic Operating, LLC, Calpine Bethlehem, LLC, Calpine New Jersey
Generation, LLC, Calpine Mid-Atlantic Generation, LLC, Calpine Solar, LLC, Calpine Vineland Solar, LLC and
Calpine Mid-Atlantic Marketing, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of
October 21, 2009, providing for the issuance of 7.25% Senior Secured Notes due 2017 (incorporated by reference
to Exhibit 4.2 to Calpine's Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, filed with the
SEC on April 28, 2011).
First Supplemental Indenture dated as of April 26, 2011, among each of New Development Holdings, LLC, Calpine
Mid-Atlantic Energy, LLC, Calpine Mid-Atlantic Operating, LLC, Calpine Bethlehem, LLC, Calpine New Jersey
Generation, LLC, Calpine Mid-Atlantic Generation, LLC, Calpine Solar, LLC, Calpine Vineland Solar, LLC and
Calpine Mid-Atlantic Marketing, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of
May 25, 2010, providing for the issuance of 8.0% Senior Secured Notes due 2019 (incorporated by reference to
Exhibit 4.3 to Calpine's Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, filed with the SEC
on April 28, 2011).
First Supplemental Indenture dated as of April 26, 2011, among each of New Development Holdings, LLC, Calpine
Mid-Atlantic Energy, LLC, Calpine Mid-Atlantic Operating, LLC, Calpine Bethlehem, LLC, Calpine New Jersey
Generation, LLC, Calpine Mid-Atlantic Generation, LLC, Calpine Solar, LLC, Calpine Vineland Solar, LLC and
Calpine Mid-Atlantic Marketing, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of
July 23, 2010, providing for the issuance of 7.875% Senior Secured Notes due 2020 (incorporated by reference to
Exhibit 4.4 to Calpine's Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, filed with the SEC
on April 28, 2011).
First Supplemental Indenture dated as of April 26, 2011, among each of New Development Holdings, LLC, Calpine
Mid-Atlantic Energy, LLC, Calpine Mid-Atlantic Operating, LLC, Calpine Bethlehem, LLC, Calpine New Jersey
Generation, LLC, Calpine Mid-Atlantic Generation, LLC, Calpine Solar, LLC, Calpine Vineland Solar, LLC and
Calpine Mid-Atlantic Marketing, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of
October 22, 2010, providing for the issuance of 7.50% Senior Secured Notes due 2021 (incorporated by reference
to Exhibit 4.5 to Calpine's Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, filed with the
SEC on April 28, 2011).
First Supplemental Indenture dated as of April 26, 2011, among each of New Development Holdings, LLC, Calpine
Mid-Atlantic Energy, LLC, Calpine Mid-Atlantic Operating, LLC, Calpine Bethlehem, LLC, Calpine New Jersey
Generation, LLC, Calpine Mid-Atlantic Generation, LLC, Calpine Solar, LLC, Calpine Vineland Solar, LLC and
Calpine Mid-Atlantic Marketing, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of
January 14, 2011, providing for the issuance of 7.875% Senior Secured Notes due 2023 (incorporated by reference
to Exhibit 4.6 to Calpine's Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, filed with the
SEC on April 28, 2011).
Second Supplemental Indenture dated as of July 22, 2011, among each of Deer Park Energy Center LLC, Deer
Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as
trustee under the indenture, dated as of October 21, 2009, providing for the issuance of 7.25% Senior Secured Notes
due 2017 (incorporated by reference to Exhibit 4.1 to Calpine's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2011, filed with the SEC on July 28, 2011).
99
Exhibit
Number
4.15
Description
Second Supplemental Indenture dated as of July 22, 2011, among each of Deer Park Energy Center LLC, Deer
Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as
trustee under the indenture, dated as of May 25, 2010, providing for the issuance of 8.0% Senior Secured Notes
due 2019 (incorporated by reference to Exhibit 4.2 to Calpine's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2011, filed with the SEC on July 28, 2011).
4.16
4.17
4.18
4.19
4.20
4.21
4.22
4.23
Second Supplemental Indenture dated as of July 22, 2011, among each of Deer Park Energy Center LLC, Deer
Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as
trustee under the indenture, dated as of July 23, 2010, providing for the issuance of 7.875% Senior Secured Notes
due 2020 (incorporated by reference to Exhibit 4.3 to Calpine's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2011, filed with the SEC on July 28, 2011).
Second Supplemental Indenture dated as of July 22, 2011, among each of Deer Park Energy Center LLC, Deer
Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as
trustee under the indenture, dated as of October 22, 2010, providing for the issuance of 7.50% Senior Secured Notes
due 2021 (incorporated by reference to Exhibit 4.4 to Calpine's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2011, filed with the SEC on July 28, 2011).
Second Supplemental Indenture dated as of July 22, 2011, among each of Deer Park Energy Center LLC, Deer
Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as
trustee under the indenture, dated as of January 14, 2011, providing for the issuance of 7.875% Senior Secured
Notes due 2023 (incorporated by reference to Exhibit 4.5 to Calpine's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2011, filed with the SEC on July 28, 2011).
Third Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and
Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of
October 21, 2009, providing for the issuance of 7.25% Senior Secured Notes due 2017 (incorporated by reference
to Exhibit 4.1 to Calpine's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, filed with
the SEC on November 5, 2012).
Third Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and
Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of
May 25, 2010, providing for the issuance of 8.0% Senior Secured Notes due 2019 (incorporated by reference to
Exhibit 4.2 to Calpine's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, filed with the
SEC on November 5, 2012).
Third Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and
Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of
July 23, 2010, providing for the issuance of 7.875% Senior Secured Notes due 2020 (incorporated by reference to
Exhibit 4.3 to Calpine's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, filed with the
SEC on November 5, 2012).
Third Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and
Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of
October 22, 2010, providing for the issuance of 7.50% Senior Secured Notes due 2021 (incorporated by reference
to Exhibit 4.4 to Calpine's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, filed with
the SEC on November 5, 2012).
Third Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and
Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of
January 14, 2011, providing for the issuance of 7.875% Senior Secured Notes due 2023 (incorporated by reference
to Exhibit 4.5 to Calpine's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, filed with
the SEC on November 5, 2012).
100
Exhibit
Number
4.24
4.25
4.26
4.27
4.28
Description
Fourth Supplemental Indenture dated as of November 26, 2012, among each of South Point Holdings, LLC, South
Point Energy Center, LLC, Broad River Energy LLC, South Point OL-1, LLC, South Point OL-2, LLC, South Point
OL-3, LLC, South Point OL-4, LLC, Broad River OL-1, LLC, Broad River OL-2, LLC, Broad River OL-3, LLC
and Broad River OL-4, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 21,
2009, providing for the issuance of 7.25% Senior Secured Notes due 2017. *
Fourth Supplemental Indenture dated as of November 26, 2012, among each of South Point Holdings, LLC, South
Point Energy Center, LLC, Broad River Energy LLC, South Point OL-1, LLC, South Point OL-2, LLC, South Point
OL-3, LLC, South Point OL-4, LLC, Broad River OL-1, LLC, Broad River OL-2, LLC, Broad River OL-3, LLC
and Broad River OL-4, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of May 25,
2010, providing for the issuance of 8.0% Senior Secured Notes due 2019. *
Fourth Supplemental Indenture dated as of November 26, 2012, among each of South Point Holdings, LLC, South
Point Energy Center, LLC, Broad River Energy LLC, South Point OL-1, LLC, South Point OL-2, LLC, South Point
OL-3, LLC, South Point OL-4, LLC, Broad River OL-1, LLC, Broad River OL-2, LLC, Broad River OL-3, LLC
and Broad River OL-4, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of July 23,
2010, providing for the issuance of 7.875% Senior Secured Notes due 2020. *
Fourth Supplemental Indenture dated as of November 26, 2012, among each of South Point Holdings, LLC, South
Point Energy Center, LLC, Broad River Energy LLC, South Point OL-1, LLC, South Point OL-2, LLC, South Point
OL-3, LLC, South Point OL-4, LLC, Broad River OL-1, LLC, Broad River OL-2, LLC, Broad River OL-3, LLC
and Broad River OL-4, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 22,
2010, providing for the issuance of 7.50% Senior Secured Notes due 2021. *
Fourth Supplemental Indenture dated as of November 26, 2012, among each of South Point Holdings, LLC, South
Point Energy Center, LLC, Broad River Energy LLC, South Point OL-1, LLC, South Point OL-2, LLC, South Point
OL-3, LLC, South Point OL-4, LLC, Broad River OL-1, LLC, Broad River OL-2, LLC, Broad River OL-3, LLC
and Broad River OL-4, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of January 14,
2011, providing for the issuance of 7.875% Senior Secured Notes due 2023. *
10.1
Financing Agreements.
10.1.1.5
Credit Agreement, dated as of December 10, 2010, among Calpine Corporation, Goldman Sachs Bank USA, as
administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, the lenders party thereto and other
parties thereto (incorporated by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K filed with the
SEC on December 13, 2010).
10.1.1.6
Credit Agreement, dated March 9, 2011 among Calpine Corporation as borrower and the lenders party hereto, and
Morgan Stanley Senior Funding, Inc., as administrative agent, Goldman Sachs Credit Partners L.P., as collateral
agent, Citibank, N.A., Credit Suisse Securities (USA) LLC and Deutsche Bank Securities Inc., as co-documentation
agents and Goldman Sachs Bank USA as syndication agent (incorporated by reference to Exhibit 10.1 to Calpine's
Current Report on Form 8-K filed with the Securities and Exchange Commission on March 9, 2011).
10.1.1.7 Amended and Restated Guarantee and Collateral Agreement, dated as of December 10, 2010, made by the
Company and certain of the Company's subsidiaries party thereto in favor of Goldman Sachs Credit Partners, L.P.,
as collateral agent (incorporated by reference to Exhibit 10.1 to Calpine's Quarterly Report on Form 10-Q for the
quarter ended June 30, 2011, filed with the SEC on July 28, 2011).
10.1.1.8
Credit Agreement, dated October 9, 2012 among Calpine Corporation as borrower and the lenders party hereto, and
Morgan Stanley Senior Funding, Inc., as administrative agent, Goldman Sachs Credit Partners L.P., as collateral
agent, Barclays Bank PLC, Deutsche Bank Securities Inc., and RBC Capital Markets, as co-documentation agents
(incorporated by reference to Exhibit 10.1 to Calpine's Current Report on Form 8-K filed with the SEC on October
9, 2012).
10.2
Management Contracts or Compensatory Plans, Contracts or Arrangements.
101
Exhibit
Number
10.2.1.1
Description
Employment Agreement, dated August 10, 2008, between the Company and Jack A. Fusco (incorporated by
reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K filed with the SEC on August 12, 2008).†
10.2.1.2
Calpine Corporation Executive Sign On Non-Qualified Stock Option Agreement (Jack A. Fusco) (incorporated by
reference to Exhibit 10.2 to Calpine’s Current Report on Form 8-K filed with the SEC on August 12, 2008).†
10.2.1.3 Non-Qualified Stock Option Agreement between the Company and Jack Fusco, dated August 11, 2010 (incorporated
by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K filed with the SEC on August 17, 2010).†
10.2.1.4 Amendment to the Executive Employment Agreement between the Company and Jack A. Fusco, dated December
21, 2012 (incorporated by reference to Exhibit 10.1 to Calpine's Current Report on Form 8-K filed with the SEC
on December 26, 2012).†
10.2.1.5
Restricted Stock Award Agreement between the Company and Jack A. Fusco, dated December 21, 2012 (incorporated
by reference to Exhibit 10.2 to Calpine's Current Report on Form 8-K filed with the SEC on December 26, 2012).†
10.2.2
Letter Agreement, dated December 17, 2008, between the Company and Zamir Rauf (incorporated by reference to
Exhibit 10.1 to Calpine’s Current Report on Form 8-K filed with the SEC on December 19, 2008).†
10.2.3.1
Letter Agreement, dated September 1, 2008, between the Company and John B. Hill (incorporated by reference to
Exhibit 10.1 to Calpine’s Current Report on Form 8-K filed with the SEC on September 4, 2008).†
10.2.3.2
Calpine Corporation Executive Sign On Non-Qualified Stock Option Agreement (John B. Hill) (incorporated by
reference to Exhibit 10.2 to Calpine’s Current Report on Form 8-K filed with the SEC on September 4, 2008).†
10.2.3.3 Non-Qualified Stock Option Agreement between the Company and John B. (Thad) Hill, dated August 11, 2010
(incorporated by reference to Exhibit 10.2 to Calpine’s Current Report on Form 8-K filed with the SEC on August
17, 2010).†
10.2.3.4 Non-Qualified Stock Option Agreement between the Company and John B. (Thad) Hill, dated November 3, 2010
(incorporated by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K filed with the SEC on November
5, 2010).†
10.2.3.5 Amendment to the Letter Agreement between the Company and John B. (Thad) Hill, dated December 21, 2012
(incorporated by reference to Exhibit 10.3 to Calpine's Current Report on Form 8-K filed with the SEC on December
26, 2012).†
10.2.3.6
Restricted Stock Award Agreement between the Company and John B. (Thad) Hill, dated December 21, 2012
(incorporated by reference to Exhibit 10.4 to Calpine's Current Report on Form 8-K filed with the SEC on December
26, 2012).†
10.2.4.1
Employment Agreement, dated August 11, 2008, between the Company and W. Thaddeus Miller (incorporated by
reference to Exhibit 10.2.7 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008,
filed with the SEC on November 7, 2008).†
10.2.4.2
Calpine Corporation Executive Sign On Non-Qualified Stock Option Agreement (Thaddeus Miller) (incorporated
by reference to Exhibit 4.4 to Calpine’s Registration Statement on Form S-8 (Registration No. 333-153860) filed
with the SEC on October 6, 2008).†
102
Exhibit
Number
10.2.4.3 Non-Qualified Stock Option Agreement between the Company and W. Thaddeus Miller, dated August 11, 2010
(incorporated by reference to Exhibit 10.3 to Calpine’s Current Report on Form 8-K filed with the SEC on August
17, 2010).†
Description
10.2.4.4 Amendment to the Executive Employment Agreement between the Company and W. Thaddeus Miller, dated
December 21, 2012 (incorporated by reference to Exhibit 10.5 to Calpine's Current Report on Form 8-K filed with
the SEC on December 26, 2012).†
10.2.4.5
Restricted Stock Award Agreement between the Company and W. Thaddeus Miller, dated December 21, 2012
(incorporated by reference to Exhibit 10.6 to Calpine's Current Report on Form 8-K filed with the SEC on December
26, 2012).†
10.2.5
Calpine Corporation U.S. Severance Program (incorporated by reference to Exhibit 10.2.5 to Calpine's Annual
Report on Form 10-K for the year ended December 31, 2009 filed with the SEC on February 25, 2010).†
10.2.6
Calpine Corporation 2010 Calpine Incentive Plan (incorporated by reference to Exhibit 10.6 to Calpine’s Quarterly
Report on Form 10-Q for the quarter ended June 30, 2010, filed with the SEC on July 29, 2010).†
10.2.7
Calpine Corporation 2009 Calpine Incentive Plan (incorporated by reference to Exhibit 10.2 to Calpine’s Quarterly
Report on Form 10-Q for the quarter ended March 31, 2009, filed with the SEC on May 8, 2009).†
10.2.7.1
The Amended and Restated Calpine Corporation 2008 Equity Incentive Plan (incorporated by reference to Exhibit
10.2 to Calpine’s Current Report on Form 8-K filed with the SEC on November 5, 2010).†
10.2.7.2
Form of Non-Qualified Stock Option Agreement (Pursuant to the 2008 Equity Incentive Plan) (incorporated by
reference to Exhibit 10.4.3 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, filed
with the SEC on May 12, 2008).†
10.2.7.3
Form of Restricted Stock Agreement (Pursuant to the 2008 Equity Incentive Plan) (incorporated by reference to
Exhibit 10.4.4 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, filed with the
SEC on May 12, 2008).†
10.2.8
The Amended and Restated Calpine Corporation 2008 Director Incentive Plan (incorporated by reference to
Appendix A to Calpine’s Definitive Proxy Statement on Schedule 14A filed with the SEC on April 5, 2010).†
10.2.9
Calpine Corporation Change in Control and Severance Benefits Plan (incorporated by reference to Exhibit 10.7 to
Calpine’s Current Report on Form 8-K filed with the SEC on December 26, 2012).†
10.2.10
Letter Agreement, dated December 30, 2008, between the Company and Jim D. Deidiker (incorporated by reference
to Exhibit 10.1 to Calpine’s Current Report on Form 8-K filed with the SEC on January 8, 2009).†
10.2.11
Letter re Employment Offer, dated February 6, 2009, between the Company and Michael D. Rogers (incorporated
by reference to Exhibit 10.1 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009,
filed with the SEC on May 7, 2009).†
103
Exhibit
Number
18.1
Description
Letter of preferability regarding change in accounting principle from PricewaterhouseCoopers LLP, Independent
Registered Public Accounting Firm (incorporated by reference to Exhibit 18.1 to Calpine’s Annual Report on Form
10-K for the year ended December 31, 2009 filed with the SEC on February 25, 2010).
21.1
Subsidiaries of the Company.*
23.1
Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.*
24.1
Power of Attorney of Officers and Directors of Calpine Corporation (set forth on the signature pages of this Form
10-K).*
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 Chief Executive Officer and 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.*
_______________
*
‡
†
**
††
Filed herewith.
Furnished herewith.
Management contract or compensatory plan, contract or arrangement.
Schedules omitted pursuant to Item 601(b)(2) of Regulation S-K. Calpine will furnish supplementally a copy of any omitted
schedule to the SEC upon request.
Portions of this exhibit have been omitted pursuant to a request for confidential treatment under Rule 24b-2 under the
Securities Exchange Act of 1934.
104
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.
SIGNATURES
CALPINE CORPORATION
By:
/s/ ZAMIR RAUF
Zamir Rauf
Executive Vice President and Chief Financial Officer
Date: February 12, 2013
105
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENT: That the undersigned officers and directors of Calpine Corporation do
hereby constitute and appoint W. Thaddeus Miller the lawful attorney and agent or attorneys and agents with power and authority
to do any and all acts and things and to execute any and all instruments which said attorneys and agents, or either of them, determine
may be necessary or advisable or required to enable Calpine Corporation to comply with the Securities and Exchange Act of 1934,
as amended, and any rules or regulations or requirements of the Securities and Exchange Commission in connection with this
Report. Without limiting the generality of the foregoing power and authority, the powers granted include the power and authority
to sign the names of the undersigned officers and directors in the capacities indicated below to this Report or amendments or
supplements thereto, and each of the undersigned hereby ratifies and confirms all that said attorneys and agents, or either of them,
shall do or cause to be done by virtue hereof. This Power of Attorney may be signed in several counterparts.
IN WITNESS WHEREOF, each of the undersigned has executed this Power of Attorney as of the date indicated opposite
the name.
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following
persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ JACK A. FUSCO
Jack A. Fusco
/s/ ZAMIR RAUF
Zamir Rauf
/s/ JIM D. DEIDIKER
Jim D. Deidiker
/s/ FRANK CASSIDY
Frank Cassidy
/s/ ROBERT C. HINCKLEY
Robert C. Hinckley
/s/ DAVID C. MERRITT
David C. Merritt
/s/ W. BENJAMIN MORELAND
W. Benjamin Moreland
/s/ ROBERT MOSBACHER, JR.
Robert Mosbacher, Jr.
/s/ DENISE M. O'LEARY
Denise M. O’Leary
/s/ WILLIAM E. OBERNDORF
William E. Oberndorf
/s/ J. STUART RYAN
J. Stuart Ryan
Chief Executive Officer and Director
(principal executive officer)
February 12, 2013
Executive Vice President and Chief
Financial Officer (principal financial
officer)
February 12, 2013
Chief Accounting Officer (principal
accounting officer)
February 12, 2013
February 12, 2013
February 12, 2013
February 12, 2013
February 12, 2013
February 12, 2013
February 12, 2013
February 12, 2013
February 12, 2013
Director
Director
Director
Director
Director
Director
Director
Director
106
CALPINE CORPORATION AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2012
Report of Independent Registered Public Accounting Firm ................................................................................................
Consolidated Statements of Operations for the Years Ended December 31, 2012, 2011 and 2010.....................................
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2012, 2011 and 2010.....
Consolidated Balance Sheets at December 31, 2012 and 2011............................................................................................
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2012, 2011 and 2010.....................
Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010....................................
Notes to Consolidated Financial Statements for the Years Ended December 31, 2012, 2011 and 2010 .............................
Page
108
109
111
112
113
114
116
107
Report of Independent Registered Public Accounting Firm
To the Board of Directors
and Stockholders of Calpine Corporation
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)-1 present fairly, in all material
respects, the financial position of Calpine Corporation and its subsidiaries at December 31, 2012 and 2011, and the results of their
operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting
principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed
in the index appearing under Item 15(a)-2 presents fairly, in all material respects, the information set forth therein when read in
conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as of December 31, 2012 based on criteria established in Internal
Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining
effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial
reporting, included in Management’s Report on Internal Control over Financial Reporting, appearing under Item 9A. Our
responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s
internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards
of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits
to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective
internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included
examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting
principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our
audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting,
assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal
control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the
circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets
of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that
could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 12, 2013
108
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Years Ended December 31, 2012, 2011 and 2010
(in millions, except share and per share amounts)
2012
2011
2010
Operating revenues:
Commodity revenue.................................................................................................. $
Unrealized mark-to-market gain (loss).....................................................................
Other revenue............................................................................................................
Operating revenues ..............................................................................................
5,417
$
6,753
$
48
13
35
12
5,478
6,800
Operating expenses:
Fuel and purchased energy expense:
Commodity expense .................................................................................................
Unrealized mark-to-market (gain) loss.....................................................................
Fuel and purchased energy expense.....................................................................
Plant operating expense ............................................................................................
Depreciation and amortization expense....................................................................
Sales, general and other administrative expense ......................................................
Other operating expenses..........................................................................................
Total operating expenses......................................................................................
Impairment losses .......................................................................................................
(Gain) on sale of assets, net ........................................................................................
(Income) from unconsolidated investments in power plants ......................................
Income from operations............................................................................................
Interest expense...........................................................................................................
Loss on interest rate derivatives..................................................................................
Interest (income) .........................................................................................................
Debt extinguishment costs ..........................................................................................
Other (income) expense, net .......................................................................................
Income (loss) before income taxes and discontinued operations .............................
Income tax expense (benefit) ......................................................................................
Income (loss) before discontinued operations ..........................................................
Discontinued operations, net of tax expense...............................................................
Net income (loss) .................................................................................................
Net income attributable to the noncontrolling interest................................................
2,894
130
3,024
922
562
140
78
4,726
—
(222)
(28)
1,002
736
14
(11)
30
15
218
19
199
—
199
—
Net income (loss) attributable to Calpine ............................................................ $
199
$
6,578
(61)
28
6,545
4,187
(204)
3,983
868
570
151
91
4,299
60
4,359
904
550
131
77
6,021
5,663
—
—
(21)
800
760
145
(9)
94
21
(211)
(22)
(189)
—
(189)
(1)
(190) $
116
(119)
(16)
901
813
223
(11)
91
15
(230)
(68)
(162)
193
31
—
31
The accompanying notes are an integral part of these Consolidated Financial Statements.
109
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS — (Continued)
(in thousands, except per share amounts)
2012
2011
2010
Basic earnings (loss) per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands) ..................
Income (loss) before discontinued operations attributable to Calpine ..................... $
Discontinued operations, net of tax expense attributable to Calpine........................
Net income (loss) per common share attributable to Calpine — basic................ $
Diluted earnings (loss) per common share attributable to Calpine:
Weighted average shares of common stock outstanding (in thousands) ..................
Income (loss) before discontinued operations attributable to Calpine ..................... $
Discontinued operations, net of tax expense attributable to Calpine........................
Net income (loss) per common share attributable to Calpine — diluted............. $
0.43
—
0.43
471,343
0.42
—
0.42
$
$
$
$
467,752
485,381
(0.39) $
—
(0.39) $
486,044
(0.33)
0.39
0.06
485,381
(0.39) $
—
(0.39) $
487,294
(0.33)
0.39
0.06
The accompanying notes are an integral part of these Consolidated Financial Statements.
110
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
For the Years Ended December 31, 2012, 2011 and 2010
(in millions)
2012
2011
2010
Net income (loss) ...................................................................................................
Cash flow hedging activities:
Gain (loss) on cash flow hedges before reclassification adjustment for cash
flow hedges realized in net income (loss) .....................................................
Reclassification adjustment for (gain) loss on cash flow hedges realized in
net income (loss)............................................................................................
Unrealized actuarial losses arising during period ..................................................
Foreign currency translation gain (loss) ................................................................
Income tax (expense) benefit .................................................................................
Other comprehensive income (loss).......................................................................
Comprehensive income (loss)................................................................................
Comprehensive income attributable to the noncontrolling interest .......................
Comprehensive income (loss) attributable to Calpine .................................
$
199
$
(189)
$
(61)
(20)
(1)
3
9
(70)
129
—
129
$
(69)
(25)
(3)
(1)
45
(53)
(242)
(1)
(243)
$
$
31
25
141
—
2
(27)
141
172
—
172
The accompanying notes are an integral part of these Consolidated Financial Statements.
111
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, 2012 and 2011
(in millions, except share and per share amounts)
2012
2011
Current assets:
ASSETS
Cash and cash equivalents ($109 and $285 attributable to VIEs).................................................... $
Accounts receivable, net of allowance of $6 and $13......................................................................
Margin deposits and other prepaid expense .....................................................................................
Restricted cash, current ($53 and $57 attributable to VIEs) ............................................................
Derivative assets, current .................................................................................................................
Inventory and other current assets....................................................................................................
Total current assets ......................................................................................................................
Property, plant and equipment, net ($4,192 and $4,313 attributable to VIEs) ...................................
Restricted cash, net of current portion ($59 and $53 attributable to VIEs) ........................................
Investments .........................................................................................................................................
Long-term derivative assets................................................................................................................
Other assets.........................................................................................................................................
Total assets ................................................................................................................................ $
LIABILITIES & STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable ............................................................................................................................. $
Accrued interest payable ..................................................................................................................
Debt, current portion ($39 and $41 attributable to VIEs) ................................................................
Derivative liabilities, current............................................................................................................
Income taxes payable .......................................................................................................................
Other current liabilities.....................................................................................................................
Total current liabilities.................................................................................................................
Debt, net of current portion ($2,660 and $2,522 attributable to VIEs)...............................................
Long-term derivative liabilities ..........................................................................................................
Other long-term liabilities...................................................................................................................
Total liabilities...........................................................................................................................
$
$
$
1,284
437
244
193
339
335
2,832
13,005
60
81
98
473
16,549
382
180
115
357
11
273
1,318
10,635
293
247
12,493
1,252
598
193
139
1,051
329
3,562
13,019
55
80
113
542
17,371
435
200
104
1,144
3
276
2,162
10,321
279
245
13,007
Commitments and contingencies (see Note 15)
Stockholders’ equity:
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and
outstanding at December 31, 2012 and 2011................................................................................
—
—
Common stock, $0.001 par value per share; authorized 1,400,000,000 shares, 492,495,100
shares issued and 457,048,970 shares outstanding at December 31, 2012, and 490,468,815
shares issued and 481,743,738 shares outstanding at December 31, 2011...................................
Treasury stock, at cost, 35,446,130 and 8,725,077 shares, respectively..........................................
Additional paid-in capital.................................................................................................................
Accumulated deficit .........................................................................................................................
Accumulated other comprehensive loss ...........................................................................................
Total Calpine stockholders’ equity..............................................................................................
Noncontrolling interest.....................................................................................................................
Total stockholders’ equity............................................................................................................
Total liabilities and stockholders’ equity................................................................................... $
1
(594)
12,335
(7,500)
(248)
3,994
62
4,056
16,549
$
1
(125)
12,305
(7,699)
(178)
4,304
60
4,364
17,371
The accompanying notes are an integral part of these Consolidated Financial Statements.
112
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF
STOCKHOLDERS’ EQUITY
For the Years Ended December 31, 2012, 2011 and 2010
(in millions)
Common
Stock
Treasury
Stock
Additional
Paid-In
Capital
Accumulated
Deficit
Accumulated
Other
Comprehensive
Loss
Noncontrolling
Interest
Total
Stockholders’
Equity
$
12,256
$
(7,540)
$
(266)
$
(2)
$
4,446
$
$
Balance, December 31, 2009 .................. $
Treasury stock transactions..................
Stock-based compensation expense.....
Other ....................................................
Net income...........................................
Other comprehensive income ..............
Balance, December 31, 2010 .................. $
Treasury stock transactions..................
Stock-based compensation expense.....
Other ....................................................
Net income (loss).................................
Other comprehensive loss....................
Balance, December 31, 2011 .................. $
Treasury stock transactions..................
Stock-based compensation expense.....
Option exercises ..................................
Other ....................................................
Net income...........................................
Other comprehensive loss....................
Balance, December 31, 2012 .................. $
1
—
—
—
—
—
1
—
—
—
—
—
1
—
—
—
—
—
—
1
(3)
(2)
—
—
—
—
—
24
1
—
—
—
—
—
31
—
—
—
—
—
141
(5)
$
12,281
$
(7,509)
$
(125)
$
(120)
—
—
—
—
—
24
—
—
—
—
—
—
(190)
—
$
(125)
$
12,305
$
(7,699)
$
(469)
—
—
—
—
—
—
25
5
—
—
—
—
—
—
—
199
—
$
(594)
$
12,335
$
(7,500)
$
—
—
—
—
(53)
(178)
$
—
—
—
—
—
(70)
(248)
$
—
—
28
—
—
26
—
—
33
1
—
60
—
—
—
2
—
—
62
$
$
$
(2)
24
29
31
141
4,669
(120)
24
33
(189)
(53)
4,364
(469)
25
5
2
199
(70)
4,056
The accompanying notes are an integral part of these Consolidated Financial Statements.
113
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2012, 2011 and 2010
(in millions)
Cash flows from operating activities:
Net income (loss)...................................................................................................... $
Adjustments to reconcile net income (loss) to net cash provided by operating
activities:
Depreciation and amortization expense(1) ............................................................
Debt extinguishment costs ...................................................................................
Deferred income taxes .........................................................................................
Impairment losses ................................................................................................
(Gain) loss on sale of power plants and other, net...............................................
Unrealized mark-to-market (gain) loss ................................................................
(Income) from unconsolidated investments in power plants ...............................
Return on unconsolidated investments in power plants.......................................
Stock-based compensation expense.....................................................................
Other ....................................................................................................................
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable .............................................................................................
Derivative instruments, net ..................................................................................
Other assets ..........................................................................................................
Accounts payable and accrued expenses .............................................................
Settlement of non-hedging interest rate swaps ....................................................
Other liabilities.....................................................................................................
Net cash provided by operating activities .......................................................
Cash flows from investing activities:
Purchases of property, plant and equipment.............................................................
Proceeds from sale of power plants, interests and other...........................................
Purchase of Bosque Energy Center, Conectiv assets and BRSP, net of cash...........
Cash acquired due to consolidation of OMEC .........................................................
Return of investment from unconsolidated investments ..........................................
Settlement of non-hedging interest rate swaps .........................................................
(Increase) decrease in restricted cash .......................................................................
Purchases of deferred transmission credits...............................................................
Other .........................................................................................................................
Net cash used in investing activities..................................................................
Cash flows from financing activities:
Borrowings under First Lien Term Loans.................................................................
Repayments of First Lien Term Loans .....................................................................
Repayments on NDH Project Debt...........................................................................
Issuance of First Lien Notes .....................................................................................
Repayments of First Lien Notes ...............................................................................
Repayments on First Lien Credit Facility.................................................................
Borrowings from project financing, notes payable and other...................................
Repayments of project financing, notes payable and other ......................................
Capital contributions from noncontrolling interest holder .......................................
Financing costs .........................................................................................................
Stock repurchases .....................................................................................................
Refund of financing costs .........................................................................................
Other .........................................................................................................................
Net cash provided by (used in) financing activities ..........................................
Net increase (decrease) in cash and cash equivalents .................................................
Cash and cash equivalents, beginning of period .........................................................
Cash and cash equivalents, end of period ................................................................... $
2012
2011
2010
199
$
(189) $
31
605
—
1
—
(212)
(72)
(28)
24
25
1
159
(52)
(57)
(86)
156
(10)
653
(637)
825
(432)
—
5
(156)
(59)
(12)
(4)
(470)
835
(19)
—
—
(590)
—
389
(289)
—
(20)
(463)
—
6
(151)
32
1,252
1,284
587
82
(21)
—
13
(30)
(21)
6
24
6
74
15
1
28
189
11
775
(683)
13
—
—
—
(189)
54
(31)
—
(836)
1,657
—
(1,283)
1,200
—
(1,195)
327
(550)
33
(81)
(119)
—
(3)
(14)
(75)
1,327
1,252
$
$
615
91
(26)
116
(314)
56
(16)
11
24
1
91
(52)
277
(43)
69
(2)
929
(369)
954
(1,680)
8
—
(69)
322
—
3
(831)
—
—
—
3,491
—
(3,477)
1,272
(937)
17
(136)
—
10
—
240
338
989
1,327
The accompanying notes are an integral part of these Consolidated Financial Statements.
114
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS — (Continued)
(in millions)
Cash paid during the period for:
Interest, net of amounts capitalized .......................................................................... $
Income taxes ............................................................................................................. $
719
16
$
$
656
18
$
$
2012
2011
2010
Supplemental disclosure of non-cash investing and financing activities:
Change in capital expenditures included in accounts payable.................................. $
Other non-cash additions to property, plant and equipment..................................... $
Liabilities assumed in BRSP acquisition.................................................................. $
Conversion of project debt to noncontrolling interest .............................................. $
$
19
13
$
— $
— $
(24) $
— $
— $
— $
____________
(1)
Includes depreciation and amortization included in fuel and purchased energy expense, interest expense and
discontinued operations on our Consolidated Statements of Operations.
The accompanying notes are an integral part of these Consolidated Financial Statements.
635
21
1
—
85
11
115
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the Years Ended December 31, 2012, 2011 and 2010
1.
Organization and Operations
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, Texas and the Mid-Atlantic region 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 engage in the purchase of natural gas and fuel
oil as fuel for our power plants and in related natural gas transportation and storage transactions, and in the purchase of electric
transmission rights to deliver power to our customers. We also enter into natural gas and power physical and financial contracts
to economically hedge our business risks and optimize our portfolio of power plants.
2.
Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
Our Consolidated Financial Statements have been prepared in accordance with U.S. GAAP and include the accounts of
all majority-owned subsidiaries that are not VIEs and all VIEs where we have determined we are the primary beneficiary.
Intercompany transactions have been eliminated in consolidation.
Equity Method Investments — We use the equity method of accounting to record our net interests in VIEs where we have
determined that we are not the primary beneficiary, which include Greenfield LP, a 50% partnership interest, and Whitby, a 50%
partnership interest. Our share of net income (loss) is calculated according to our equity ownership percentage or according to the
terms of the applicable partnership agreement. See Note 5 for further discussion of our VIEs and unconsolidated investments.
Change in Presentation — We have changed the presentation on our Consolidated Statements of Operations to separately
present our Commodity revenue, unrealized mark-to-market gain (loss) and other revenue which are components of operating
revenues and our Commodity expense and unrealized mark-to-market (gain) loss which are components of fuel and purchased
energy expense. The change in presentation had no impact on our financial condition, results of operations or cash flows.
Reclassification — We have reclassified RGGI compliance and other environmental costs previously recorded in other
operating expenses of $10 million and $9 million to Commodity expense on our Consolidated Statements of Operations for the
years ended December 31, 2011 and 2010, respectively, to conform to the current year presentation.
Jointly-Owned Plants — Certain of our subsidiaries own undivided interests in jointly-owned plants. These plants are
maintained and operated pursuant to their joint ownership participation and operating agreements. We are responsible for our
subsidiaries’ share of operating costs and direct expenses and include our proportionate share of the facilities and related revenues
and direct expenses in these jointly-owned plants in the corresponding balance sheet and income statement captions of our
Consolidated Financial Statements. The following table summarizes our proportionate ownership interest in jointly-owned power
plants:
As of December 31, 2012
Ownership Interest
Property, Plant &
Equipment
Accumulated
Depreciation
Construction in Progress
(in millions, except percentages)
Freestone Energy Center ...
Hidalgo Energy Center......
75.0% $
78.5% $
392
252
$
$
(124)
(86)
$
$
1
—
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 Financial Statements. Actual results could differ from those estimates.
116
Fair Value of Financial Instruments and Derivatives
The carrying values of accounts receivable, accounts payable and other receivables and payables approximate their
respective fair values due to their short-term maturities. See Note 6 for disclosures regarding the fair value of our debt instruments
and Notes 7 and 8 for disclosures regarding the fair values of our derivative instruments and margin deposits and certain of our
cash balances.
Concentrations of Credit Risk
Financial instruments that potentially subject us to credit risk consist of cash and cash equivalents, restricted cash, accounts
and notes receivable and derivative assets. Certain of our cash and cash equivalents, as well as our restricted cash balances, are
invested in money market accounts with investment banks that are not FDIC insured. We place our cash and cash equivalents and
restricted cash in what we believe to be creditworthy financial institutions and 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.
Additionally, we actively monitor the credit risk of our counterparties, including our receivable, commodity and derivative
transactions. Our accounts and notes receivable are concentrated within entities engaged in the energy industry, mainly within the
U.S. We generally have not collected collateral for accounts receivable from utilities and end-user customers; however, we may
require collateral in the future. For financial and commodity derivative counterparties, we evaluate the net accounts receivable,
accounts payable and fair value of commodity contracts and may require security deposits, cash margin or letters of credit to be
posted if our exposure reaches a certain level or their credit rating declines.
Our counterparties primarily consist of three categories of entities who participate in the wholesale energy markets:
•
•
•
financial institutions and trading companies;
regulated utilities, municipalities, cooperatives, ISOs and other retail power suppliers; and
oil, natural gas, chemical and other energy-related industrial companies.
We have concentrations of credit risk with a few of our commercial customers relating to our sales of power, steam and
hedging and optimization activities. We have exposure to trends within the energy industry, including declines in the
creditworthiness of our counterparties for our commodity and derivative transactions. Currently, certain of our marketing
counterparties within the energy industry have below investment grade credit ratings. Our risk control group manages counterparty
credit risk and monitors our net exposure with each counterparty on a daily basis. The analysis is performed on a mark-to-market
basis using forward curves. The net exposure is compared against a counterparty credit risk threshold which is determined based
on each counterparty’s credit rating and evaluation of their financial statements. We utilize these thresholds to determine the need
for additional collateral or restriction of activity with the counterparty. 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.
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. At December 31, 2012 and
2011, we had cash and cash equivalents of $131 million and $306 million, respectively, that were subject to such project finance
facilities and lease agreements.
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 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 Balance Sheets and Statements of Cash Flows.
117
The table below represents the components of our restricted cash as of December 31, 2012 and 2011 (in millions):
Debt service(1)....................................... $
Construction/major maintenance..........
Security/project/insurance ....................
Other.....................................................
Total ................................................... $
___________
Current
11
32
101
49
193
2012
Non-Current
41
$
14
3
2
60
$
$
$
Total
Current
52
46
104
51
253
$
$
11
33
79
16
139
2011
Non-Current
42
$
10
—
3
55
$
$
$
Total
53
43
79
19
194
(1) At both December 31, 2012 and 2011, amounts restricted for debt service included approximately $25 million of repurchase
agreements with a financial institution containing maturity dates greater than one year.
Accounts Receivable and Payable
Accounts receivable and payable represent amounts due from customers and owed to vendors, respectively. Accounts
receivable are recorded at invoiced amounts, net of reserves and allowances, and do not bear interest. Receivable balances greater
than 30 days past due are individually reviewed for collectability, and if deemed uncollectible, are charged off against the allowance
accounts after all means of collection have been exhausted and the potential for recovery is considered remote. We use our best
estimate to determine the required allowance for doubtful accounts based on a variety of factors, including the length of time
receivables are past due, economic trends and conditions affecting our customer base, significant one-time events and historical
write-off experience. Specific provisions are recorded for individual receivables when we become aware of a customer’s inability
to meet its financial obligations. We review the adequacy of our reserves and allowances quarterly.
The accounts receivable and payable balances also include settled but unpaid amounts relating to our marketing, hedging
and optimization activities. Some of these receivables and payables with individual counterparties are subject to master netting
arrangements whereby we legally have a right of offset and settle the balances net. However, for balance sheet presentation purposes
and to be consistent with the way we present the majority of amounts related to marketing, hedging and optimization activities
on our Consolidated Statements of Operations, we present our receivables and payables on a gross basis. We do not have any
significant off balance sheet credit exposure related to our customers.
Inventory
At December 31, 2012 and 2011, we had inventory of $301 million and $294 million, respectively. Inventory primarily
consists of spare parts, stored natural gas and fuel oil, emission reduction credits and natural gas exchange imbalances. Inventory,
other than spare parts, is stated primarily at the lower of cost or market value under the weighted average cost method. Spare parts
inventory is valued at weighted average cost and is expensed to plant operating expense or capitalized to property, plant and
equipment as the parts are utilized and consumed.
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 previously
subject to first priority liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility as collateral
under certain of our power and natural gas agreements. These agreements qualify as “eligible commodity hedge agreements”
under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. The first priority liens have been granted in
order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to our counterparties under
such agreements. The counterparties under such agreements would share the benefits of the collateral subject to such first priority
liens ratably with the lenders under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. Our interest
rate swap agreements relate to hedges of certain of our project financings collateralized by first priority liens on the underlying
assets. See Note 9 for a further discussion on our amounts and use of collateral.
Deferred Financing Costs
Costs incurred related to the issuance of debt instruments are deferred and amortized over the term of the related debt
using a method that approximates the effective interest rate method. However, when the timing of debt transactions involve
contemporaneous exchanges of cash between us and the same creditor(s) in connection with the issuance of a new debt obligation
118
and satisfaction of an existing debt obligation, deferred financing costs are accounted for depending on whether the transaction
qualifies as an extinguishment or modification, which requires us to either write off the original deferred financing costs and
capitalize the new issuance costs, or continue to amortize the original deferred financing costs and immediately expense the new
issuance costs.
Property, Plant and Equipment, Net
Property, plant, and equipment items are recorded at cost. We capitalize costs incurred in connection with the construction
of power plants, the development of geothermal properties and the refurbishment of major turbine generator equipment. When
capital improvements to leased power plants meet our capitalization criteria they are capitalized as leasehold improvements and
amortized over the shorter of the term of the lease or the economic life of the capital improvement. We expense maintenance when
the service is performed for work that does not meet our capitalization criteria. Our current capital expenditures at our Geysers
Assets are those incurred for proven reserves and reservoir replenishment (primarily water injection), pipeline and power generation
assets and drilling of “development wells” as all drilling activity has been performed within the known boundaries of the steam
reservoir. We have capitalized costs incurred during ownership consisting of additions, repairs or replacements when they
appreciably extend the life, increase the capacity or improve the efficiency or safety of the property. Such costs are expensed when
they do not meet the above criteria. We purchased our Geysers Assets as a proven steam reservoir and accounted for the assets
under purchase accounting. All well costs, except well workovers and routine repairs and maintenance, have been capitalized since
our purchase date.
We depreciate our assets under the straight-line method over the shorter of their estimated useful lives or lease term. For
our natural gas-fired power plants, we assume an estimated salvage value which approximates 10% of the depreciable cost basis
where we own the land or have a favorable option to purchase the land at conclusion of the lease term and approximately 0.15%
of the depreciable costs basis for rotable equipment. For our Geysers Assets, we typically assume no salvage values. We use the
component depreciation method for our natural gas-fired power plant rotable parts and our information technology equipment and
the composite depreciation method for most of all of the other natural gas-fired power plant asset groups and Geysers Assets.
Generally, upon normal retirement of assets under the composite depreciation method, the costs of such assets are retired
against accumulated depreciation and no gain or loss is recorded. For the retirement of assets under the component depreciation
method, generally, the costs and related accumulated depreciation of such assets are removed from our Consolidated Balance
Sheets and a gain or loss is recorded as plant operating expense.
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. If we determine that the undiscounted cash flows from an asset to be held and
used are less than the carrying amount of the asset, 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 and future contracts and PPAs and
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).
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 impact 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
119
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 impact of
such variations could be material.
During 2012 and 2011, we did not record any impairment losses. During 2010, we impaired approximately $95 million
related to South Point (see Note 3 for further information related to our acquisition of the South Point lease and subsequent
impairment of our South Point assets) and development costs of approximately $21 million associated with two development
projects that originated prior to our Chapter 11 bankruptcy proceedings. We continued to market these projects after our Effective
Date, but during 2010 we determined that their continued development was unlikely.
Asset Retirement Obligation
We record all known asset retirement obligations for which the liability’s fair value can be reasonably estimated. Over
time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related
asset. At December 31, 2012 and 2011, our asset retirement obligation liabilities were $38 million and $27 million, respectively,
primarily relating to land leases upon which our power plants are built and the requirement that the property meet specific conditions
upon its return.
Revenue Recognition
Our operating revenues are comprised of the following:
•
•
•
power and steam revenue consisting of fixed and variable capacity payments, which are not related to generation
including capacity payments received from PJM capacity auctions, variable payments for power and steam, which
are related to generation, host steam and RECs from our Geysers Assets, other revenues such as RMR Contracts,
resource adequacy and certain ancillary service revenues and realized settlements from our marketing, hedging and
optimization activities;
unrealized revenues from derivative instruments as a result of our marketing, hedging and optimization activities;
and
other service revenues.
Power and Steam
Physical Commodity Contracts — We recognize revenue primarily from the sale of power and steam thermal energy for
sale to our customers for use in industrial or other heating operations upon transmission and delivery to the customer.
We routinely enter into physical commodity contracts for sales of our generated power to manage risk and capture the
value inherent in our generation. Such contracts often meet the criteria of a derivative but are generally eligible for and designated
under the normal purchase normal sale exemption. We apply lease accounting to contracts that meet the definition of a lease and
accrual accounting treatment to those contracts that are either exempt from derivative accounting or do not meet the definition of
a derivative instrument. Additionally, we determine whether the financial statement presentation of revenues should be on a gross
or net basis.
With respect to our physical executory contracts, where we act as a principal, we take title of the commodities and assume
the risks and rewards of ownership by receiving the natural gas and using the natural gas in our operations to generate and deliver
the power. Where we act as principal, we record settlement of our physical commodity contracts on a gross basis. Where we do
not take title of the commodities but receive a net variable payment to convert natural gas into power and steam in a tolling
operation, we record the variable payment as revenue but do not record any fuel and purchased energy expense.
Capacity payments, RMR Contracts, RECs, resource adequacy and other ancillary revenues are recognized when
contractually earned and consist of revenues received from our customers either at the market price or a contract price.
Realized and Unrealized Revenues from Commodity Derivative Instruments
Realized Settlements of Commodity Derivative Instruments — The realized value of power commodity sales and purchase
contracts that are net settled or settled as gross sales and purchases, but could have been net settled, are reflected on a net basis
and are included in Commodity revenue on our Consolidated Statements of Operations.
120
Unrealized Mark-to-Market Gain (Loss) — The changes in the unrealized mark-to-market value of power-based
commodity derivative instruments are reflected on a net basis as a separate component of operating revenues.
Leases — We have contracts, such as certain tolling agreements, which we account for as operating leases under U.S.
GAAP. Generally, we levelize certain components of these contract revenues on a straight-line basis over the term of the contract.
The total contractual future minimum lease rentals for our contracts accounted for as operating leases, excluding tolling agreements
related to power plants under construction, at December 31, 2012, are as follows (in millions):
2013 ......................................................................................................................................................................... $
2014 .........................................................................................................................................................................
2015 .........................................................................................................................................................................
2016 .........................................................................................................................................................................
2017 .........................................................................................................................................................................
Thereafter ................................................................................................................................................................
Total....................................................................................................................................................................... $
548
446
455
397
359
2,078
4,283
Accounting for Derivative Instruments
We enter into a variety of derivative instruments including both exchange traded and OTC power and natural gas forwards,
options as well as instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) and
interest rate swaps. 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 are designated under the normal purchase normal
sale exemption. Accounting for derivatives at fair value requires us to make estimates about future prices during periods for which
price quotes are not available from sources external to us, in which case we rely on internally developed price estimates. See Note
8 for a further discussion on our accounting for derivatives.
Fuel and Purchased Energy Expense
Fuel and purchased energy expense is comprised of the cost of natural gas and fuel oil purchased from third parties for
the purposes of consumption in our power plants as fuel, and the cost of power and natural gas purchased from third parties for
our marketing, hedging and optimization activities and realized settlements and unrealized mark-to-market gains and losses
resulting from general market price movements against certain derivative natural gas contracts including financial gas transactions
economically hedging anticipated future power sales that do not qualify for hedge accounting treatment.
Realized and Unrealized Expenses from Commodity Derivative Instruments
Realized Settlements of Commodity Derivative Instruments — The realized value of natural gas purchase and sales
commodity contracts that are net settled are reflected on a net basis and included in Commodity expense on our Consolidated
Statements of Operations. Power purchase commodity contracts that result in the physical delivery of power, and that also
supplement our power generation, are reflected on a gross basis and are included in Commodity expense on our Consolidated
Statements of Operations.
Unrealized Mark-to-Market (Gain) Loss — The changes in the unrealized mark-to-market value of natural gas-based
commodity derivative instruments are reflected on a net basis as a separate component of fuel and purchased energy expense.
Plant Operating Expense
Plant operating expense primarily includes employee expenses, utilities, chemicals, repairs and maintenance, insurance
and property taxes. We recognize these expenses when the service is performed or in the period in which the expense relates.
Income Taxes
Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized
for the future tax consequences attributable to differences between the financial statement carrying values of existing assets and
liabilities and their respective tax basis and tax credit and NOL carryforwards. Deferred tax assets and liabilities are measured
using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered
or settled. The effect on deferred tax assets and liabilities due to a change in tax rates is recognized in income in the period that
includes the enactment date.
121
We recognize the financial statement effects of a tax position when it is more-likely-than-not, based on the technical
merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold
is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a
taxing authority. We reverse a previously recognized tax position in the first period in which it is no longer more-likely-than-not
that the tax position would be sustained upon examination. See Note 10 for a further discussion on our income taxes.
Earnings (Loss) per Share
Basic earnings (loss) per share is calculated using the weighted average shares outstanding during the period and includes
restricted stock units for which no future service is required as a condition to the delivery of the underlying common stock. Diluted
earnings (loss) per share is calculated by adjusting the weighted average shares outstanding by the dilutive effect of share-based
awards using the treasury stock method. See Note 11 for a further discussion of our earnings (loss) per share.
Stock-Based Compensation
We use the Black-Scholes option-pricing model or the Monte Carlo simulation model to estimate the fair value of our
employee stock options on the grant date. The Black-Scholes option-pricing model and the Monte Carlo simulation model take
into account certain variables, which are further explained in Note 12.
New Accounting Standards and Disclosure Requirements
Fair Value Measurement — In May 2011, the FASB issued Accounting Standards Update 2011-04, “Fair Value
Measurement” to clarify and amend the application or requirements relating to fair value measurements and disclosures relating
to fair value measurements. The update stems from the FASB and the International Accounting Standards Board project to develop
common requirements for measuring fair value and for disclosing information about fair value measurements. The update did not
impact any of our fair value measurements but did require disclosure of the following:
•
•
•
quantitative information about the unobservable inputs used in a fair value measurement that is categorized within
level 3 of the fair value hierarchy;
for those fair value measurements categorized within level 3 of the fair value hierarchy, both the valuation processes
used and the sensitivity of the fair value measurement to changes in unobservable inputs and the interrelationships
between those unobservable inputs, if any; and
the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement
of financial position but for which the fair value is required to be disclosed.
The new requirements relating to fair value measurements are prospective and effective for interim and annual periods
beginning after December 15, 2011, with early adoption prohibited. We adopted all of the requirements related to this update at
January 1, 2012. Since this update did not impact any of our fair value measurements and only required additional disclosures,
adoption of this standard did not have a material impact on our financial condition, results of operations or cash flows.
Disclosures about Offsetting Assets and Liabilities — In December 2011, the FASB issued Accounting Standards Update
2011-11, “Balance Sheet - Disclosures about Offsetting Assets and Liabilities” to enhance disclosure requirements relating to the
offsetting of assets and liabilities on an entity's balance sheet. The update requires enhanced disclosures regarding assets and
liabilities that are presented net or gross in the statement of financial position when the right of offset exists, or that are subject to
an enforceable master netting arrangement. In January 2013, the FASB issued Accounting Standards Update 2013-01, “Clarifying
the Scope of Disclosures about Offsetting Assets and Liabilities” to provide clarification that the scope previously defined in
Accounting Standards Update 2011-11 applies to derivatives, repurchase agreements, reverse repurchase agreements and securities
borrowing and lending transactions that are subject to an enforceable master netting arrangement or similar agreement. The new
disclosure requirements relating to these updates are retrospective and effective for annual and interim periods beginning on or
after January 1, 2013. These updates only require additional disclosures, as such, the adoption of these standards will not have a
material impact on our financial condition, results of operations or cash flows.
Comprehensive Income — In February 2013, the FASB issued Accounting Standards Update 2013-02, “Reporting of
Amounts Reclassified Out of Accumulated Other Comprehensive Income” to amend the reporting of reclassifications out of AOCI
to require an entity to report the effect of significant reclassifications out of AOCI on the respective line items in net income if the
amount reclassified is required under U.S. GAAP to be reclassified in its entirety to net income in the same reporting period. An
entity shall provide this information together in one location, either on the face of the statement where net income is presented,
or as a separate disclosure in the notes to the financial statements. The new disclosure requirements relating to this update are
prospective and effective for interim and annual periods beginning after December 15, 2012, with early adoption permitted. This
122
update only requires additional disclosures, as such, the adoption of this standard will not have a material impact on our financial
condition, results of operations or cash flows.
3.
Acquisitions, Divestitures and Discontinued Operations
Acquisition of Bosque Energy Center
On November 7, 2012, we, through our indirect, wholly-owned subsidiary Calpine Bosque Energy Center, LLC, completed
the purchase of a power plant with a nameplate capacity of 800 MW owned by Bosque Power Co., LLC, for approximately $432
million. The modern, natural gas-fired, combined-cycle power plant increased capacity in our Texas segment and is located in
Central Texas near the unincorporated community of Laguna Park in Bosque County. The site includes a 250 MW generation
block with one natural-gas turbine, one heat recovery steam generator and one steam turbine that achieved COD in June 2001 and
a 550 MW generation block with two natural-gas turbines that went online in June 2000 as well as two heat recovery steam
generators and one steam turbine that achieved COD in June 2011. We funded the $432 million purchase price with cash on hand.
The purchase price was primarily allocated to property, plant and equipment. 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.
Conectiv Acquisition
On July 1, 2010, we, through our indirect, wholly-owned subsidiary NDH, completed the Conectiv Acquisition. The
assets acquired included 18 operating power plants and the York Energy Center that was under construction and achieved COD
on March 2, 2011, totaling 4,491 MW of capacity. We did not acquire Conectiv’s trading book, load serving auction obligations
or collateral requirements. Additionally, we did not assume any of Conectiv’s off-site environmental liabilities, environmental
remediation liabilities in excess of $10 million related to assets located in New Jersey that are subject to ISRA, or pre-close
accumulated pension and retirement welfare liabilities; however, we did assume pension liabilities on future services and
compensation increases for past services for approximately 130 grandfathered union employees who joined Calpine as a result of
the Conectiv Acquisition. During the second half of 2010, we initiated a voluntary retirement incentive program which reduced
the number of employees covered by our pension obligation by 31 employees. The net proceeds of $1.3 billion received from the
NDH Project Debt were used, together with available operating cash, to pay the Conectiv Acquisition purchase price of
approximately $1.64 billion and also fund a cash contribution from Calpine Corporation to NDH of $110 million to fund completion
of the York Energy Center. The NDH Project Debt was repaid in March 2011 with proceeds from borrowings under our 2018 First
Lien Term Loans.
The Conectiv Acquisition provided us with a significant presence in the Mid-Atlantic market, one of the most robust
competitive power markets in the U.S., and positioned us with three scale markets instead of two (California and Texas) giving
us greater geographic diversity. We accounted for the Conectiv Acquisition under the acquisition method of accounting in
accordance with U.S. GAAP.
The following table summarizes the pro forma operating revenues and net income (loss) attributable to Calpine for 2010
as if the Conectiv Acquisition had occurred on January 1, 2009. The pro forma information has been prepared by adding the
preliminary, unaudited historical results of Conectiv, as adjusted for depreciation expense (utilizing the preliminary values assigned
to the net assets acquired from Conectiv), interest expense from NDH Project Debt and income taxes to our historical results for
the periods indicated below (in millions, except per share amounts).
Operating revenues...............................................................................................................................................
Net loss attributable to Calpine ............................................................................................................................
Basic loss per common share attributable to Calpine ..........................................................................................
Diluted loss per common share attributable to Calpine .......................................................................................
$
$
$
$
2010
7,931
(83)
(0.17)
(0.17)
Acquisition of Broad River and South Point Leases
On December 8, 2010, we, through our indirect, wholly-owned subsidiary, Calpine BRSP, purchased entities from CIT
Capital USA Inc. that held the leases for our Broad River and South Point power plants by assuming debt with a fair value of
approximately $297 million and a cash payment of approximately $40 million. Prior to this purchase, our Broad River power plant
was operated under a sale-leaseback transaction that was accounted for as a failed sale-leaseback financing transaction and our
South Point power plant was accounted for as an operating lease. The purchase of the entities holding the power plant leases only
123
added an incremental $85 million in consolidated debt, as the transaction eliminated approximately $212 million recorded as debt
and accrued interest owed to CIT Capital USA Inc. under our Broad River power plant lease. The Calpine BRSP project debt was
repaid in October 2012 with proceeds from borrowings under our 2019 First Lien Term Loan.
We recorded a total pre-tax loss of approximately $125 million on our Consolidated Statement of Operations for the year
ended December 31, 2010, for this transaction, which was recorded as shown below (in millions):
Broad River: debt extinguishment costs..................................................................................................................... $
South Point: impairment loss .....................................................................................................................................
Total loss recorded for this transaction....................................................................................................................... $
30
95
125
Broad River — Prior to the purchase, we operated the Broad River power plant under a lease that was accounted for as
a failed sale-leaseback financing transaction under U.S. GAAP. The lease liability was included in project financing, notes payable
and other debt balance and the power plant assets were included in our property, plant and equipment. As a result of the purchase,
we did not adjust the historical value of the assets. We allocated the value of the consideration paid in the transaction based upon
the fair value of both power plants, and the result was an allocation of assumed debt that was greater than the prior debt obligation
resulting in a pre-tax loss of approximately $30 million. Because we primarily exchanged future lease obligations for a debt
obligation, the resulting loss is recorded as debt extinguishment costs in accordance with U.S. GAAP.
South Point — Prior to the purchase, we accounted for the South Point lease as an operating lease. We allocated the
consideration paid in the transaction based upon the fair value of both power plants. The result was an allocation of consideration
paid for South Point that was in excess of the fair value of assets acquired by approximately $95 million, which was primarily
due to the elimination of a lease levelization asset associated with the prior lease, which was no longer proper on a consolidated
basis. The resulting loss has been reported as an impairment loss for accounting purposes.
While the transaction resulted in a one-time, pre-tax loss, in the longer-term, the acquisition of these entities grants us
greater flexibility and more control of the future operation of both plants and simplified a previously complex leasing arrangement.
Sale of Riverside Energy Center
Our 603 MW Riverside Energy Center had a PPA that provided WP&L an option to purchase the power plant and plant-
related assets upon written notice of exercise prior to May 31, 2012. On May 18, 2012, WP&L exercised their option to purchase
Riverside Energy Center, LLC, one of our VIEs which owned Riverside Energy Center. The sale closed on December 31, 2012
for approximately $402 million, and we recorded a pre-tax gain of approximately $7 million, which is included in (gain) on sale
of assets, net on our Consolidated Statements of Operations. We expect to use the sale proceeds for our capital allocation activities
and for general corporate purposes. The sale of Riverside Energy Center did not meet the criteria for treatment as discontinued
operations.
Sale of Broad River
On December 27, 2012, we, through our indirect, wholly-owned subsidiary Calpine Power Company, completed the sale
of 100% of our ownership interest in each of the Broad River Entities for approximately $423 million. This transaction resulted
in the disposition of our Broad River power plant, an 847 MW natural gas-fired, peaking power plant located in Gaffney, South
Carolina, and includes a five year consulting agreement with the buyer. We recorded a pre-tax gain of approximately $215 million
in December 2012, which is included in (gain) on sale of assets, net on our Consolidated Statements of Operations. We expect to
use the sale proceeds for our capital allocation activities and for general corporate purposes. The sale of the Broad River Entities
did not meet the criteria for treatment as discontinued operations.
Sale of Blue Spruce and Rocky Mountain
On December 6, 2010, we, through our indirect, wholly-owned subsidiaries Riverside Energy Center, LLC and CDHI,
completed the sale of 100% of our ownership interests in Blue Spruce and Rocky Mountain for approximately $739 million, and
we recorded a pre-tax gain of approximately $209 million during the fourth quarter of 2010. The results of operations for Blue
Spruce and Rocky Mountain are reported as discontinued operations on our Consolidated Statement of Operations for the year
ended December 31, 2010.
124
Discontinued Operations
The table below presents the components of our discontinued operations for the period presented (in millions):
Operating revenues ...................................................................................................................................................
Gain on disposal of discontinued operations ............................................................................................................
Income from discontinued operations before taxes ..................................................................................................
Less: Income tax expense .........................................................................................................................................
Discontinued operations, net of tax ..........................................................................................................................
$
$
2010
92
209
43
59
193
Other Asset Sales
On December 8, 2010, we sold a 25% undivided interest in the assets of our Freestone power plant for approximately
$215 million in cash. We recorded a pre-tax gain of approximately $119 million in December 2010, which is included in (gain)
on sale of assets, net on our Consolidated Statements of Operations. We continue to operate Freestone after the sale.
4.
Property, Plant and Equipment, Net
As of December 31, 2012 and 2011, the components of property, plant and equipment, are stated at cost less accumulated
depreciation as follows (in millions):
Buildings, machinery and equipment.................................................. $
Geothermal properties.........................................................................
Other....................................................................................................
Less: Accumulated depreciation .........................................................
Land ....................................................................................................
Construction in progress .....................................................................
Property, plant and equipment, net...................................................... $
2012
2011
14,774
1,243
142
16,159
4,390
11,769
98
1,138
13,005
$
$
15,074
1,163
156
16,393
4,158
12,235
91
693
13,019
Depreciable Lives
3 – 47 Years
13 – 59 Years
3 – 47 Years
Total depreciation expense, including amortization of leased assets, recorded in income from operations and discontinued
operations for the years ended December 31, 2012, 2011 and 2010, was $557 million, $560 million and $568 million, respectively.
We have various debt instruments that are collateralized by our property, plant and equipment. See Note 6 for a detailed
discussion of such instruments.
Buildings, Machinery and Equipment
This component primarily includes power plants and related equipment. Included in buildings, machinery and equipment
are assets under capital leases. See Note 6 for further information regarding these assets under capital leases.
Geothermal Properties
This component primarily includes our Geysers Assets.
Other
This component primarily includes software and emission reduction credits that are power plant specific and not available
to be sold.
Capitalized Interest
The total amount of interest capitalized was $38 million, $24 million and $15 million for the years ended December 31,
2012, 2011 and 2010, respectively.
125
5.
Variable Interest Entities and Unconsolidated Investments
We consolidate all of our VIEs where we have determined that we are the primary beneficiary. There were no changes
to our determination of whether we are the primary beneficiary of our VIEs for the year ended December 31, 2012. We have the
following types of VIEs consolidated in our financial statements:
Subsidiaries with Project Debt — All of our subsidiaries with project debt not guaranteed by Calpine have PPAs that
provide financial support and are thus considered VIEs. We retain ownership and absorb the full risk of loss and potential for
reward once the project debt is paid in full. Actions by the lender to assume control of collateral can occur only under limited
circumstances such as upon the occurrence of an event of default, which we have determined to be unlikely. See Note 6 for further
information regarding our project debt and Note 2 for information regarding our restricted cash balances.
Subsidiaries with PPAs — Certain of our majority owned subsidiaries have PPAs that limit the risk and reward of our
ownership and thus constitute a VIE.
VIE with a Purchase Option — OMEC has an agreement that provides a third party a fixed price option to purchase power
plant assets exercisable in the year 2019 with an aggregate capacity of 608 MW. This purchase option limits the risk and reward
of our ownership and, thus, constitutes a VIE.
Consolidation of VIEs
We consolidate our VIEs where we determine that we have both the power to direct the activities of a VIE that most
significantly impact the VIE’s economic performance and the obligation to absorb losses or receive benefits from the VIE. We
have determined that we hold the obligation to absorb losses and receive benefits in all of our VIEs where we hold the majority
equity interest. Therefore, our determination of whether to consolidate is based upon which variable interest holder has the power
to direct the most significant activities of the VIE (the primary beneficiary). Our analysis includes consideration of the following
primary activities which we believe to have a significant impact on a power plant’s financial performance: operations and
maintenance, plant dispatch, and fuel strategy as well as our ability to control or influence contracting and overall plant strategy.
Our approach to determining which entity holds the powers and rights is based on powers held as of the balance sheet date.
Contractual terms that may change the powers held in future periods, such as a purchase or sale option, are not considered in our
analysis. Based on our analysis, we believe that we hold the power and rights to direct the most significant activities of all our
majority-owned VIEs.
Under our consolidation policy and under U.S. GAAP we also:
•
•
perform an ongoing reassessment each reporting period of whether we are the primary beneficiary of our VIEs; and
evaluate if an entity is a VIE and whether we are the primary beneficiary whenever any changes in facts and
circumstances occur such that the holders of the equity investment at risk, as a group, lose the power from voting
rights or similar rights of those investments to direct the activities of a VIE that most significantly impact the VIE’s
economic performance or when there are other changes in the powers held by individual variable interest holders.
Noncontrolling Interest — We own a 75% interest in Russell City Energy Company, LLC, one of our VIEs, which is also
25% owned by a third party. We fully consolidate this entity in our Consolidated Financial Statements and account for the third
party ownership interest as a noncontrolling interest.
VIE Disclosures
Our consolidated VIEs include natural gas-fired power plants with an aggregate capacity of 8,255 MW and 11,391 MW,
at December 31, 2012 and 2011, 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. In addition to amounts contractually
required, we provided support to these VIEs in the form of cash and other contributions of $20 million and $87 million for the
years ended December 31, 2012 and 2011, respectively. During the year ended December 31, 2010, we provided $540 million to
NDH, an indirect, wholly-owned subsidiary, to fund the Conectiv Acquisition, including $110 million to complete the construction
of the York Energy Center. Additionally, we provided support to our other VIEs in the form of cash and other contributions other
than amounts contractually required of $46 million during the year ended December 31, 2010.
U.S. GAAP requires separate disclosure on the face of our Consolidated Balance Sheets of the significant assets of a
consolidated VIE that can be used only to settle obligations of the consolidated VIE and the significant liabilities of a consolidated
126
VIE for which creditors (or beneficial interest holders) do not have recourse to the general credit of the primary beneficiary. In
determining which assets of our VIEs meet the separate disclosure criteria, we consider that this separate disclosure requirement
is met where Calpine Corporation is substantially limited or prohibited from access to assets (primarily cash and cash equivalents,
restricted cash and property, plant and equipment), and where our VIEs had project financing that prohibits the VIE from providing
guarantees on the debt of others. In determining which liabilities of our VIEs meet the separate disclosure criteria, we consider
that this separate disclosure requirement is met where there are agreements that prohibit the debt holders of the VIEs from recourse
to the general credit of Calpine Corporation and where the amounts were material to our financial statements.
Unconsolidated VIEs and Investments
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. We account
for these entities under the equity method of accounting and include our net equity interest in investments on our Consolidated
Balance Sheets. At December 31, 2012 and 2011, our equity method investments included on our Consolidated Balance Sheets
were comprised of the following (in millions):
Greenfield LP .....................................................................................
Whitby................................................................................................
Total investments .............................................................................
Ownership
Interest as of
December 31, 2012
50%
50%
$
$
2012
2011
69
12
81
$
$
72
8
80
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 Balance Sheets. At December 31, 2012 and 2011, equity method
investee debt was approximately $448 million and $462 million, respectively, and based on our pro rata share of each of the
investments, our share of such debt would be approximately $224 million and $231 million at December 31, 2012 and 2011,
respectively.
Our equity interest in the net income from Greenfield LP and Whitby for the years ended December 31, 2012, 2011 and
2010, are recorded in (income) from unconsolidated investments in power plants. The following table sets forth details of our
(income) from unconsolidated investments in power plants and distributions for the years indicated (in millions):
(Income) from Unconsolidated
Investments in Power Plants
Distributions
2012
2011
2010
2012
2011
2010
Greenfield LP ....................................... $
Whitby..................................................
Total ................................................... $
(17) $
(11)
(28) $
(12) $
(9)
(21) $
(8) $
(8)
(16) $
22
7
29
$
$
2
4
6
$
$
6
5
11
Greenfield LP — Greenfield LP is a limited partnership between certain subsidiaries of ours and of Mitsui & Co., Ltd.
and contains the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant located in Ontario, Canada
which is operated by a third party. We and Mitsui & Co., Ltd. each hold a 50% interest in Greenfield LP. Greenfield LP holds an
18-year term loan with an original principal amount of CAD $648 million. Borrowings under the project finance facility bear
interest at Canadian LIBOR plus 1.125% or Canadian prime rate plus 0.125%.
Whitby — Whitby is a limited partnership between certain subsidiaries of ours 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.
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 which achieved COD on May 3, 2010) 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.
127
Significant Unconsolidated Subsidiaries — Greenfield LP and Whitby met the criteria of significant unconsolidated
subsidiaries for the year ended December 31, 2012, based upon the relationship of our equity income from our investment in these
subsidiaries, when combined, to our consolidated net income before taxes. Aggregated summarized financial data for our
unconsolidated subsidiaries is set forth below (in millions):
Condensed Combined Balance Sheets
of Our Unconsolidated Subsidiaries
December 31, 2012 and 2011
2012
2011
Assets:
Cash and cash equivalents................................................................................................
Current assets ...................................................................................................................
Property, plant and equipment, net...................................................................................
Other assets ......................................................................................................................
Total assets................................................................................................................... $
Liabilities:
Current maturities of long-term debt................................................................................ $
Current liabilities..............................................................................................................
Long-term debt .................................................................................................................
Long-term derivative liabilities ........................................................................................
Total liabilities.............................................................................................................
Member's interest .............................................................................................................
Total liabilities and member's interest ....................................................................
$
$
64
30
648
4
742
25
36
423
84
568
178
746
Condensed Combined Statements of Operations
of Our Unconsolidated Subsidiaries
For the Years Ended December 31, 2012, 2011 and 2010
Revenues ................................................................................................... $
Operating expenses ...................................................................................
Income from operations..........................................................................
Interest expense, net of interest income ....................................................
Other (income) expense, net .....................................................................
Net income ......................................................................................... $
247
171
76
27
(2)
51
$
$
277
208
69
30
2
37
$
$
2012
2011
2010
76
37
656
3
769
24
47
438
85
594
178
1,295
228
183
45
27
—
18
128
6.
Debt
Our debt at December 31, 2012 and 2011, was as follows (in millions):
First Lien Notes(1) ............................................................................................................................... $
First Lien Term Loans(1)......................................................................................................................
Project financing, notes payable and other(1) ......................................................................................
CCFC Notes........................................................................................................................................
Capital lease obligations .....................................................................................................................
Total debt..........................................................................................................................................
Less: Current maturities......................................................................................................................
Debt, net of current portion .............................................................................................................. $
2012
2011
5,303
2,463
1,789
978
217
10,750
115
10,635
$
$
5,892
1,646
1,691
972
224
10,425
104
10,321
_____________
(1) During the fourth quarter of 2012, we redeemed 10% of the aggregate principal amount of our First Lien Notes and repaid
project debt with proceeds received from the issuance of our 2019 First Lien Term Loan.
Annual Debt Maturities
Contractual annual principal repayments or maturities of debt instruments as of December 31, 2012, are as follows (in
millions):
2013............................................................................................................................................................................ $
2014............................................................................................................................................................................
2015............................................................................................................................................................................
2016............................................................................................................................................................................
2017............................................................................................................................................................................
Thereafter ...................................................................................................................................................................
Total debt .................................................................................................................................................................
Less: Discount ............................................................................................................................................................
Total ......................................................................................................................................................................... $
115
188
153
1,162
1,597
7,580
10,795
45
10,750
First Lien Notes
Our First Lien Notes are summarized in the table below (in millions, except for interest rates):
Outstanding at December 31,
Weighted Average
Effective Interest Rates(1)
2012
2011
2012
2011
2017 First Lien Notes .......................................................................... $
2019 First Lien Notes ..........................................................................
2020 First Lien Notes ..........................................................................
2021 First Lien Notes ..........................................................................
2023 First Lien Notes ..........................................................................
1,080
$
360
983
1,800
1,080
Total First Lien Notes........................................................................ $
5,303
$
1,200
400
1,092
2,000
1,200
5,892
7.5%
7.5%
8.2
8.1
7.7
8.0
8.2
8.1
7.7
8.0
____________
(1) Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
Our First Lien Notes are secured equally and ratably with indebtedness incurred under our First Lien Term Loans and
Corporate Revolving Facility, subject to certain exceptions and permitted liens, on substantially all of our and certain of the
guarantors’ existing and future assets. Additionally, our First Lien Notes rank equally in right of payment with all of our and the
129
guarantors’ other existing and future senior indebtedness, and will be effectively subordinated in right of payment to all existing
and future liabilities of our subsidiaries that do not guarantee our First Lien Notes.
Subject to certain qualifications and exceptions, our First Lien Notes will, among other things, limit our ability and the
ability of the guarantors to:
•
•
•
•
•
incur or guarantee additional first lien indebtedness;
enter into certain types of commodity hedge agreements that can be secured by first lien collateral;
enter into sale and leaseback transactions;
create or incur liens; and
consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries on a
combined basis.
On October 9, 2012, we issued notice to the holders of our First Lien Notes of our intent to redeem 10% of the aggregate
principal amount of each series of our existing First Lien Notes. On November 7, 2012, we completed the redemption at a redemption
price of 103% of the principal amount redeemed, plus accrued and unpaid interest. This redemption was funded using a portion
of the proceeds received from the issuance of the 2019 First Lien Term Loan discussed further below.
First Lien Term Loans
Our First Lien Term Loans provide for senior secured term loan facilities and bear interest, at our option, at either (i) the
base rate, equal to the higher of the Federal Funds effective rate plus 0.5% per annum or the Prime Rate (as such terms are defined
in the First Lien Term Loans credit agreements), plus an applicable margin of 2.25%, or (ii) LIBOR plus 3.25% per annum subject
to a LIBOR floor of 1.25%. An aggregate amount equal to 0.25% of the aggregate principal amount of the First Lien Term Loans
will be payable at the end of each quarter with the remaining balance payable on the maturity date. The First Lien Term Loans are
subject to certain qualifications and exceptions, similar to our First Lien Notes. The 2018 First Lien Term Loans have a maturity
date of April 1, 2018.
On October 9, 2012, we entered into and borrowed $835 million under our 2019 First Lien Term Loan, which bears
interest at the same rate as our First Lien Term Loans (discussed above). We used the net proceeds received to redeem 10% of the
aggregate principal amount of each series of our existing First Lien Notes at a redemption price of 103% of the principal amount
redeemed and to repay project debt totaling $218 million, plus accrued and unpaid interest for each. The 2019 First Lien Term
Loan allows us to reduce our overall cost of debt by replacing a portion of our First Lien Notes with fixed interest rates ranging
from 7.25% to 8.0% with a corporate level term loan carrying a lower variable interest rate currently at 4.5% and to repay variable
rate project debt.
The 2019 First Lien Term Loan carries substantially the same terms as the 2018 First Lien Term Loans and matures on
October 9, 2019. The 2019 First Lien Term Loan also contains substantially similar covenants, qualifications, exceptions and
limitations as the 2018 First Lien Term Loans and First Lien Notes. We recorded debt extinguishment costs of approximately $18
million associated with the redemption premium, the write-off of unamortized deferred financing costs and debt premium and
discount during the fourth quarter of 2012.
Outstanding at December 31,
Weighted Average
Effective Interest Rates(1)
2012
2011
2012
2011
2018 First Lien Term Loans ................................................................ $
2019 First Lien Term Loan..................................................................
Total First Lien Term Loans............................................................. $
1,630
833
2,463
$
$
1,646
—
1,646
4.7%
4.7
4.7%
—
____________
(1) Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
130
Project Financing, Notes Payable and Other
The components of our project financing, notes payable and other are (in millions, except for interest rates):
Outstanding at
December 31,
2012
2011
Weighted Average
Effective Interest Rates(1)
2011
2012
Russell City Project Debt due 2023 ........................ $
Steamboat due 2017 ................................................
OMEC due 2019 .....................................................
Los Esteros Project Debt due 2023 .........................
Pasadena(2)...............................................................
Bethpage Energy Center 3 due 2020-2025(3) ..........
Gilroy note payable due 2014 .................................
Calpine BRSP due 2014(4).......................................
Other........................................................................
Total...................................................................... $
_____________
507
428
345
209
160
93
33
—
14
1,789
$
$
244
437
355
83
185
98
49
232
8
1,691
3.6%
6.8
6.8
3.5
8.9
7.0
10.8
—
—
4.1%
6.6
6.8
3.8
8.8
7.0
10.6
5.7
—
(1) Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount or
premium.
(2) Represents a sale-leaseback transaction that is accounted for as financing transaction under U.S. GAAP.
(3) Represents a weighted average of first and second lien loans for the weighted average effective interest rates.
(4) During the fourth quarter of 2012, we repaid the Calpine BRSP project debt with proceeds received from the issuance of
our 2019 First Lien Term Loan.
Our project financings are collateralized solely by the capital stock or partnership interests, physical assets, contracts
and/or cash flows attributable to the entities that own the power plants. The lenders’ recourse under these project financings is
limited to such collateral.
CCFC Notes
On May 19, 2009, our wholly-owned subsidiaries, CCFC and CCFC Finance, issued approximately $1.0 billion aggregate
principal amount of 8.0% CCFC Notes in a private placement. The CCFC Notes and the related guarantees are secured, subject
to certain exceptions and permitted liens, by all real and personal property of CCFC and CCFC’s material subsidiaries (including
the CCFC Guarantors), consisting primarily of six natural gas power plants as well as the equity interests in CCFC and the CCFC
Guarantors. The CCFC Notes are not guaranteed by Calpine Corporation and are without recourse to Calpine Corporation or any
of our other non-CCFC or CCFC Finance subsidiaries or assets; however, CCFC generates the majority of its cash flows from an
intercompany tolling agreement with CES and has various service agreements in place with other subsidiaries of Calpine
Corporation. The CCFC Notes mature on June 1, 2016 and the weighted average interest rates, which includes the amortization
of deferred financing costs and debt discount, was 8.9% for both 2012 and 2011.
131
Capital Lease Obligations
The following is a schedule by year of future minimum lease payments under capital leases and failed sale-leaseback
transactions together with the present value of the net minimum lease payments as of December 31, 2012 (in millions):
2013....................................................................................................................... $
2014.......................................................................................................................
2015.......................................................................................................................
2016.......................................................................................................................
2017.......................................................................................................................
Thereafter............................................................................................................
Total minimum lease payments .....................................................................
Less: Amount representing interest.......................................................................
Present value of net minimum lease payments .............................................. $
Sale-Leaseback
Transactions(1)
37
25
25
25
17
127
256
96
160
Capital Lease
42
$
43
38
41
38
161
363
146
217
$
$
$
Total
79
68
63
66
55
288
619
242
377
____________
(1) Amounts are accounted for as financing transactions under U.S. GAAP and are included in our project financing, notes
payable and other amounts above.
The primary types of property leased by us are power plants and related equipment. The leases generally provide for the
lessee to pay taxes, maintenance, insurance, and certain other operating costs of the leased property. The remaining lease terms
range up to 36 years (including lease renewal options). Some of the lease agreements contain customary restrictions on dividends
up to Calpine Corporation, additional debt and further encumbrances similar to those typically found in project financing
agreements. At December 31, 2012 and 2011, the asset balances for the leased assets totaled approximately $880 million and $879
million with accumulated amortization of $312 million and $318 million, respectively. See Note 15 for discussion of capital leases
guaranteed by Calpine Corporation.
Corporate Revolving Facility and Other Letters of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at December 31, 2012 and 2011 (in millions):
Corporate Revolving Facility ............................................................................................................. $
CDHI...................................................................................................................................................
Various project financing facilities.....................................................................................................
Total.................................................................................................................................................. $
2012
2011
243
253
130
626
$
$
440
193
130
763
The Corporate Revolving Facility represents our primary revolving facility. Borrowings under the Corporate Revolving
Facility bear interest, at our option, at either a base rate or LIBOR rate. Base rate borrowings shall be at the base rate, plus an
applicable margin ranging from 2.00% to 2.25% as provided in the Corporate Revolving Facility credit agreement. Base rate is
defined as the higher of (i) the Federal Funds Effective Rate, as published by the Federal Reserve Bank of New York, plus 0.50%
and (ii) the rate the administrative agent announces from time to time as its prime per annum rate. LIBOR rate borrowings shall
be at the British Bankers’ Association Interest Settlement Rates for the interest period as selected by us as a one, two, three, six
or, if agreed by all relevant lenders, nine or twelve month interest period, plus an applicable margin ranging from 3.00% to 3.25%.
Interest payments are due on the last business day of each calendar quarter for base rate loans and the earlier of (i) the last day of
the interest period selected or (ii) each day that is three months (or a whole multiple thereof) after the first day for the interest
period selected for LIBOR rate loans. Letter of credit fees for issuances of letters of credit include fronting fees equal to that
percentage per annum as may be separately agreed upon between us and the issuing lenders and a participation fee for the lenders
equal to the applicable interest margin for LIBOR rate borrowings. Drawings under letters of credit shall be repaid within two
business days or be converted into borrowings as provided in the Corporate Revolving Facility credit agreement. We incur an
unused commitment fee ranging from 0.50% to 0.75% on the unused amount of commitments under the Corporate Revolving
Facility.
132
The Corporate Revolving Facility does not contain any requirements for mandatory prepayments, except in the case of
certain designated asset sales in excess of $3 billion in the aggregate. However, we may voluntarily repay, in whole or in part, the
Corporate Revolving Facility, together with any accrued but unpaid interest, with prior notice and without premium or penalty.
Amounts repaid may be reborrowed, and we may also voluntarily reduce the commitments under the Corporate Revolving Facility
without premium or penalty. The Corporate Revolving Facility matures on December 10, 2015.
The Corporate Revolving Facility is guaranteed and secured by each of our current domestic subsidiaries that was a
guarantor under the First Lien Credit Facility and will also be additionally guaranteed by our future domestic subsidiaries that are
required to provide such a guarantee in accordance with the terms of the Corporate Revolving Facility. The Corporate Revolving
Facility ranks equally in right of payment with all of our and the guarantors’ other existing and future senior indebtedness and will
be effectively subordinated in right of payment to all existing and future liabilities of our subsidiaries that do not guarantee the
Corporate Revolving Facility. The Corporate Revolving Facility also requires compliance with financial covenants that include a
minimum cash interest coverage ratio and a maximum net leverage ratio.
CDHI
We also have a letter of credit facility related to CDHI. On January 10, 2012, we increased the CDHI letter of credit
facility to $300 million and extended the maturity date to January 2, 2016. As a result of the completion of the sale of Riverside
Energy Center, LLC, a wholly-owned subsidiary of CDHI, on December 31, 2012, we are required to cash collateralize letters of
credit issued in excess of $225 million until replacement collateral is contributed to the CDHI collateral package which we are in
the process of arranging. At December 31, 2012, we had $28 million of cash collateral posted in support of outstanding letters of
credit under our CDHI letter of credit facility. We do not believe that this change will have a material impact on our liquidity.
Fair Value of Debt
We record our debt instruments based on contractual terms, net of any applicable premium or discount. We did not elect
to apply the alternative U.S. GAAP provisions of the fair value option for recording financial assets and financial liabilities. The
following table details the fair values and carrying values of our debt instruments at December 31, 2012 and 2011 (in millions):
2012
2011
Fair Value
Carrying
Value
Fair Value
Carrying
Value
First Lien Notes ................................................................................... $
First Lien Term Loans .........................................................................
Project financing, notes payable and other(1).......................................
CCFC Notes.........................................................................................
Total................................................................................................... $
5,863
2,489
1,599
1,075
11,026
$
$
5,303
2,463
1,629
978
10,373
$
$
6,219
1,615
1,467
1,070
10,371
$
$
5,892
1,646
1,504
972
10,014
____________
(1)
Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.
On January 1, 2012, we adopted Accounting Standards Update 2011-04 “Fair Value Measurement” which requires the
categorization by level of the fair value hierarchy for items not measured at fair value on our Consolidated Balance Sheets but for
which fair value is required to be disclosed. We measure the fair value of our First Lien Notes, First Lien Term Loans and CCFC
Notes 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.
7.
Assets and Liabilities with Recurring Fair Value Measurements
Cash Equivalents — Highly liquid investments which meet the definition of cash equivalents, primarily investments in
money market accounts, are included in both our cash and cash equivalents and our restricted cash on our Consolidated 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 Held by Us Posted by Our Counterparties — Margin deposits and margin deposits
held by us posted by our counterparties represent cash collateral paid between our counterparties and us to support our commodity
133
contracts. Our margin deposits and margin deposits held by us posted 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.
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 natural gas swaps, futures and options traded on the
NYMEX.
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 primarily 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 or 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. In cases where there is no corroborating market information available to
support significant model inputs, we initially use the transaction price as the best estimate of fair value. 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.
134
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
December 31, 2012 and 2011, by level within the fair value hierarchy:
Assets and Liabilities with Recurring Fair Value Measures
as of December 31, 2012
Level 1
Level 2
Level 3
Total
(in millions)
1,502
$
— $
— $
Assets:
Cash equivalents(1) ............................................................................ $
Margin deposits.................................................................................
Commodity instruments:...................................................................
Commodity exchange traded futures and swaps contracts...........
Commodity forward contracts(2)...................................................
Interest rate swaps .............................................................................
Total assets ................................................................................... $
Liabilities:
Margin deposits held by us posted by our counterparties ................. $
Commodity instruments:...................................................................
Commodity exchange traded futures and swaps contracts...........
Commodity forward contracts(2)...................................................
Interest rate swaps .............................................................................
196
385
—
—
2,083
11
424
—
—
$
$
Total liabilities.............................................................................. $
435
$
—
—
24
4
28
$
—
—
24
—
24
$
1,502
196
385
48
4
2,135
— $
— $
11
—
18
200
218
$
—
8
—
8
$
424
26
200
661
Assets and Liabilities with Recurring Fair Value Measures
as of December 31, 2011
Level 1
Level 2
Level 3
Total
(in millions)
1,415
$
— $
— $
Assets:
Cash equivalents(1) ............................................................................ $
Margin deposits.................................................................................
Commodity instruments:...................................................................
Commodity exchange traded futures and swaps contracts...........
Commodity forward contracts(2)...................................................
Interest rate swaps .............................................................................
140
1,043
—
—
Total assets ................................................................................... $
2,598
Liabilities:
Margin deposits held by us posted by our counterparties ................. $
Commodity instruments:...................................................................
Commodity exchange traded futures and swaps contracts...........
Commodity forward contracts(2)...................................................
Interest rate swaps .............................................................................
34
899
—
—
$
$
Total liabilities.............................................................................. $
933
$
___________
—
—
74
10
84
$
—
—
37
—
37
1,415
140
1,043
111
10
$
2,719
— $
— $
34
—
184
320
504
$
—
20
—
20
899
204
320
$
1,457
(1) As of December 31, 2012 and 2011, we had cash equivalents of $1,274 million and $1,249 million included in cash and
cash equivalents and $228 million and $166 million included in restricted cash, respectively.
135
(2)
Includes OTC swaps and options.
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 years ended December 31, 2012, 2011 and 2010 (in millions):
Balance, beginning of period ...................................................................................... $
17
$
30
$
2012
2011
2010
Realized and unrealized gains (losses):
Included in net income:
Included in operating revenues(1) ....................................................................
Included in fuel and purchased energy expense(2)...........................................
Included in OCI ........................................................................................................
Purchases, issuances and settlements:
Purchases..............................................................................................................
Issuances ..............................................................................................................
Settlements...........................................................................................................
Transfers in and/or out of level 3(3):
Transfers into level 3(4) .....................................................................................
Transfers out of level 3(5) ..................................................................................
Balance, end of period ................................................................................................ $
Change in unrealized gains relating to instruments still held at end of period ........... $
8
—
—
3
(1)
(11)
—
—
16
8
$
$
5
—
2
—
—
(18)
(2)
—
17
5
$
$
38
7
—
2
—
—
(20)
—
3
30
7
___________
(1)
(2)
For power contracts and Heat Rate swaps and options, included on our Consolidated Statements of Operations.
For natural gas contracts, swaps and options, included on our Consolidated Statements of Operations.
(3) We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no significant transfers
into/out of level 1 during the years ended December 31, 2012, 2011 and 2010.
(4)
There were no significant transfers into level 3 for the years ended December 31, 2012 and 2010. We had $2 million in
losses transferred out of level 2 into level 3 for the year ended December 31, 2011 due to changes in market liquidity in
various power and natural gas markets.
(5) We had no significant transfers out of level 3 for the years ended December 31, 2012 and 2011. There were $3 million in
losses transferred out of level 3 into level 2 for the year ended December 31, 2010 due to changes in market liquidity in
various power markets.
At December 31, 2012, the derivative instruments classified as level 3 primarily included a longer-term OTC traded
commodity contract extending through 2014. This contract is classified as level 3 because the contract terms exceed the period
for which liquid market rate information is available. As such, the fair value of the contract incorporates extrapolation assumptions
made in the determination of the market price for future delivery periods in which applicable commodity prices were either not
observable or lacked corroborative market data. The fair value of the net derivative position classified as level 3 is predominantly
driven by market commodity prices; however, given the nature of our net derivative position, we do not believe that a significant
change in market commodity prices would have a material impact on our level 3 net fair value. The following table presents
quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at December 31,
2012:
Quantitative Information about Level 3 Fair Value Measurements
December 31, 2012
Significant Unobservable
Valuation Technique
Input
Range
Fair Value, Net Asset
(Liability)
(in millions)
Physical Power ............
$
11 Discounted cash flow Market price (per MWh)
$23.75 — $53.82/MWh
136
8.
Derivative Instruments
Types of Derivative Instruments and Volumetric Information
Commodity Instruments — We are exposed to changes in prices for the purchase and sale of power, natural gas 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.
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 December 31, 2012, the maximum length of time over which we were hedging using interest rate derivative
instruments designated as cash flow hedges was 11 years.
As of December 31, 2012 and 2011, the net forward notional buy (sell) position of our outstanding commodity and
interest rate swap contracts that did not qualify under the normal purchase normal sale exemption were as follows (in millions):
Derivative Instruments
Power (MWh)................................................................................................
Natural gas (MMBtu) ....................................................................................
Interest rate swaps(1) ......................................................................................
$
____________
Notional Amounts
2012
2011
(16)
66
1,602
$
(21)
(200)
5,639
(1) Approximately $4.1 billion at December 31, 2011 was related to hedges of our First Lien Credit Facility’s variable rate
debt that was converted to fixed rate debt. On March 26, 2012, we terminated the interest rate swaps formerly hedging our
First Lien Credit Facility.
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 December 31, 2012, was $5 million for which we have posted collateral of $1 million by posting
margin deposits or granting additional first priority liens on the assets currently subject to first priority liens under our First Lien
Notes, First Lien Term Loans and Corporate Revolving Facility. However, if our credit rating were downgraded by one notch from
its current level, we estimate that additional collateral of $1 million 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
Statements of Operations until the period of delivery. In order to simplify our reporting, we elected to discontinue the application
of hedge accounting treatment during the first quarter of 2012 for all commodity derivatives, including the remaining commodity
derivatives previously accounted for as cash flow hedges. Accordingly, prospective changes in fair value from the date of this
election are reflected in unrealized mark-to-market gain/loss on our Consolidated Statements of Operations and could create more
volatility in our earnings. Revenues and fuel costs 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. Although we have discontinued
the application of hedge accounting treatment for our commodity derivative instruments, prior to this change and for our interest
rate swaps, 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 or investing activities (in the case of settlements for our interest rate swaps formerly hedging
our First Lien Credit Facility term loans) on our Consolidated Statements of Cash Flows unless they contain an other-than-
insignificant financing element in which case their cash flows are classified within financing activities.
137
Cash Flow Hedges — We report the effective portion of the unrealized gain or loss on a derivative instrument 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 commodity
hedging instruments are recognized currently in earnings and are separately stated on our Consolidated Statements of Operations
in unrealized mark-to-market gain/loss as a component of operating revenues (for power contracts and swaps) and fuel and
purchased energy expense (for natural gas contracts and swaps). Gains and losses due to ineffectiveness on interest rate hedging
instruments are recognized currently in earnings as a component of interest expense (for interest rate swaps except as discussed
below). 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 and interest rate 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 Statements of Operations in unrealized mark-to-market gain/loss as a component of
operating revenues (for power contracts and Heat Rate swaps and options) and fuel and purchased energy expense (for natural
gas 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 (for interest rate swaps except as discussed below).
Interest Rate Swaps Formerly Hedging our First Lien Credit Facility and Other Project Debt — During 2010, we repaid
approximately $3.5 billion of our First Lien Credit Facility term loans, which had approximately $3.3 billion notional amount of
interest rate swaps hedging the scheduled variable interest payments, and in January 2011, we repaid the remaining approximately
$1.2 billion of First Lien Credit Facility term loans which had approximately $1.0 billion notional amount of interest rate swaps
hedging the scheduled variable interest payments. With the repayment of the remaining First Lien Credit Facility term loans,
unrealized losses of approximately $91 million in AOCI related to the interest rate swaps formerly hedging the First Lien Credit
Facility, were reclassified out of AOCI and into earnings as an additional loss on interest rate derivatives during 2011. In addition,
we reclassified approximately $17 million in unrealized losses in AOCI to loss on interest rate derivatives during 2011 resulting
from the repayment of project debt in 2011. During 2010, we reclassified approximately $206 million out of AOCI and into earnings
as additional loss on interest rate derivatives related to interest rate swaps formerly hedging our First Lien Credit Facility term
loans. We have presented the reclassification of unrealized losses from AOCI into earnings and the changes in fair value and
settlements subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility described
above separate from interest expense as loss on interest rate derivatives on our Consolidated Statements of Operations. On March
26, 2012, we terminated the legacy interest rate swaps formerly hedging our First Lien Credit Facility and paid the fair value of
the swaps totaling approximately $156 million. Approximately $14 million of the settlement amount was recorded as a component
of loss on interest rate derivatives on our Consolidated Statement of Operations for the year ended December 31, 2012, and
approximately $142 million reflected the realization of losses recorded in prior periods.
138
Derivatives Included on Our Consolidated Balance Sheet
The following tables present the fair values of our net derivative instruments recorded on our Consolidated Balance
Sheets by location and hedge type at December 31, 2012 and 2011 (in millions):
December 31, 2012
Interest Rate
Swaps
Commodity
Instruments
Total
Derivative
Instruments
Balance Sheet Presentation
Current derivative assets ............................................................................................. $
Long-term derivative assets ........................................................................................
Total derivative assets............................................................................................... $
Current derivative liabilities........................................................................................ $
Long-term derivative liabilities...................................................................................
Total derivative liabilities ......................................................................................... $
Net derivative assets (liabilities).......................................................................... $
— $
4
4
$
$
40
160
200
$
(196) $
339
94
433
$
$
$
317
133
450
$
(17) $
339
98
437
357
293
650
(213)
December 31, 2011
Interest Rate
Swaps
Commodity
Instruments
Total
Derivative
Instruments
Balance Sheet Presentation
Current derivative assets ............................................................................................. $
Long-term derivative assets ........................................................................................
Total derivative assets............................................................................................... $
Current derivative liabilities........................................................................................ $
Long-term derivative liabilities...................................................................................
Total derivative liabilities ......................................................................................... $
Net derivative assets (liabilities).......................................................................... $
— $
10
10
$
$
166
154
320
$
(310) $
1,051
103
1,154
978
125
1,103
51
$
$
$
$
$
1,051
113
1,164
1,144
279
1,423
(259)
December 31, 2012
December 31, 2011
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(1):
Interest rate swaps ............................................................................. $
Commodity instruments ....................................................................
Total derivatives designated as cash flow hedging instruments... $
Derivatives not designated as hedging instruments:
Interest rate swaps ............................................................................. $
Commodity instruments ....................................................................
Total derivatives not designated as hedging instruments............. $
Total derivatives ...................................................................... $
____________
4
—
4
$
$
— $
433
433
437
$
$
184
—
184
16
450
466
650
$
$
$
$
$
10
51
61
$
$
— $
1,103
1,103
1,164
$
$
149
18
167
171
1,085
1,256
1,423
(1)
Includes accumulated fair value of derivative instruments as of the date hedge accounting was discontinued, net of amortized
fair value for settlement periods which have transpired.
139
Derivatives Included on Our Consolidated 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 in our earnings.
The following tables detail the components of our total mark-to-market activity for both the net realized gain (loss) and
the net unrealized gain (loss) recognized from our derivative instruments in earnings and where these components were recorded
on our Consolidated Statements of Operations for the years ended December 31, 2012, 2011 and 2010 (in millions):
Realized gain (loss)(1)
Interest rate swaps.......................................................................................... $
Commodity derivative instruments................................................................
Total realized gain (loss)........................................................................... $
Unrealized gain (loss)(2)
Interest rate swaps.......................................................................................... $
Commodity derivative instruments................................................................
Total unrealized gain (loss)....................................................................... $
Total mark-to-market activity, net........................................................ $
___________
2012
2011
2010
(157) $
387
230
$
154
(82)
72
302
$
$
$
(193) $
143
(50) $
$
55
(25)
30
$
(20) $
(31)
114
83
(199)
143
(56)
27
(1) Does not include the realized value associated with derivative instruments that settle through physical delivery.
(2)
In addition to changes in market value on derivatives not designated as hedges, changes in unrealized gain (loss) also
includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into earnings, hedge
ineffectiveness and adjustments to reflect changes in credit default risk exposure.
Realized and unrealized gain (loss)
Derivatives contracts included in operating revenues...................................... $
Derivatives contracts included in fuel and purchased energy expense ............
Interest rate swaps included in interest expense...............................................
Loss on interest rate derivatives .......................................................................
Total mark-to-market activity, net............................................................... $
2012
2011
2010
187
118
11
(14)
302
$
$
(20) $
138
7
(145)
(20) $
(19)
276
(7)
(223)
27
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 years ended December 31, 2012 and 2011 (in millions):
Gains (Loss) Recognized in
OCI (Effective Portion)
Gain (Loss) Reclassified from
AOCI into Income (Effective
Portion)(1)
Gain (Loss) Reclassified from
AOCI into Income (Ineffective
Portion)
2012
2011
2012
2011
2012
2011
Interest rate swaps.......................... $
Commodity derivative instruments
Total............................................. $
(43) $
(38)
(81) $
(23) $
(71)
(94) $
(32) (2) $
52 (3)
20
$
(138) (2) $
163 (3)
25 $
— $
2
2
$
(1)
(2)
(3)
____________
(1) Cumulative cash flow hedge losses, net of tax, remaining in AOCI were $242 million and $172 million at December 31,
2012 and 2011, respectively.
(2) Reclassification of losses from OCI to earnings consisted of $32 million from the reclassification of interest rate contracts
due to settlement for each of the years ended December 31, 2012 and 2011, $15 million in losses from terminated interest
rate contracts due to the repayment of project debt in 2011, and $91 million in losses from existing interest rate contracts
140
reclassified from OCI into earnings due to the refinancing of variable rate First Lien Credit Facility term loans for the year
ended December 31, 2011.
(3)
Included in Commodity revenue and Commodity expense on our Consolidated Statements of Operations.
As a result of our election to discontinue hedge accounting treatment for our commodity derivatives accounted for as
cash flow hedges, the fair value of our commodity derivative instruments that previously resided in AOCI on the de-designation
date was reclassified to earnings during 2012 as the related hedged transactions affected earnings. Thus, there is no fair value
amounts related to commodity derivatives remaining in AOCI at December 31, 2012. We estimate that pre-tax net losses of $41
million (comprised of amounts related to interest rate swaps) would be reclassified from AOCI into earnings during the next 12
months as the hedged transactions settle; however, the actual amounts that will be reclassified will likely vary based on changes
in interest rates. Therefore, we are unable to predict what the actual reclassification from AOCI into earnings (positive or negative)
will be for the next 12 months.
9.
Use of Collateral
We use margin deposits, prepayments and letters of credit as credit support with and from our counterparties for commodity
procurement and risk management activities. In addition, we have granted additional first priority liens on the assets currently
subject to first priority liens under various debt agreements as collateral under certain of our power and natural gas agreements
and certain of our interest rate swap agreements 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
December 31, 2012 and 2011 (in millions):
Margin deposits(1) ............................................................................................................................... $
Natural gas and power prepayments...................................................................................................
Total margin deposits and natural gas and power prepayments with our counterparties(2) ............ $
Letters of credit issued........................................................................................................................ $
First priority liens under power and natural gas agreements..............................................................
First priority liens under interest rate swap agreements .....................................................................
Total letters of credit and first priority liens with our counterparties ............................................ $
Margin deposits held by us posted by our counterparties(1)(3)............................................................. $
Letters of credit posted with us by our counterparties........................................................................
Total margin deposits and letters of credit posted with us by our counterparties.......................... $
2012
2011
196
35
231
484
14
206
704
11
1
12
$
$
$
$
$
$
140
42
182
581
1
318
900
34
—
34
___________
(1) Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated 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.
(2) At December 31, 2012 and 2011, $211 million and $162 million, respectively, were included in margin deposits and other
prepaid expense and $20 million and $20 million, respectively, were included in other assets on our Consolidated Balance
Sheets.
(3)
Included in other current liabilities on our Consolidated 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.
141
10.
Income Taxes
Income Tax Expense (Benefit)
The jurisdictional components of income (loss) from continuing operations before income tax expense (benefit),
attributable to Calpine, for the years ended December 31, 2012, 2011 and 2010, are as follows (in millions):
U.S............................................................................................................................... $
International ................................................................................................................
Total.......................................................................................................................... $
2012
2011
2010
194
24
218
$
$
(232) $
20
(212) $
(226)
(4)
(230)
The components of income tax expense (benefit) from continuing operations for the years ended December 31, 2012,
2011 and 2010, consisted of the following (in millions):
2012
2011
2010
Current:
Federal ................................................................................................................... $
State .......................................................................................................................
Foreign...................................................................................................................
Total current......................................................................................................
Deferred:
Federal ...................................................................................................................
State .......................................................................................................................
Foreign...................................................................................................................
Total deferred....................................................................................................
Total income tax expense (benefit).............................................................. $
(12) $
16
14
18
11
(5)
(5)
1
19
$
(16) $
12
3
(1)
(33)
9
3
(21)
(22) $
(1)
10
3
12
(70)
—
(10)
(80)
(68) (1)
_________
(1)
Includes approximately $13 million in intraperiod tax expense related to a prior period with an offsetting benefit in OCI.
142
For the years ended December 31, 2012, 2011 and 2010, our income tax rates did not bear a customary relationship to
statutory income tax rates, primarily as a result of the impact of our valuation allowance, state income taxes and changes in
unrecognized tax benefits. A reconciliation of the federal statutory rate of 35% to our effective rate from continuing operations
for the years ended December 31, 2012, 2011 and 2010, is as follows:
Federal statutory tax expense (benefit) rate ................................................................
State tax expense, net of federal benefit ...................................................................
Depletion in excess of basis......................................................................................
Preferred interest expense.........................................................................................
Federal refunds .........................................................................................................
Valuation allowances against future tax benefits......................................................
Valuation allowances related to reconsolidation of CCFC.......................................
Valuation allowances related to foreign taxes ..........................................................
Foreign taxes.............................................................................................................
Non-deductible reorganization items........................................................................
Intraperiod allocation................................................................................................
Bankruptcy settlement ..............................................................................................
Change in unrecognized tax benefits........................................................................
Permanent differences and other items.....................................................................
Effective income tax expense (benefit) rate................................................................
Deferred Tax Assets and Liabilities
2012
35.0%
3.2
(0.2)
2.0
(4.7)
(32.3)
—
(8.2)
3.7
0.1
4.6
—
5.1
0.4
8.7%
2011
(35.0)%
6.5
—
0.4
—
56.7
(36.0)
—
(0.9)
0.5
19.9
(15.7)
(6.6)
(0.2)
(10.4)%
2010
(35.0)%
2.8
(1.3)
0.5
—
33.6
—
—
9.9
0.3
(40.1)
—
0.6
(0.9)
(29.6)%
The components of the deferred income taxes as of December 31, 2012 and 2011, are as follows (in millions):
Deferred tax assets:
NOL and credit carryforwards.......................................................................................................... $
Taxes related to risk management activities and derivatives ...........................................................
Reorganization items and impairments ............................................................................................
Foreign capital losses .......................................................................................................................
Other differences ..............................................................................................................................
Deferred tax assets before valuation allowance ..........................................................................
Valuation allowance .........................................................................................................................
Total deferred tax assets ..............................................................................................................
Deferred tax liabilities: property, plant and equipment ......................................................................
Net deferred tax asset ..................................................................................................................
Less: Current portion deferred tax liability ........................................................................................
Less: Non-current deferred tax asset ..................................................................................................
Deferred income tax liability, non-current .................................................................................. $
2012
2011
$
3,073
90
315
25
60
3,563
(2,222)
1,341
(1,316)
25
(3)
28
— $
3,290
58
318
24
26
3,716
(2,336)
1,380
(1,364)
16
(2)
18
—
Consolidation of CCFC and Calpine Tax Reporting Groups — For federal income tax reporting purposes, our historical
tax reporting group was comprised primarily of two separate groups, CCFC and its subsidiaries, which we referred to as the CCFC
group, and Calpine Corporation and its subsidiaries other than CCFC, which we referred to as the Calpine group. During the first
quarter of 2011, we elected to consolidate our CCFC and Calpine groups for federal income tax reporting purposes and Calpine
filed a consolidated federal income tax return for the year ended December 31, 2011 that included the CCFC group. As a result
of the consolidation, the CCFC group deferred tax liabilities will be eligible to offset existing Calpine group NOLs that were
reserved by a valuation allowance. Accordingly, we recorded a one-time federal deferred income tax benefit of approximately $76
million during the first quarter of 2011 to reduce our valuation allowance. For the year ended December 31, 2010, the CCFC group
was deconsolidated from the Calpine group for federal income tax reporting purposes.
143
Intraperiod Tax Allocation — In accordance with U.S. GAAP, intraperiod tax allocation provisions require allocation of
a tax expense (benefit) to continuing operations due to current OCI gains (losses) and income from discontinued operations with
a partial offsetting amount recognized in OCI and discontinued operations. The following table details the effects of our intraperiod
tax allocations for the years ended December 31, 2012, 2011 and 2010 (in millions).
Intraperiod tax allocation expense (benefit) included in continuing operations ......... $
Intraperiod tax allocation expense included in discountinued operations .................. $
Intraperiod tax allocation expense (benefit) included in OCI..................................... $
9
$
— $
(9) $
42
$
— $
(45) $
(86)
59
27
2012
2011
2010
NOL Carryforwards — Our NOL carryforwards consist primarily of federal NOL carryforwards of approximately $7.3
billion, which expire between 2023 and 2031, and NOL carryforwards in 33 states and the District of Columbia totaling
approximately $4.0 billion, which expire between 2013 and 2031, substantially all of which are offset with a full valuation
allowance. We also have approximately $1.0 billion in foreign NOLs, substantially all of which are offset with a full valuation
allowance. The NOL carryforwards available are subject to limitations on their annual usage. Under federal and applicable state
income tax laws, a corporation is generally permitted to deduct from taxable income in any year NOLs carried forward from prior
years subject to certain time limitations as prescribed by the taxing authorities. Under federal income tax law, our NOL carryforwards
can be utilized to reduce future taxable income subject to certain limitations, including if we were to undergo an ownership change
as defined by Section 382 of the IRC. We experienced an ownership change on the Effective Date as a result of the cancellation
of our old common stock and the distribution of our new common stock pursuant to our Plan of Reorganization. However, this
ownership change and the resulting annual limitations are not expected to result in the expiration of our NOL carryforwards if we
are able to generate sufficient future taxable income within the carryforward periods. At December 31, 2012, approximately $2.4
billion of our $7.3 billion federal NOLs are not subject to annual Section 382 limitations. When considering our cumulative annual
Section 382 limitations, in addition to our post-Effective Date NOLs that are not limited, our total unrestricted NOLs are
approximately $7.1 billion. If a subsequent ownership change were to occur as a result of future transactions in our common stock,
accompanied by a significant reduction in our market value immediately prior to the ownership change, our ability to utilize the
NOL carryforwards may be significantly limited.
Deferred tax assets relating to tax benefits of employee stock-based compensation do not reflect stock options exercised
and restricted stock that vested in 2012. Some stock option exercises and restricted stock vestings result in tax deductions in excess
of previously recorded deferred tax benefits based on the equity award value at the grant date. Although these additional tax
benefits or “windfalls” are reflected in net operating tax carryforwards pursuant to accounting for stock-based compensation under
U.S. GAAP, the additional tax benefit associated with the windfall is not recognized until the deduction reduces taxes payable,
which will not occur for Calpine until a future period. Accordingly, since the tax benefit does not reduce our current taxes payable
in 2012 due to NOL carryforwards, these “windfall” tax benefits are not reflected in our NOL in deferred tax assets for 2012.
Windfalls included in NOL carryforwards, but not reflected in deferred tax assets as of December 31, 2012 were $10 million.
Under state income tax laws, our NOL carryforwards can be utilized to reduce future taxable income subject to certain
limitations, including if we were to undergo an ownership change as defined by Section 382 of the IRC. During 2011, we analyzed
the effect of our change in ownership on the Effective Date for each of our significant states to determine the amount of our NOL
limitation. The analysis determined that $640 million of our state NOLs are expected to expire unutilized as a result of statutory
limitations on the use of some of our pre-emergence date NOLs as of the Effective Date or the cessation of business operations
in various tax jurisdictions. We reduced our deferred tax asset for state NOLs that we are unable to utilize and made an equal
reduction in our valuation allowance in 2011. The result did not have an impact on our income tax expense in 2011. We estimate
that approximately $117 million of our state NOLs expired unutilized during 2012 as a result of statutory state limitations relating
to the time period NOLs can be carried forward, and accordingly, we reduced our deferred tax asset and made an equal reduction
in our valuation allowance. The reduction did not have an impact to our income tax expense in 2012. We will likely make future
annual adjustments to our state NOLs that have expired or are limited under Section 382 of the IRC.
In 2011, we had certain intercompany accounts payable/receivable balances that were eliminated as part of the final steps
of our emergence from bankruptcy. There was no effect to our federal NOLs, however, there was a reduction in our state NOLs
of $44 million which was partially offset by a reduction in current state taxable income of $24 million. The resulting net reduction
to our state NOLs was offset by an equal reduction in our valuation allowance. The reduction did not have an impact on our income
tax expense in 2011.
As a result of the settlement of certain bankruptcy claims and the final distribution to the holders of allowed unsecured
claims in accordance with our Plan of Reorganization in 2011, we recognized approximately $66 million and $39 million for
144
federal and state income tax purposes, respectively, in cancellation of debt income related to this distribution for federal income
tax reporting in 2011.
Income Tax Audits — We remain subject to various audits and reviews by taxing authorities; however, we do not expect
these 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. Due to significant NOLs, any adjustment of state returns or
federal returns would likely result in a reduction of deferred tax assets rather than a cash payment of income taxes.
Canadian Tax Audits — In September 2009, we received notice from the Canadian Revenue Authority, or CRA, of their
intent to conduct a limited scope income tax audit on four of our Canadian subsidiaries for the tax years 2005 through 2008. The
CRA concluded that there were no adjustments on two of the subsidiaries, but further review was required on the remaining two
subsidiaries. On April 23, 2012, the remaining two subsidiaries received proposed adjustments from the CRA regarding our transfer
pricing positions. On June 21, 2012, we met with the CRA to discuss their proposed adjustments and provided clarification where
we believed it was needed. In July 2012, we received additional questions from the CRA as a result of our meeting, and we
responded to their request in September and October 2012. In December 2012, we received and responded to additional questions
from the CRA. In January 2013, we received an adjusted reassessment on one of the two transfer pricing issues that we are disputing
with the CRA and are currently evaluating the merits of the adjusted reassessment. If accepted, any adjustments to our transfer
pricing would increase taxable income and would be offset entirely by existing NOL's to which a valuation allowance has been
applied. Any interest assessments resulting from acceptance of the CRA offer would be immaterial.
We continue to evaluate the remaining proposed adjustments on our other Canadian subsidiary; however, based on our
current analysis which is supported by our tax advisors, we believe that our transfer pricing positions and policies are appropriate,
and we intend to challenge the CRA’s proposed adjustments. If we are unsuccessful in our challenge, any adjustment to Canadian
taxable income would first be offset against the existing NOLs that are available; however, we do not believe any reassessment
resulting in an adjustment to taxable income which is greater than our existing NOLs, or including interest or penalties which
cannot be offset by existing NOLs, would have a material adverse effect on our financial condition, results of operations or cash
flows.
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, since our emergence
from Chapter 11, we are able to consider available tax planning strategies.
As of December 31, 2012, we have provided a valuation allowance of approximately $2.2 billion on certain federal, state
and foreign tax jurisdiction deferred tax assets to reduce the amount of these assets to the extent necessary to result in an amount
that is more likely than not to be realized. The net change in our valuation allowance was a decrease of $114 million, $50 million
and $186 million for the years ended December 31, 2012, 2011 and 2010, respectively; all primarily related to changes in our
estimates of our ability to utilize our NOL carryforwards.
Unrecognized Tax Benefits
At December 31, 2012, we had unrecognized tax benefits of $92 million. If recognized, $36 million of our unrecognized
tax benefits could impact the annual effective tax rate and $56 million, related to deferred tax assets, could be offset against the
recorded valuation allowance resulting in no impact to our effective tax rate. We also had accrued interest and penalties of $24
million for income tax matters at December 31, 2012. We recognize interest and penalties related to unrecognized tax benefits in
income tax expense (benefit) on our Consolidated Statements of Operations. We believe that it is reasonably possible that a decrease
within the range of approximately nil and $28 million in unrecognized tax benefits could occur within the next 12 months primarily
related to state and foreign tax issues.
145
A reconciliation of the beginning and ending amounts of our unrecognized tax benefits for the years ended December 31,
2012, 2011 and 2010, is as follows (in millions):
Balance, beginning of period ...................................................................................... $
Increases related to prior year tax positions .............................................................
Decreases related to prior year tax positions ............................................................
Decrease related to lapse of statute of limitations ....................................................
Balance, end of period ................................................................................................ $
2012
2011
2010
(74) $
(19)
1
—
(92) $
(88) $
—
1
13
(74) $
(98)
(1)
11
—
(88)
U.S. Federal Income Tax Refund
In 2004, we deducted a portion of our foreign dividends as allowed by the IRC when we filed our federal income tax
return. Upon further review and analysis, we determined our foreign dividends should have been offset against our current 2004
operating loss. In 2009, we filed an amended federal income tax return that reflected this change and would result in a refund of
approximately $10 million. This amended federal return has been under audit by the IRS since it was filed. In October 2012, the
IRS approved our amended tax return, and we received a refund of approximately $13 million which included approximately $3
million in accrued interest. The benefit of this refund is reflected in our Consolidated Financial Statements in the fourth quarter
of 2012.
11. Earnings (Loss) per Share
Pursuant to our Plan of Reorganization, all shares of our common stock outstanding prior to the Effective Date were
canceled and the issuance of 485 million new shares of reorganized Calpine Corporation common stock was authorized to resolve
allowed unsecured claims. A portion of the 485 million authorized shares was immediately distributed, and the remainder was
reserved for distribution to holders of certain disputed claims that, although allowed as of the Effective Date, were unresolved. In
June 2011, we settled the largest remaining claim outstanding and began the process of distributing the balance of the reserved
shares, which was completed during the third quarter of 2011, pursuant to our Plan of Reorganization. Accordingly, although the
reserved shares were not issued and outstanding for the entire balance of the periods presented, all conditions of distribution had
been met for these reserved shares as of the Effective Date, and such shares are considered issued and are included in our calculation
of weighted average shares outstanding. We also include restricted stock units for which no future service is required as a condition
to the delivery of the underlying common stock in our calculation of weighted average shares outstanding.
As we incurred a net loss for the year ended December 31, 2011, diluted loss per share for this period is computed on
the same basis as basic loss per share, as the inclusion of any other potential shares outstanding would be anti-dilutive.
Reconciliations of the amounts used in the basic and diluted earnings (loss) per common share computations for the years
ended December 31, 2012, 2011 and 2010, are as follows (shares in thousands):
Diluted weighted average shares calculation:
Weighted average shares outstanding (basic) .............................................................
Share-based awards.....................................................................................................
Weighted average shares outstanding (diluted)...........................................................
2012
2011
2010
467,752
3,591
471,343
485,381
—
485,381
486,044
1,250
487,294
We excluded the following items from diluted earnings (loss) per common share for the years ended December 31, 2012,
2011 and 2010, because they were anti-dilutive (shares in thousands):
Share-based awards.....................................................................................................
2012
10,302
2011
15,260
2010
14,883
12.
Stock-Based Compensation
Calpine Equity Incentive Plans
The Calpine Equity Incentive Plans provide for the issuance of equity awards to all non-union employees as well as the
non-employee members of our Board of Directors. The equity awards may include incentive or non-qualified stock options,
146
restricted stock, restricted stock units, stock appreciation rights, performance compensation awards and other share-based awards.
The equity awards granted under the Calpine Equity Incentive Plans include both graded and cliff vesting options which vest over
periods between one and five years, contain contractual terms between approximately five and ten years and are subject to forfeiture
provisions under certain circumstances, including termination of employment prior to vesting. At December 31, 2012, there were
567,000 and 27,533,000 shares of our common stock authorized for issuance to participants under the Director Plan and the Equity
Plan, respectively.
We use the Black-Scholes option-pricing model or the Monte Carlo simulation model, as appropriate, to estimate the fair
value of our employee stock options on the grant date, which takes into account the exercise price and expected term of the stock
option, the current price of the underlying stock and its expected volatility, expected dividends on the stock and the risk-free
interest rate for the expected term of the stock option as of the grant date. For our restricted stock and restricted stock units, we
use our closing stock price on the date of grant, or the last trading day preceding the grant date for restricted stock granted on non-
trading days, as the fair value for measuring compensation expense. Stock-based compensation expense is recognized over the
period in which the related employee services are rendered. The service period is generally presumed to begin on the grant date
and end when the equity award is fully vested. We use the graded vesting attribution method to recognize fair value of the equity
award over the service period. For example, the graded vesting attribution method views one three-year option grant with annual
graded vesting as three separate sub-grants, each representing 33 1/3% of the total number of stock options granted. The first sub-
grant vests over one year, the second sub-grant vests over two years and the third sub-grant vests over three years. A three-year
option grant with cliff vesting is viewed as one grant vesting over three years.
Stock-based compensation expense recognized was $25 million, $24 million and $24 million for the years ended
December 31, 2012, 2011 and 2010, 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 years ended December 31, 2012, 2011 and 2010. At December 31, 2012, there was unrecognized compensation
cost of $6 million related to options, $25 million related to restricted stock and nil related to restricted stock units, which is expected
to be recognized over a weighted average period of 0.8 years for options, 1.3 years for restricted stock and 0.4 years for restricted
stock units. We issue new shares from our share reserves set aside for the Calpine Equity Incentive Plans and employment
inducement options when stock options are exercised and for other share-based awards.
A summary of all of our non-qualified stock option activity for the Calpine Equity Incentive Plans for the year ended
December 31, 2012, is as follows:
Number of
Shares
Weighted Average
Exercise Price
Outstanding — December 31, 2011 ............................
Granted......................................................................
Exercised ...................................................................
Forfeited ....................................................................
Expired ......................................................................
Outstanding — December 31, 2012 ............................
Exercisable — December 31, 2012 .............................
Vested and expected to vest – December 31, 2012...
17,665,902
898,115
348,500
187,716
165,300
17,862,501
10,251,149
17,588,775
$
$
$
$
$
$
$
$
17.32
15.35
14.94
13.42
17.77
17.30
19.16
17.34
Weighted
Average
Remaining
Term
(in years)
Aggregate
Intrinsic Value
(in millions)
4.8
$
26
4.0
3.6
3.9
$
$
$
42
12
41
The total intrinsic value of our employee stock options exercised was $1 million, nil and nil for the years ended
December 31, 2012, 2011 and 2010, respectively. The total cash proceeds received from our employee stock options exercised
was $5 million, nil and nil for the years ended December 31, 2012, 2011 and 2010, respectively.
The fair value of options granted during the years ended December 31, 2012, 2011 and 2010, was determined on the
grant date using the Black-Scholes option-pricing model or the Monte Carlo simulation model, as appropriate. Certain assumptions
were used in order to estimate fair value for options as noted in the following table.
147
Expected term (in years)(1) ........................................................................
Risk-free interest rate(2) .............................................................................
Expected volatility(3) .................................................................................
Dividend yield(4)........................................................................................
Weighted average grant-date fair value (per option)................................. $
___________
6.5
2012
2011
2010
4.0 – 6.5
1.3 – 3.3 %
1.7 – 3.2 %
27.0 – 30.5 % 31.2 – 44.9 % 31.4 – 37.6 %
1.2 – 1.6 %
6.5
—
5.18
$
—
5.49
$
—
1.98
(1)
Expected term calculated using the simplified method prescribed by the SEC due to the lack of sufficient historical exercise
data to provide a reasonable basis to estimate the expected term.
(2)
Zero Coupon U.S. Treasury rate or equivalent based on expected term.
(3) Volatility calculated using the implied volatility of our exchange traded stock options.
(4) We have never paid cash dividends on our common stock, and it is not anticipated that any cash dividends will be paid on
our common stock in the near future.
No restricted stock or restricted stock units have been granted other than under the Calpine Equity Incentive Plans. A
summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the year ended
December 31, 2012, is as follows:
Nonvested — December 31, 2011......................................................................................................
Granted .............................................................................................................................................
Forfeited ...........................................................................................................................................
Vested...............................................................................................................................................
Nonvested — December 31, 2012......................................................................................................
Number of
Restricted
Stock Awards
3,510,358
1,991,894
297,166
1,071,049
4,134,037
Weighted
Average
Grant-Date
Fair Value
$
$
$
$
$
12.10
15.97
13.70
10.17
14.33
The total fair value of our restricted stock and restricted stock units that vested during the years ended December 31,
2012, 2011 and 2010, was approximately $20 million, $7 million and $4 million, respectively.
13. Defined Contribution and Defined Benefit Plans
We maintain two defined contribution savings plans that are intended to be tax exempt under Sections 401(a) and 501
(a) of the IRC. Our non-union plan generally covers employees who are not covered by a collective bargaining agreement, and
our union plan covers employees who are covered by a collective bargaining agreement. We recorded expenses for these plans of
approximately $11 million, $10 million and $9 million for the years ended December 31, 2012, 2011 and 2010, respectively.
Employer matching contributions are 100% of the first 5% of compensation a participant defers for the non-union plan. The
employee deferral limit is 75% of eligible compensation under both plans.
As part of the Conectiv Acquisition, we assumed approximately $6 million of pension liability for approximately 130
grandfathered union employees who joined Calpine as a result of the Conectiv Acquisition and enrolled them into the New
Development Holdings, LLC Union Retirement Plan, a defined benefit plan. PHI retained the pension liability associated with
prior service cost; however, we are responsible for benefits for services after July 1, 2010 and future compensation increases
related to prior service. During the second half of 2010, we initiated a voluntary retirement incentive program which reduced our
pension obligation by 31 employees. Under the New Development Holdings, LLC Union Retirement Plan, retirement benefits
are primarily a function of age attained, years of participation, years of service, vesting and level of compensation. As of
December 31, 2012 and 2011, our pension assets, liabilities and related costs were not material to us. As of December 31, 2012
and 2011, there were approximately $12 million and $10 million in plan assets and approximately $21 million and $18 million in
pension liabilities, respectively. Our net pension liability recorded on our Consolidated Balance Sheets as of December 31, 2012
and 2011, was approximately $9 million and $8 million, respectively. For the years ended December 31, 2012, 2011 and 2010,
we recognized net periodic benefit costs of approximately $1 million, $1 million and $9 million, respectively. Net pension benefit
costs for 2010 includes a one-time charge to pension expense for a voluntary retirement incentive program of approximately $8
million. The voluntary retirement incentive program was accepted by 31 of the 48 eligible employees that were retained as part
of the Conectiv Acquisition allowing these employees the ability to commence receiving retirement benefits early without reducing
148
their overall pension benefits. Our net periodic benefit cost is included in plant operating expense on our Consolidated Statements
of Operations. As of December 31, 2012 and 2011, the total amount recognized in AOCI for actuarial losses related to pension
obligation was approximately $1 million and $3 million, respectively.
In making our estimates of our pension obligation and related costs, we utilize discount rates, rates of compensation
increases and rates of return on our assets that we believe are reasonable. Due to relatively small size of our pension liability
(which is not considered material), significant changes in these assumptions would not have a material effect on our pension
liability. During 2012 and 2011, we made contributions of approximately $2 million and $3 million, respectively, and estimated
contributions to the pension plan are expected to be approximately $1 million in 2013. Estimated future benefit payments to
participants in each of the next five years are expected to be approximately $1 million in each year.
14. Capital Structure
Common Stock
Pursuant to our Plan of Reorganization, all shares of our common stock outstanding prior to the Effective Date were
canceled and the issuance of 485 million new shares of reorganized Calpine Corporation common stock was authorized to resolve
allowed unsecured claims. A portion of the 485 million authorized shares was immediately distributed, and the remainder was
reserved for distribution to holders of certain disputed claims that, although allowed as of the Effective Date, were unresolved. In
June 2011, we settled the largest remaining claim outstanding and began the process of distributing the balance of the reserved
shares, which was completed during the third quarter of 2011, pursuant to our Plan of Reorganization.
Our authorized common stock consists of 1.4 billion shares of Calpine Corporation common stock. Common stock issued
as of December 31, 2012 and 2011, was 492,495,100 shares and 490,468,815 shares, respectively, at a par value of $0.001 per
share. Common stock outstanding as of December 31, 2012 and 2011, was 457,048,970 shares and 481,743,738 shares, respectively.
The table below summarizes our common stock activity for the years ended December 31, 2012, 2011 and 2010.
Balance, December 31, 2009 ............................................
Resolution of claims ............................................................
Shares issued under Calpine Equity Incentive Plans...........
Balance, December 31, 2010 ............................................
Resolution of claims ............................................................
Shares issued under Calpine Equity Incentive Plans...........
Share repurchase program ...................................................
Balance, December 31, 2011.............................................
Shares issued under Calpine Equity Incentive Plans...........
Share repurchase program ...................................................
Balance, December 31, 2012 ............................................
Treasury Stock
Shares
Issued
443,325,827
488,612
1,068,917
444,883,356
44,258,432
1,327,027
—
490,468,815
2,026,285
—
492,495,100
Shares
Held in
Treasury
(327,572)
—
(120,586)
(448,158)
—
(139,846)
(8,137,073)
(8,725,077)
(284,376)
(26,436,677)
(35,446,130)
Total
487,745,299
—
Shares
Held in
Reserve
44,747,044
(488,612)
—
948,331
44,258,432
488,693,630
(44,258,432)
—
—
1,187,181
(8,137,073)
—
— 481,743,738
1,741,909
—
(26,436,677)
—
— 457,048,970
As of December 31, 2012 and 2011, we had treasury stock of 35,446,130 shares and 8,725,077 shares, respectively, with
a cost of $594 million and $125 million, respectively. On August 23, 2011, we announced that our Board of Directors had authorized
the repurchase of up to $300 million in shares of our common stock. In April 2012, our Board of Directors authorized us to double
the size of our share repurchase program, increasing our permitted cumulative repurchases to $600 million in shares of our common
stock. As of the filing of this Report, we have completed our previously announced $600 million share repurchase program, having
repurchased a total of 35,568,833 shares of our outstanding common stock at an average price paid of $16.87 per share. In February
2013, our Board of Directors authorized the repurchase of an additional $400 million in shares of our common stock, bringing the
cumulative authorization total to $1.0 billion. Our treasury stock also consists of our common stock withheld to satisfy federal,
state and local income tax withholding requirements for vested employee restricted stock awards. All treasury stock is held at cost.
149
15. Commitments and Contingencies
Long-Term Service Agreements
As of December 31, 2012, the total estimated commitments for LTSAs associated with turbines installed or in storage
were approximately $68 million. These commitments are payable over the terms of the respective agreements, which range from
1 to 5 years. LTSA future commitment estimates are based on the stated payment terms in the contracts at the time of execution
and are subject to an annual inflationary adjustment. Certain of these agreements have terms that allow us to cancel the contracts
for a fee. If we cancel such contracts, the estimated commitments remaining for LTSAs would be reduced.
Power Plant, Land and Other Operating Leases
We have entered into certain long-term operating leases for power plants, extending through 2020, which include renewal
options or purchase options at fair value and contain customary restrictions on dividends up to Calpine Corporation, additional
debt and further encumbrances similar to those typically found in project finance agreements. Payments on our operating leases,
which may contain escalation clauses or step rent provisions, are recognized on a straight-line basis. Certain capital improvements
associated with leased power plants may be deemed to be leasehold improvements and are amortized over the shorter of the term
of the lease or the economic life of the capital improvement. We have also entered into various land and other operating leases for
ground facilities and operations, which extend through 2069. Future minimum lease payments under these leases are as follows
(in millions):
Initial
Year
Land and other
operating leases .
various
Power plant
operating leases:
Greenleaf ..........
KIAC ................
Total power plant
leases..................
Total leases .......
1998
2000
$
$
$
$
2013
2014
2015
2016
2017
Thereafter
Total
14
$
14
$
14
$
15
$
15
$
228
$
300
7
24
31
45
$
$
$
3
24
27
41
$
$
$
— $
23
23
37
$
$
— $
22
22
37
$
$
— $
22
22
37
$
$
— $
52
52
280
$
$
10
167
177
477
During the years ended December 31, 2012, 2011 and 2010, rent expense for power plant and land and other operating
leases amounted to $51 million, $53 million and $60 million, respectively.
Production Royalties and Leases
We are obligated under numerous geothermal leases and right-of-way, easement and surface agreements. The geothermal
leases generally provide for royalties based on production revenue with reductions for property taxes paid. The right-of-way,
easement and surface agreements are based on flat rates or adjusted based on consumer price index changes and are not material.
Under the terms of most geothermal leases, the royalties accrue as a percentage of power revenues. Certain properties also have
net profits and overriding royalty interests that are in addition to the land base lease royalties. Some lease agreements contain
clauses providing for minimum lease payments to lessors if production temporarily ceases or if production falls below a specified
level. Production royalties for geothermal power plants for the years ended December 31, 2012, 2011 and 2010, were $22 million,
$22 million and $25 million, respectively.
150
Office Leases
We lease our corporate and regional offices under noncancellable operating leases extending through 2020. Future
minimum lease payments under these leases are as follows (in millions):
2013............................................................................................................................................................................ $
2014............................................................................................................................................................................
2015............................................................................................................................................................................
2016............................................................................................................................................................................
2017............................................................................................................................................................................
Thereafter ...................................................................................................................................................................
Total ......................................................................................................................................................................... $
12
12
12
12
12
31
91
Lease payments are subject to adjustments for our pro rata portion of annual increases or decreases in building operating
costs. During the years ended December 31, 2012, 2011 and 2010, rent expense for noncancellable operating leases was $12
million, $13 million and $12 million, respectively.
Natural Gas Purchases
We enter into natural gas purchase contracts of various terms with third parties to supply natural gas to our natural gas-
fired power plants. The majority of our purchases are made in the spot market or under index-priced contracts. At December 31,
2012, we had future commitments of approximately $3.0 billion for natural gas purchases under contracts with terms from 1 to
13 years, and one contract with a term of 29 years.
Guarantees and Indemnifications
As part of our normal business operations, we enter into various agreements providing, or otherwise arranging, financial
or performance assurance to third parties on behalf of our subsidiaries in the ordinary course of such subsidiaries’ respective
business. Such arrangements include guarantees, standby letters of credit and surety bonds for power and natural gas purchase
and sale arrangements and contracts associated with the development, construction, operation and maintenance of our fleet of
power plants. These arrangements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a
subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended
commercial purposes.
At December 31, 2012, guarantees of subsidiary debt, standby letters of credit and surety bonds to third parties and
guarantees of subsidiary operating lease payments and their respective expiration dates were as follows (in millions):
Guarantee Commitments
Guarantee of subsidiary debt(1)..
Standby letters of credit(2)(4) ......
Surety bonds(3)(4)(5).....................
Guarantee of subsidiary
operating lease payments(4).....
Total........................................
____________
2013
2014
2015
2016
2017
Thereafter
Total
$
47
$
536
—
7
$
590
$
36
41
—
3
80
$
$
37
—
—
—
37
$
$
36
—
—
—
36
$
$
26
19
—
—
45
$
209
$
30
4
—
391
626
4
10
$
243
$
1,031
(1) Represents Calpine Corporation guarantees of certain power plant capital leases and related interest. All guaranteed capital
leases are recorded on our Consolidated Balance Sheets.
The standby letters of credit disclosed above represent those disclosed in Note 6.
The majority of surety bonds do not have expiration or cancellation dates.
These are contingent off balance sheet obligations.
(2)
(3)
(4)
(5) As of December 31, 2012, $3 million of cash collateral is outstanding related to these bonds.
We routinely arrange for the issuance of letters of credit and various forms of surety bonds to third parties in support of
our subsidiaries’ contractual arrangements of the types described above and may guarantee the operating performance of some of
151
our partially-owned subsidiaries up to our ownership percentage. The letters of credit issued under various credit facilities support
CES risk management and other operational and construction activities. In the event a subsidiary were to fail to perform its
obligations under a contract supported by such a letter of credit or surety bond, and the issuing bank or surety were to make
payment to the third party, we would be responsible for reimbursing the issuing bank or surety within an agreed timeframe, typically
a period of one to ten days. To the extent liabilities are incurred as a result of activities covered by letters of credit or the surety
bonds, such liabilities are included on our Consolidated Balance Sheets.
Commercial Agreements — In connection with the purchase and sale of power, natural gas and emission allowances to
and from third parties with respect to the operation of our power plants, we may be required to guarantee a portion of the obligations
of certain of our subsidiaries. These guarantees may include future payment obligations and effectively guarantee our future
performance under certain agreements.
Asset Acquisition and Disposition Agreements — In connection with our purchase and sale agreements, we have frequently
provided for indemnification to the counterparty for liabilities incurred as a result of a breach of a representation or warranty by
the indemnifying party. These indemnification obligations generally have a discrete term and are intended to protect the parties
against risks that are difficult to predict or impossible to quantify at the time of the consummation of a particular transaction.
Other — Additionally, we and our subsidiaries from time to time assume other guarantee and indemnification obligations
in conjunction with other transactions such as parts supply agreements, construction agreements and equipment lease agreements.
These guarantee and indemnification obligations may include future payment obligations and effectively guarantee our future
performance under certain agreements.
Our potential exposure under guarantee and indemnification obligations can range from a specified amount to an unlimited
dollar amount, depending on the nature of the claim and the particular transaction. Our total maximum exposure under our guarantee
and indemnification obligations is not estimable due to uncertainty as to whether claims will be made or how any potential claim
will be resolved. As of December 31, 2012, there are no outstanding claims related to our guarantee and indemnification obligations
and we do not anticipate that we will be required to make any material payments under our guarantee and indemnification
obligations.
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 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 impact on our financial condition,
results of operations or cash flows or that would significantly change our operations.
152
16.
Segment and Significant Customer Information
We assess our business on a regional basis due to the impact on our financial performance of the differing characteristics
of these regions, particularly with respect to competition, regulation and other factors impacting supply and demand. At December
31, 2012, our reportable segments were West (including geothermal), Texas, North (including Canada) and Southeast. We continue
to evaluate the optimal manner in which we assess our performance including our segments and future changes may result.
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).
Year Ended December 31, 2012
West
Texas
North
Southeast
Consolidation
and
Elimination
Total
Revenues from external customers ...... $
Intersegment revenues..........................
Total operating revenues.................... $
Commodity Margin (1)(2) ....................... $
Add: Unrealized mark-to-market
commodity activity, net and other(3) ...
1,668
10
1,678
994
$
$
$
(93)
368
203
36
42
—
—
252
Less:
Plant operating expense........................
Depreciation and amortization
expense .............................................
Sales, general and other administrative
expense .............................................
Other operating expenses .....................
(Gain) on sale of assets, net..................
(Income) from unconsolidated
investments in power plants..............
Income from operations....................
Interest expense, net of interest
income...............................................
Loss on interest rate derivatives ...........
Debt extinguishment costs and other
(income) expense, net .......................
Income before income taxes and
discontinued operations.................
1,857
61
1,918
570
$
$
$
1,280
14
1,294
729
$
$
$
673
80
753
245
$
$
$
— $
5,478
(165)
(165) $
— $
—
5,478
2,538
87
247
142
47
5
—
—
216
(14)
(33)
206
134
28
29
(7)
(28)
353
131
85
29
5
(215)
—
177
(31)
(30)
(2)
—
(3)
—
—
4
$
(84)
922
562
140
78
(222)
(28)
1,002
725
14
45
218
153
Revenues from external customers ...... $
Intersegment revenues..........................
Total operating revenues.................... $
Commodity Margin(1)(2) ........................ $
Add: Unrealized mark-to-market
commodity activity, net and other(3) ...
Less:
Plant operating expense .........................
Depreciation and amortization
expense .............................................
Sales, general and other administrative
expense .............................................
Other operating expenses .....................
(Income) from unconsolidated
investments in power plants..............
Income (loss) from operations ..........
Interest expense, net of interest
income...............................................
Loss on interest rate derivatives ...........
Debt extinguishment costs and other
(income) expense, net .......................
Loss before income taxes and
discontinued operations.................
Year Ended December 31, 2011
West
Texas
North
Southeast
2,372
12
2,384
1,061
$
$
$
2,306
23
2,329
469
$
$
$
1,336
7
1,343
704
$
$
$
113
380
192
43
41
—
518
(102)
(13)
235
135
43
3
—
(49)
177
138
24
30
(21)
343
786
135
921
240
1
141
90
22
5
—
(17)
Consolidation
and
Elimination
Total
$
$
$
— $
6,800
(177)
(177) $
— $
—
6,800
2,474
(32)
(29)
(5)
(1)
(2)
—
5
(33)
904
550
131
77
(21)
800
751
145
115
$
(211)
154
Year Ended December 31, 2010
West
Texas
North
Southeast
Consolidation
and
Elimination
Total
2,525
12
2,537
1,080
$
$
$
2,162
22
2,184
504
$
$
$
69
351
207
55
59
97
—
—
380
89
285
150
38
2
—
(119)
—
237
978
6
984
535
21
138
111
45
28
—
—
(16)
250
$
$
$
880
138
1,018
272
$
$
$
— $
6,545
(178)
(178) $
— $
—
6,545
2,391
22
123
109
12
4
19
—
—
27
(30)
(29)
(7)
1
(2)
—
—
—
7
171
868
570
151
91
116
(119)
(16)
901
802
223
106
$
(230)
Revenues from external customers ...... $
Intersegment revenues..........................
Total operating revenues.................... $
Commodity Margin(1)(2) ........................ $
Add: Unrealized mark-to-market
commodity activity, net and other ....
Less:
Plant operating expense........................
Depreciation and amortization
expense .............................................
Sales, general and other administrative
expense .............................................
Other operating expenses .....................
Impairment losses.................................
(Gain) on sale of assets, net..................
(Income) from unconsolidated
investments in power plants..............
Income from operations....................
Interest expense, net of interest
income...............................................
Loss on interest rate derivatives ...........
Debt extinguishment costs and other
(income) expense, net .......................
Loss before income taxes and
discontinued operations.................
__________
(1) Our North segment includes Commodity Margin related to Riverside Energy Center, LLC of $73 million , $70 million and
$73 million for the years ended December 31, 2012, 2011 and 2010, respectively.
(2) Our Southeast segment includes Commodity Margin related to Broad River of $52 million, $51 million and $55 million
for the years ended December 31, 2012, 2011 and 2010, respectively.
(3)
Includes $1 million and $12 million of lease levelization and $14 million and $8 million of amortization expense for the
years ended December 31, 2012 and 2011, respectively, related to contracts that became effective in 2011.
Significant Customer
For the years ended December 31, 2012 and 2011, we had one significant customer, PJM Settlement, Inc., that accounted
for more than 10% of our annual consolidated revenues. Our revenues of $713 million and $742 million from PJM Settlement,
Inc. for the years ended December 31, 2012 and 2011, respectively, were attributed to our North segment. Our receivables from
PJM Settlement, Inc. were $37 million and $28 million as of December 31, 2012 and 2011, respectively. We did not have a customer
that accounted for more than 10% of our annual consolidated revenues for the year ended December 31, 2010.
155
17. Quarterly Consolidated Financial Data (unaudited)
Our quarterly operating results have fluctuated in the past and may continue to do so in the future as a result of a number
of factors, including, but not limited to, our restructuring activities (including asset sales), the completion of development projects,
the timing and amount of curtailment of operations under the terms of certain PPAs, the degree of risk management and marketing,
hedging and optimization activities, energy commodity market prices and variations in levels of production. Furthermore, the
majority of the dollar value of capacity payments under certain of our PPAs are received during the months of May through October.
Quarter Ended
December 31
September 30
June 30
March 31
(in millions, except per share amounts)
2012
Operating revenues ........................................................................... $
Income (loss) from operations .......................................................... $
Net income (loss) attributable to Calpine ......................................... $
Net income (loss) per common share attributable to Calpine —
Basic.................................................................................................. $
Net income (loss) per common share attributable to Calpine —
Diluted............................................................................................... $
1,367
295
100
0.22
0.22
$
$
$
$
$
1,996
705
437
0.95
0.94
2011
Operating revenues ........................................................................... $
Income from operations .................................................................... $
Net income (loss) attributable to Calpine ......................................... $
Net income (loss) per common share attributable to Calpine —
Basic.................................................................................................. $
Net income (loss) per common share attributable to Calpine —
Diluted............................................................................................... $
1,459
$
2,209
196
$
(13) $
(0.03) $
(0.03) $
403
190
0.39
0.39
$
$
$
$
$
$
$
$
$
$
$
879
(193) $
(329) $
1,236
195
(9)
(0.69) $
(0.02)
(0.69) $
(0.02)
1,633
$
1,499
183
$
(70) $
18
(297)
(0.14) $
(0.61)
(0.14) $
(0.61)
156
CALPINE CORPORATION AND SUBSIDIARIES
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS
Description
Year ended December 31, 2012
Balance at
Beginning
of Year
Charged to
Expense
Charged to
Other
Accounts
(in millions)
Deductions
(1)
Balance at
End of Year
Allowance for doubtful accounts..................................... $
Deferred tax asset valuation allowance ...........................
13
$
(1) $
2,336
(114)
Year ended December 31, 2011
Allowance for doubtful accounts..................................... $
Deferred tax asset valuation allowance ...........................
2
$
2,386
$
7
(50)
Year ended December 31, 2010
Allowance for doubtful accounts..................................... $
Deferred tax asset valuation allowance ...........................
14
$
2,572
(12) $
(186)
(1) $
—
$
4
—
— $
—
(5) $
—
— $
—
— $
—
6
2,222
13
2,336
2
2,386
_____________
(1) Represents write-offs of accounts considered to be uncollectible and previously reserved.
157
Delivering Effective
Capital Allocation
As a management team, we are committed to being good stewards of your
capital. Our goal is to deliver Adjusted Free Cash Flow Per Share growth
of 15 – 20% compounded annually. We strive to do this by identifying high-
return growth projects while also opportunistically repurchasing our stock,
which we believe represents an investment in clean, efficient and flexible
natural gas-fired generation at attractive prices. As America moves toward
clean, affordable natural gas as the preferred fuel for power generation and
as the electric grid requires more flexible power generation to integrate inter-
mittent renewable power to assure reliability of electric supply, we believe
Calpine’s fleet is uniquely positioned to benefit from the combination of these
secular and fundamental trends that favor combined-cycle natural gas-fired
power generation as the technology of choice for America’s future.
Calpine’s management team rings the closing
bell at the New York Stock Exchange (L to R):
Thad Hill (President and COO), Jack Fusco
(CEO), Thad Miller (EVP and CLO) and
Zamir Rauf (EVP and CFO).
National Portfolio of more than 27,000 MW in Operation
NORTH REGION
30 plants
7,320 MW
309 MW Under Advanced
Development
WEST REGION
37 plants
6,751 MW
773 MW Under Construction
TEXAS REGION
13 plants
8,014 MW
390 MW Under Construction
SOUTHEAST REGION
10 plants
5,236 MW
ADJUSTED EBITDA
($ millions)
$1,712
$1,726
$1,749
ADJUSTED FREE CASH FLOW
ADJUSTED FREE CASH FLOW
($ millions)
$558
$564
$489
PER SHARE
$1.15
$1.01
$1.20
2010
2011
2012
2010
2011
2012
2010
2011
2012
All MW figures shown represent Calpine’s net ownership interest.
BOARD OF DIRECTORS
J. Stuart Ryan (N)
Chairman of the Board
Chief Executive Officer, Aggregates USA and
Founding Owner and President, Rydout LLC
Frank Cassidy (C)
Retired President and Chief Operating Officer
PSEG Power LLC
Jack A. Fusco
Chief Executive Officer, Calpine Corp.
Robert C. Hinckley (A)(N)
Chairman and Managing Director, MCL Intellectual
Property LLC
David C. Merritt (A)
President, BC Partners, Inc.
EXECUTIVE MANAGEMENT
Jack A. Fusco
Chief Executive Officer
John B. (Thad) Hill
President and Chief Operating Officer
GENERAL INFORMATION
Corporate Headquarters
Calpine Corporation
717 Texas Avenue, Suite 1000
Houston, Texas 77002
(713) 830-2000
www.calpine.com
Investor Relations
Calpine Corporation Investor Relations
(713) 830-8775
investor-relations@calpine.com
Independent Auditor
Pricewaterhouse Coopers LLP
Houston, Texas
Transfer Agent
Computershare, Inc.
P.O. Box 43078
Providence, RI 02940-3078
(877) 745-9351
Stock Information
Calpine Corporation’s common stock is listed on the
NYSE under the symbol CPN.
W. Benjamin Moreland (A)
President and Chief Executive Officer
Crown Castle International Corp.
Robert A. Mosbacher, Jr. (C)(N)
Chairman, Mosbacher Energy Company
William E. Oberndorf (C)
Chairman, Oberndorf Enterprises, LLC
Denise M. O’Leary (C)(N)
Private Venture Capital Investor
(A) Audit Committee
(C) Compensation Committee
(N) Nominating and Governance Committee
W. Thaddeus Miller
Executive Vice President, Chief Legal Officer and
Corporate Secretary
Zamir Rauf
Executive Vice President and Chief Financial Officer
Form 10-K
The Company’s Annual Report on Form 10-K for the year ended
December 31, 2012, as filed with the Securities and Exchange
Commission, is included in this report. Additional copies may
be obtained without charge by writing:
Calpine Corporation
Attn: Investor Relations
717 Texas Avenue, Suite 1000
Houston, Texas 77002
Annual Meeting
The Annual Meeting of Shareholders of Calpine Corporation
will be held on Friday, May 10, 2013, at 8 a.m. Central Time
at our corporate offices located at 717 Texas Ave., 10th floor,
Houston, TX 77002. All shareholders are cordially invited to attend.
Forward-Looking Statement
Certain statements made in this Annual Report by or on behalf
of the Company that are not historical facts are intended to be
forward-looking statements within the meaning of the safe harbor
provisions of the Private Securities Litigation Reform Act of 1995.
These statements are based on assumptions that the Company
believes are reasonable; however, many important factors, as
discussed under “Forward-Looking Statements” in the Company’s
Form 10-K for the year ended December 31, 2012, could cause
the Company’s results in the future to differ materially from the
forward-looking statements made herein and in any other documents
or oral presentations made by or on behalf of the Company.
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Calpine Corporation
717 Texas Avenue, Suite 1000
Houston, Texas 77002
(713) 830-2000
w w w . c a l p i n e . c o m