A GENERATION AHEAD,
today
2 0 0 9 A N N U A L R E P O R T
A GENERATION AHEAD,
today
With America embarking on a journey to a future of clean power, Calpine’s power generation portfolio contains the critical pieces
needed to help solve the nation’s energy policy puzzle. One of the most important policy challenges is to assure the right array
of power generation resources. Most renewable resources, other than geothermal, are intermittent, presenting reliability
challenges. Potential technological solutions are not assured and, in any event, may be many years off.
Our geothermal plants at The Geysers are the ideal renewable resource, providing power every minute of every day. Our
modern, clean and efficient natural gas plants provide the grid with the flexibility and reliability that allow for the integration
of intermittent renewable power, provide American industry with highly efficient steam and power to keep jobs here, and, due to
the underulitization of natural gas generation in many regions, provide an existing and immediately viable alternative to burning
coal, while emitting less than half the carbon dioxide, a fraction of the sulfur dioxide and nitrous oxide, and no mercury, among
other site advantages.
We are generating solutions for the future, today.
Geothermal Generation
Calpine owns and operates the nation’s largest baseload
renewable energy fleet, consisting of 15 geothermal plants
known as Calpine’s Geysers.
Calpine’s 121 industrial gas turbines
comprise the nation’s largest fleet converting
clean-burning natural gas into electricity.
Gas-Fired Generation
Calpine’s fleet of 22 cogeneration plants,
the nation’s largest, provide industrial
customers with thermal energy and power.
GENERATING SOLUTIONS for our
Shareholders
FINANCIAL PERFORMANCE:
D
uring 2009, amidst challenging macroeconomic conditions
and uneven capital markets, Calpine, through a combination
of conservative risk management and sound operational, commercial
and financial execution, managed to improve financial performance.
We held Commodity Margin steady, reduced expenses, increased
Adjusted EBITDA by 5%, and improved Adjusted Free Cash Flow to
help maintain strong liquidity, to service our debt, to meet our collateral needs and to fund operations and disciplined growth1.
CLO, Thad Hill, CCO, and Zamir Rauf, CFO.
(Front row) Jack Fusco, CEO. (Back row, left to right) Thad Miller,
FINANCIAL HIGHLIGHTS: ($ MILLIONS)
A d j u s t e d E b i t d a A d j u s t e d F r e e C a s h F l ow N e t I n c o m e L i qu i d i t y
1,699
1,782
609
149
2,379
2,178
495
2008
2009
2008
2009
10
2008
2009
2008
2009
N a t i o n a l Po r t fo l i o o f n e a r ly 2 5 , 0 0 0 MW
North Region:
3,417 MW
2009 Adj. EBITDA: $220M
West Region:
7,846 MW
2009 Adj. EBITDA: $959M
Texas Region:
7,392 MW
2009 Adj. EBITDA: $430M
1
Southeast Region:
6,083 MW
2009 Adj. EBITDA: $188M
In Operation - Gas-Fired (61)
In Operation - Geothermal (15)
Under Advanced Development (2)
Map does not include Consolidation and
Elimination Adjusted EBITDA of $(15)M.
1 Commodity Margin, Adjusted EBITDA, Adjusted Free Cash Flow and Liquidity, as referenced within this document,
are non-GAAP financial measures. Refer to the Investor Relations section of our website for reconciliations of these
measures to the most comparable GAAP measures.
1
Calpine 2009 Annual Report
DEAR FELLOW SHAREHOLDERS,
W
hen I wrote to you a year ago, my first year at the
helm of Calpine, I recognized that in 2009 we would be
challenged as an organization and yet was confident we would rise
to the occasion. I am pleased and proud to report that we have
exceeded my expectations and surpassed our goals. Our share
price improved 51% during the year, and our operating, commer-
cial and financial performance metrics demonstrated true progress
toward becoming the leading independent power producer in the
nation. We were able to do so because our employees remained
focused and executed on our mission. They are to be com-
mended. This year will be challenging as well. We will remain
focused on operating excellence, innovative but conservative
commercial execution, environmental leadership and customer
satisfaction, while continuing to deliver shareholder value.
2009: MEETING THE CHALLENGE
My goal for Calpine is to be the premier power plant operator
in the industry. Our ability to efficiently and reliably generate
power, coupled with the effective implementation of our hedging
strategy, enabled us to deliver exceptional results, despite a
national power demand decline of approximately 4%. We main-
tained Commodity Margin level to 2008, despite a 56% decline
in average natural gas prices and similar reduction in wholesale
electric prices in markets in which we participate. We realized
over $60 million of sustainable savings in controllable expenses,
reflecting, among other things, the results of our realignment and
business improvement efforts over the course of the year. As a
consequence, Adjusted EBITDA and Adjusted Free Cash Flow
improved by 5% and 23%, respectively. Importantly, we are
holding ourselves accountable for maintaining these savings over
the long term. We are not simply “short-term cost cutting” our
way through tough economic times.
These financial results demonstrate the culmination of many
accomplishments. Here are a few:
2009 POWER OPERATIONS
• Our Otay Mesa Energy Center, an air-cooled combined-cycle
gas turbine plant, commenced operations in October 2009
under a ten-year power purchase agreement with San Diego
Gas & Electric.
2
Calpine 2009 Annual Report
• We maintained our top-quartile safety performance for
the seventh consecutive year with four plants having earned
certification as OSHA Star VPP sites, one of the highest
safety recognitions available in the industry.
• Across the fleet, we had an astonishing 2.03% forced
outage factor, a reduction of 38% from 2008.
2009 COMMERCIAL OPERATIONS
We refocused our efforts on customer origination, with an empha-
sis on listening to our customers’ needs and creating solutions for
them. As a result, we signed multiple new contracts, including:
• A series of contracts with Pacific Gas & Electric for inter-
mediate and peaking generation, as well as baseload renewable
geothermal generation from our Geysers to help meet their
renewable portfolio standards obligations.
• An innovative agreement with Los Angeles Department
of Water and Power to integrate procured renewable wind
generation with our quick-responding natural gas-fired
generation to provide a firm power supply.
• In the challenging Southeast market, we entered into
agreements with the TVA and Entergy.
2009 CORPORATE INITIATIVES
• We made significant progress toward improving our balance
sheet and corporate structure, refinanced approximately $3 billion
of debt and improved our capital flexibility for the future by issuing
new bonds with favorable covenants. We also eliminated near-
term maturities, extended our debt maturity profile and improved
our liquidity, which approached $2.4 billion as of year-end.
• We initiated organizational efficiency improvements that
have resulted in tangible, sustainable benefits. We consolidated
office locations and administrative functions and additionally,
centralized our procurement processes, generating meaningful
cost savings. Finally, we completed the implementation of
an enterprise business system, meaningfully enhancing our
accounting and financial reporting.
By focusing on these initiatives, I believe we will solidify a
foundation of growth for Calpine and we will also better prepare
ourselves for economic recovery when it does appear. Calpine is
uniquely well positioned to benefit from both price and volume
expansion when electric markets rebound, as we have the ability
to increase our plant output at the same time that power prices
improve with minimal additional capital investment.
Otay Mesa Energy Center, San Diego, CA
2010: CONTROLLING OUR DESTINY
Be assured, we will not rest on the laurels
of 2009. Instead, we have prepared
Calpine to weather what appears to be
an equally daunting 2010. Although
some signs of economy-wide stabilization
have appeared, the climb to a robust
recovery will be long and hard fought,
and natural gas and power prices likely
will remain muted. This is why we have
substantially hedged Commodity Margin
for 2010, effectively removing gas price
volatility from the portfolio. In addition,
we are forging ahead to identify and
execute on new commercial opportuni-
ties, continuing our efforts to deliver
best-in-class plant performance to maximize the efficiency and
availability of our existing fleet, and building and strengthening
customer relationships to identify solutions that deliver long-term
value for both our customers and our organization.
From a growth perspective, we will focus primarily on organic
growth opportunities. To support organic growth, we will
upgrade select combined cycle turbines to more efficient
technology, adding incremental capacity at attractive returns;
we have begun geothermal drilling and exploration to increase
our generation capability at our Geysers facilities; and, upon
regulatory approval, we expect to commence an upgrade project
at our Los Esteros Critical Energy Facility, which will transform
the existing plant from 188 MW of simple cycle capacity to 308
MW of efficient, combined-cycle capacity. We expect to break
ground on Russell City Energy City, a 600 MW combined cycle
power plant located in Hayward, California.
A FINAL WORD: HELPING CUSTOMERS
AND THE ENVIRONMENT
We operate in an industry that is in a state of
meaningful transition and within an economy
that is likewise evolving. I remain convinced
that Calpine is uniquely positioned to embrace
and profit from the changes afoot. In a future
that calls for more sources of cleaner power,
Calpine stands out as a leader among its peers:
we operate the largest fleet of renewable baseload
generation in the country, we operate a natural-gas
fleet that is meaningfully cleaner than other fossil
fuels and able to provide baseload, intermediate
and peaking supply, and finally, with renewable
energy mandates in place or on the horizon, our
customers will need natural gas-fired generation
to integrate renewable resources into the grid to maintain
reliability. In short, Calpine is a generation ahead, today.
I encourage you to share in our future as we continue to create
the premier independent power company in the United States.
Thank you for your support.
Very truly yours,
Jack A. Fusco
President and Chief Executive Officer
3
Calpine 2009 Annual Report
GENERATING SOLUTIONS for a
Sustainable future
Secure abundant and affordable domestic natural gas supply
A
sustainable future is a national goal. In the power sector, it requires that we integrate existing
technologies with innovation to provide an affordable energy solution that reduces environmental
impact and dependence on foreign resources. Calpine, through its renewable geothermal generation and efficient
natural gas portfolio, does exactly that. We are a generation ahead, today.
WE OFFER AFFORDABLE SOLUTIONS, TODAY.
The renewable power we produce at The Geysers uses proven technology to harness naturally generated energy.
Unlike solar, wind and other renewable technologies, it is available around the clock and no additional research or
subsidy is needed. This power source is available, accessible and reliable today.
Our natural gas-fired plants offer modern, efficient and clean capacity that is substantially underutilized today in
most regions. With little to no additional investment and no need for a subsidy, load-serving entities could decide
to more fully utilize the country’s existing natural gas-fired generation capacity and achieve an estimated 6-8%
reduction in overall greenhouse gas emissions nationwide. Amazingly, this means as a nation we could achieve a
third of the proposed 2020 reduction goal immediately and affordably. Additionally, as the nation increases the use
of intermittent renewable resources, the efficiency and flexibility of natural gas-fired generation makes it the ideal
partner to allow the integration of intermittent renewable technologies, such as solar and wind into the grid.
Finally, our fleet of natural gas-fired generation features the nation’s largest portfolio of cogeneration plants, which
concurrently produces steam and power for industrial customers. Cogeneration is among the most efficient forms of
fossil-fuel generation. Our 22 cogeneration plants serve a variety of industries across the country, providing our cus-
tomers with affordable energy and steam that help keep jobs in America.
WE OFFER MEANINGFULLY LESS ENVIRONMENTAL IMPACT, TODAY.
Since its inception, Calpine has been a leader in environmental stewardship, investing exclusively in renewable
4
Calpine 2009 Annual Report
Clean air
Clean water
Reliable and affordable power
geothermal and clean-burning natural gas-fired generation technologies. As a result, our fleet offers the lowest
greenhouse gas footprint among large independent power providers (IPP).
Calpine’s environmental stewardship extends to other precious resources, such as water and land. Rather than using
water from lakes, bays and rivers, Calpine uses nearly 32 million gallons of reclaimed water every day in its energy centers
throughout the country. Many of our plants substantially reduce the need to use precious ground or potable municipal
water for cooling needs and avoid putting heated water back into our waterways so as not to be detrimental to marine
life. With respect to land, natural gas-fired generation plants, on average, are capable of producing multiple times more
energy per acre than alternative generation technologies, including nuclear, solar and wind. As the nation’s largest oper-
ator of natural gas-fired technology, we are a generation ahead in terms of efficiently using our nation’s natural resources.
WE OFFER A SECURE SOLUTION, TODAY.
Given recent shale gas discoveries in the United States, transitioning to an energy platform that relies more on
natural gas than other fossil fuels advances our country’s efforts to reduce dependence on foreign oil. It is estimated
that the United States now has proven natural gas
reserves in excess of 100 years, which fully supports
the sustainability of natural gas as a domestically
viable solution for our future. The abundance
of this supply also mitigates the historic price
volatility associated with natural gas, helping
make it a secure and economically viable
solution for the future, today.
c a l p i n e f a c t s :
needed for solar, wind, coal and nuclear power plants.
• Calpine’s Otay Mesa Energy Center in San Diego features one of
the world’s largest air cooled condensers, which allows us to cool
the plant using minimal amounts of water.
• Calpine produces about 1,000 fewer pounds of CO2/MWh each year
than our IPP peers, equivalent to taking 8 million cars off the road.
• Calpine’s natural gas-fired plants use a fraction of the acreage
5
Calpine 2009 Annual Report
GENERATING SOLUTIONS that are
Renewable
Calpine is proud to include this photo taken by amateur photographer,
John Grice, Operating Technician III at Calpine’s Geysers facilities.
R e n e w a b l e G e o t h e r m a l F l e e t
Calpine’s Geysers plants in Northern California sit on the largest
geothermal field in the world and are the largest baseload renewable
power resource in the U.S. During 2008, our Geysers plants
generated approximately 21% of California’s renewable energy.
Given the increasing importance of renewable energy – particularly
in California, which is setting the precedent for national renewable
portfolio standards – our Geysers plants fill a vital role. Available
every minute of every day and posing none of the grid integration
challenges of other renewable resources, Calpine’s Geysers plants
are one reason Calpine is a generation ahead, today.
Pow e r G e n e r a t i o n Av e r a ge Ava i l a b i l i t y
( 0 0 0 MW h )
6,021
5,949
97.2%
96.8%
2008
2009
2008
2009
c a l p i n e f a c t s :
• Calpine’s Geysers achieved a reliable 97% capacity factor in 2009.
• Calpine’s Geysers produce about 40% of the nation’s
geothermal power.
• Calpine’s Geysers use 15 million gallons of municipal wastewater
each day, eliminating the need to discharge this water into
local waterways – another innovative environmental win-win.
GENERATING SOLUTIONS that are
Flexible and Reliable
Pow e r G e n e r a t i o n Av e r a ge Ava i l a b i l i t y S ta r t i n g r e l i a b i l i t y Fo rc e d O u ta ge Fa c t o r
( 0 0 0 MW h )
91,931
89,033
92.10%
96.97%
90.50%
96.76%
3.29%
2.03%
2008
2009
2008
2009
2008
2009
2008
2009
D
uring 2009, we made remarkable progress toward our goal to be a best-in-class operating power company in
the United States. We took a “return-to-basics” approach, and the results are evidenced by improvements
in several of our key performance indicators.
As the charts above display, our generation output increased during 2009, despite an approximate 4% downturn
in national power demand. We improved fleetwide Average Availability, meaning that our plants were online more
often, particularly when our customers needed us the most. Similarly, our Starting Reliability increased, which allows
our customers to dependably call on Calpine to fill their generation needs.
Year-over-year, our Forced Outage Factor, a measure of unplanned events causing a unit to go offline, dropped a
meaningful 38%. This was due to our proactive approach to maintenance. We have the largest fleet of modern
gas turbines in the country, comprised predominantly of F-Class combustion turbines, which has allowed us to build
substantial in-house expertise in our Turbine Maintenance Group, giving us world-class technical performance. By
applying technical proficiency and an entrepreneurial approach, we craft solutions that deliver superior performance.
This allows us to maximize revenue by producing more power.
Our improvements in plant operations are particularly significant considering they were achieved while simultaneously
reducing expenses. New management took a long, hard look at how we were operating and realigned the organiza-
tion to promote organizational efficiencies. Each of our plant managers developed site-specific business plans with a
clear focus on embracing accountability. Additionally, we initiated a nationwide program to ensure that we were
leveraging our purchasing power through national supply contracts. These efforts, among others, allowed us to
deliver top-notch operating results while improving the bottom line.
G e o gr a p h i c D i v e rs i t y D i s p a t ch F l e x i b i l i t y G e n e r a t i o n by T y p e
North
3,417 MW
14%
West
7,846 MW
32%
Southeast
6,083 MW
24%
Texas
7,392 MW
30%
Peaking
5,000 MW
20%
Baseload
4,050 MW
17%
Intermediate
15,688 MW
63%
8
Calpine 2009 Annual Report
Combustion turbine
2%
Geothermal 6%
38%
Combined-cycle
cogeneration
Combined-cycle
54%
C l e a n - b u r n i n g N a t u r a l G a s F l e e t
Our modern fleet uses state-of-the-art technology for natural
gas-fired power generation. This allows us to produce far cleaner
and more efficient power across the fleet than the average U.S.
power producer. Our plants feature fast response digital controls
allowing us to quickly respond to our customers’ real-time needs.
Within our natural gas fleet, we operate the nation’s largest portfolio
of highly efficient cogeneration plants, which harness the energy in
a single fuel source to produce both electricity and thermal products
(like steam) for our customers. These cogeneration plants are
critical to American industry.
Metcalf Energy Center, San Jose, CA
c a l p i n e f a c t s :
• Calpine’s fleet is an average 8 years young, while over 40% of
the nation’s non-renewable generation is more than 35 years old.
• Calpine’s cogeneration plants are over 60% more fuel efficient on
average than typical older technology natural gas and coal plants.
• Our Russell City Energy Center features the nation’s first air permit
voluntarily subject to greenhouse gas emissions limits,
demonstrating our commitment to environmental stewardship.
GENERATING SOLUTIONS for our
Customers
Power for manufacturing
Power for load-serving entities
I
n 2009, we reinvigorated our focus on the key principle of fostering customer relationships. We realigned
our organization to dedicate a core team of professionals to understand our customers’ needs and provide
them with innovative, cost-effective and mutually beneficial solutions, including:
• Environmentally responsible products. Energy from Calpine’s clean fleet helps our customers minimize their
greenhouse gas footprint while meeting their needs for reliable power. In addition, power from our Geysers allows
our customers in California to meet regulatory obligations for utilizing renewable energy.
• Flexible products. Our ability to cycle our natural gas-fired plants
quickly allows us to respond to customers’ varying demands for energy
supply. Our diverse portfolio of baseload, intermediate and peaking
power plants enables us to provide a suite of products that can be
shaped to match individual customer needs.
• Integration products. As the nation escalates its reliance on intermit-
tent renewable resources like solar and wind, it will become increasingly
important to have quick-responding and reliable backup generation to
call upon when these renewable sources go offline or suddenly reduce or
increase output. Calpine operates the nation’s largest fleet of flexible
natural gas-fired power plants, offering an ideal partner in the effort to
further integrate renewable resources into our nation’s power supply.
• Cost-effective products. Our modern and efficient fleet allows us
to produce power reliably and affordably. In an environment where
cost matters, we are able to offer products that are affordable for
our customers.
10
Calpine 2009 Annual Report
Calpine is proud to include this photo of
Hidalgo Energy Center in Edinburg, TX, taken
by Don Flanagan, Operator Technician I.
Power for industry
Power for agriculture
During 2009, our customer relationship efforts translated into meaningful results for Calpine. We signed several
significant and innovative new contracts with our customers, including:
• Pacific Gas & Electric (PG&E)*: Meeting our customer’s needs for nearly 1,800 MW of capacity in California,
we will provide PG&E with a full range of baseload, intermediate and peaking generation, including renewable
energy from our Geysers. In addition, we will upgrade our peaking plant at Los Esteros to a more efficient
combined-cycle plant, allowing us to enhance the expansion capabilities of our facility.
• Los Angeles Department of Water and Power (LADWP): Leveraging the flexibility of our fleet to meet
LADWP’s need to deliver reliable power while meeting its obligation under California’s renewable portfolio
standards, we designed a product that blends power from intermittent wind resources with power from our
Hermiston plant in Oregon to provide LADWP with a firm renewable-based power product. By combining the
procurement of intermittent renewable wind generation with the essential backstop of a reliable, flexible natural
gas-fired power supply, Calpine offers an innovative solution to meet the needs of the LADWP.
These partnerships with load-serving entities
illustrate only a portion of our customer base.
We also have strong, long-standing relationships
with the multiple industrial customers for whom
we provide steam and power. Across our nation-
wide fleet of 22 cogeneration plants, our steam
and power help our customers make or process
products such as gasoline, jet and diesel fuel, soft
drink bottles, juice cartons, garlic, onions, figs,
antifreeze, tires and traffic signs.
c a l p i n e f a c t s :
• In 2009, Calpine produced 92 million MWh of energy, enough
to power Los Angeles for more than three years.
• For the nearly 50 million travelers who commute through New York’s
Kennedy International Airport each year, Calpine’s cogeneration plant
provides the energy to heat and cool the airport’s water and air.
• Calpine’s cogeneration plants provided 47.3 billion pounds of steam
to industrial customers in 2009.
* Contracts subject to CPUC approval.
11
Calpine 2009 Annual Report
GENERATING SOLUTIONS by our
People
Safety
Esprit de Corps
W
hen our current management team joined Calpine eighteen months ago, they developed a new Values
Statement to guide the company. It’s not just lip service. All across the Calpine organization, employees
ASPIRE to the values which will make the company the premier independent power company in the United
States: Accountability, Safety, Passion, Integrity, Respect, and an Esprit de Corps. Big or small, visible or not,
our values make us who we are and make what we do meaningful. The following is a sampling of what went
on across our organization in 2009.
ACCOUNTABILITY. Under the leadership of project sponsor CFO Zamir Rauf,
Calpine launched a major financial and management reporting systems rebuilding
project that involved employees from every company office and all 76 plant locations.
Project Phoenix was designed to enhance accountability across Calpine by increasing
organizational efficiency through business process redesign, achieve operational
efficiencies, create a foundation for future growth, deliver consistent and concise
reporting, and modernize and simplify system architecture. With the improvement in processes and procedures
that resulted from the project, Calpine was able to achieve an expedited year-end financial close using the
redesigned system that enhanced our reporting.
SAFETY. At Calpine, we put safety first in everything that we do. Each year, Calpine recognizes employees
with its highest safety award, the Ron Appleton Memorial Safety Award, for their contributions to the company’s
vibrant safety culture. The 2009 winners – John Hinkel, Deer Park Energy Center, Operator Technician III;
Robert Sorenson, Turbine Maintenance Group, Engineering Technical Advisor; Dave Dickenson, Hermiston
Power Project, Maintenance Technician III – were recognized for improving Calpine’s overall safety systems
by implementing best practices, making safety process enhancements, providing outstanding safety training,
and making key suggestions to protect the health and well-being of their fellow employees.
12
Calpine 2009 Annual Report
Passion
Respect
PASSION. Rick Colgan, plant manager, and his employees at the Hermiston Power Project are passionate about
keeping the power on, and they proved it in 2009 when the plant recorded 100% availability and 100% capacity
factor in the months of September and December. The team at this merchant plant has a very strong understanding
of its plant economics and the value of being ready when called upon. Our Geysers, Morgan, Agnews, Delta,
Los Esteros and Pastoria Energy Centers had similarly exceptional performance last year.
INTEGRITY. Employees at Calpine’s facilities believe operating with integrity means being true to
your word. Calpine was founded on a premise that a commitment to good environmental practices
is an integral part of excellence in power generation. That ongoing commitment was exemplified by
six Calpine facilities which were recognized by the Texas Commission on Environmental Quality
(TCEQ) with Bronze Level membership in the Clean Texas Program for their efforts to achieve signif-
icant environmental results, create environmental awareness and protect air, water and land resources in Texas.
The six facilities are Baytown, Freestone, Hidalgo, Magic Valley, Pasadena and the Calpine corporate headquarters.
RESPECT. Calpine commenced operation under or signed approximately 5,300 megawatts of contracts that
leverage our flexible fleet to satisfy customer needs. With a focus on respecting customer’s needs, our California-
focused commercial, legal and governmental relations teams found many win-win solutions in the West that
resulted in increased utilization of company assets. Of particular note was an innovative arrangement in California
that integrates reliable, gas-fired generation with a variable renewable resource – wind – to help customers meet the
renewable energy portion of their portfolios.
ESPRIT DE CORPS. When Calpine’s newest power plant, the 608 MW Otay Mesa Energy Center, began
commercial operation in late 2009, Calpine employees from across the company celebrated the achievement with
a ribbon cutting ceremony in December. From the beginning of Calpine’s involvement with the project over nine
years ago to construction and operation, the Calpine team showed its tenacity, expertise and teamwork to make
the new plant a reality.
13
Calpine 2009 Annual Report
DEAR FELLOW SHAREHOLDERS,
W
hen I wrote to you last year, I noted the unprecedented
macroeconomic conditions that Calpine, like every
company, was facing. I also conveyed that I was confident new
management was building a solid foundation to enable Calpine
to weather the storm and to set a course for a successful future
for Calpine’s shareholders. The balance of 2009 did indeed
bring turbulent commodity prices, declining power demand
and overall economic sluggishness, yet Calpine’s management
made meaningful progress in strengthening the company and
positioning Calpine for continued growth in shareholder value.
I remain confident that Calpine is on the right track.
During 2009, our Board of Directors worked closely with the
management team to identify long-term value creation
opportunities. For example, mindful of the impact that
economic uncertainty could have upon capital markets and
intent upon ensuring the company’s financial strength in the
unlikely event that capital markets did not fully recover, we
encouraged a financing plan to address near-term debt maturities
and to begin to extend longer dated debt. With this charge,
management successfully refinanced approximately $3 billion
in debt, in part through a novel loan-for-bond exchange offer.
These refinancings eliminated our near-term maturities and
meaningfully extended the company’s debt maturity profile,
while at the same time improving liquidity, enhancing strategic
flexibility and preserving the company’s financial strength.
Our Board of Directors remains intent upon fully protecting
and enhancing the substantial value of Calpine’s assets. As
this Annual Report conveys, that value is tightly linked to
Calpine’s clear positioning as a solution for the country’s future
power needs. Building upon Calpine’s history of environmental
leadership and investment in clean, modern technology and
renewable energy, we are well-positioned to continue to lead
and benefit from the move toward clean power. Calpine is
generating solutions for a sustainable energy future, while
creating value for Calpine’s shareholders.
We continue to focus on long-term value creation, allocating
capital to earn attractive returns and positioning the company
for growth in profitability and free cash flow generation.
Our performance in 2009 demonstrated we are headed in the
right direction. As Jack outlines in his own message to you,
there are many reasons why we continue to remain optimistic
about Calpine’s future. We believe Calpine is poised to benefit
as the economy improves, the electricity supply/demand balance
tightens, and our country moves toward cleaner, more efficient
and more flexible sources of electricity.
On behalf of the Board, I would like to extend our thanks to
Jack Fusco and all of the hard-working people of Calpine.
We have benefitted from their prudent and responsible
leadership during these tumultuous times and are confident
their dedicated efforts are enhancing our company’s strong
prospects for significant long-term value creation.
Sincerely,
William J. Patterson
Chairman of the Board
14
Calpine 2009 Annual Report
A GENERATION AHEAD,
today
2 0 0 9 F O R M 1 0 - K
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
[X]
[
]
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2009
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) 830-8775
Not Applicable
(Former Address)
Securities registered pursuant to Section 12(b) of the Act:
Calpine Corporation Common Stock, $.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 [
] 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, 2009, the last business day of the registrant’s most recently completed second fiscal quarter: approximately $2,018 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: 442,890,684 shares of common stock, par value $.001, were outstanding as of
February 22, 2010.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as
specified in the responses to the item numbers involved.
Designated portions of the Proxy Statement relating to the 2010 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, 2009
TABLE OF CONTENTS
PART I
Item 1.
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1A. Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 2.
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 3.
Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 4.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 6.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations . . . .
Item 7A. Quantitative and Qualitative Disclosures about Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 8.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . .
Item 9.
Item 9A. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 9B. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART III
Item 10. Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Item 12.
Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 13. Certain Relationships and Related Transactions and Director Independence . . . . . . . . . . . . . . . .
Principal Accounting Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 14.
Item 15. Exhibits, Financial Statement Schedule . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Signatures
Power of Attorney . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Index to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART IV
Page
3
36
53
53
53
53
54
57
58
105
105
105
105
106
107
108
108
108
108
109
114
115
116
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. For clarification, for the period from December 20,
2005, through February 7, 2008, such terms do not include the Canadian Debtors and other foreign subsidiaries
that were deconsolidated as of the Petition Date. 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
Acadia PP
Adjusted EBITDA
Acadia Power Partners, LLC
(a)
the effects of
impairment charges,
EBITDA as adjusted for
(b)
reorganization items, (c) major maintenance expense, (d) operating lease
expense, (e) any non-cash realized gains on derivatives and any unrealized
gains or losses on commodity derivative mark-to-market activity, (f)
adjustments to reflect only the Adjusted EBITDA from our unconsolidated
investments, (g) claim settlement income, (h) stock-based compensation
expense (income), (i) non-cash gains or losses on sales or dispositions of
assets, (j) non-cash gains and losses from intercompany foreign currency
translations, (k) any gains or losses on the repurchase or extinguishment of
debt and (l) any other extraordinary, unusual or non-recurring items
Aircraft Services
AOCI
Aries Power Plant
Auburndale
Average availability
Average capacity
factor (excluding peakers)
Bankruptcy Code
BLM
Blue Spruce
Btu
CAA
CAISO
CalGen
Aircraft Services Corporation, an affiliate of General Electric Capital
Corporation
Accumulated Other Comprehensive Income
MEP Pleasant Hill, LLC
Auburndale Holdings, LLC
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
The average capacity factor (excluding peakers) is 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
during the period by (ii) the total hours in the period
U.S. Bankruptcy Code
Bureau of Land Management of the U.S. Department of the Interior
Blue Spruce Energy Center LLC
British thermal unit(s), a measure of heat content
Federal Clean Air Act, U.S. Code Title 42, Chapter 85
California ISO
Calpine Generating Company, LLC
ii
ABBREVIATION
CalGen Secured Debt
CalGen Third Lien Debt
DEFINITION
Collectively the: CalGen First Lien Debt comprised of (a) $235,000,000
First Priority Secured Floating Rate Notes Due 2009, (b) $600,000,000 First
Priority Secured Institutional Term Loans Due 2009, and (c) $200,000,000
First Priority Revolving Loans issued on or about March 23, 2004; CalGen
Second Lien Debt comprised of (a) $640,000,000 Second Priority Secured
Floating Rate Notes Due 2010, and (b) $100,000,000 Second Priority
Secured Institutional Term Loans Due 2010; and CalGen Third Lien Debt.
In each case, issued by CalGen or CalGen and CalGen Finance Corp. and
repaid on March 29, 2007
Together, the $680,000,000 Third Priority Secured Floating Rate Notes Due
2011, issued by CalGen and CalGen Finance Corp.; and the $150,000,000
11 1/2% Third Priority Secured Notes Due 2011, issued by CalGen and
CalGen Finance Corp., in each case repaid on March 29, 2007
Calpine Debtors
The U.S. Debtors and the Canadian Debtors
Calpine Equity Incentive Plans
Canadian Court
Canadian Debtors
Canadian Effective Date
Canadian Settlement Agreement
Cap-and-trade
Cash Collateral Order
Collectively, the MEIP and the DEIP, which provide for grants of equity
awards to Calpine employees and non-employee members of Calpine’s
Board of Directors
The Court of Queen’s Bench of Alberta, Judicial District of Calgary
The subsidiaries and affiliates of Calpine Corporation that were granted
creditor protection under the CCAA in the Canadian Court
February 8, 2008, the date on which the Canadian Court ordered and
declared that the Canadian Debtors’ proceedings under the CCAA were
terminated
Settlement Agreement dated as of July 24, 2007, by and between Calpine
Corporation, on behalf of itself and its U.S. subsidiaries, Calpine Canada
Energy Ltd., Calpine Canada Power Ltd., Calpine Canada Energy Finance
ULC, Calpine Energy Services Canada Ltd., Calpine Canada Resources
Company, Calpine Canada Power Services Ltd., Calpine Canada Energy
Finance II ULC, Calpine Natural Gas Services Limited, 3094479 Nova
Scotia Company, Calpine Energy Services Canada Partnership, Calpine
Canada Natural Gas Partnership, Calpine Canadian Saltend Limited
Partnership and HSBC Bank USA, National Association, as successor
indenture trustee
A government imposed GHG emissions reduction program that would place
a cap on the amount of GHG 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
GHG during each applicable period. After allowances have been distributed
or auctioned, they can be transferred, or traded
Second Amended Final Order of the U.S. Bankruptcy Court Authorizing Use
of Cash Collateral and Granting Adequate Protection, dated February 24,
2006 as modified by orders of the U.S. Bankruptcy Court dated June 21,
2006, July 12, 2006, October 25, 2006, November 15, 2006, December 20,
2006, December 28, 2006, January 17, 2007, and March 1, 2007
iii
ABBREVIATION
DEFINITION
CCAA
CCFC
CCFC Finance
CCFC Guarantors
CCFC New Notes
CCFC Old Notes
CCFC Refinancing
CCFC Term Loans
Companies’ Creditors Arrangement Act (Canada)
Calpine Construction Finance Company, L.P.
CCFC Finance Corp.
Hermiston Power LLC and Brazos Valley Energy LLC, wholly owned
subsidiaries of CCFC
The $1.0 billion aggregate principal amount of 8.0% Senior Secured Notes
due 2016 issued May 19, 2009, by CCFC and CCFC Finance
The $415 million total aggregate principal amount of Second Priority
Senior Secured Floating Rate Notes Due 2011 issued by CCFC and CCFC
issued
Finance, comprising $365 million aggregate principal amount
issued
August 14, 2003, and $50 million aggregate principal amount
September 25, 2003, and redeemed on June 18, 2009
The issuance of the CCFC New Notes on May 19, 2009, pursuant to
Rule 144A and Regulation S under the Securities Act, and the related
transactions including repayment of the CCFC Term Loans and the
redemption of the CCFC Old Notes and CCFCP Preferred Shares
The $385 million First Priority Senior Secured Institutional Term Loans
due 2009 borrowed by CCFC under the Credit and Guarantee Agreement,
dated as of August 14, 2003, among CCFC, the guarantors party thereto,
and Goldman Sachs Credit Partners L.P., as sole lead arranger, sole
bookrunner, administrative agent and syndication agent, and repaid on
May 19, 2009
CCFCP
CCFC Preferred Holdings, LLC
CCFCP Preferred Shares
The $300 million of six-year redeemable preferred shares due 2011 issued
by CCFCP and redeemed on or before July 1, 2009
CDWR
CES
CFTC
Chapter 11
CO2
Cogeneration
Commodity Collateral Revolver
Commodity expense
California Department of Water Resources
Calpine Energy Services, L.P.
U.S. Commodities Futures Trading Commission
Chapter 11 of the Bankruptcy Code
Carbon dioxide
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 Collateral Revolving Credit Agreement, dated as of July 8,
2008, among Calpine Corporation as borrower, Goldman Sachs Credit
Partners L.P., as payment agent, sole lead arranger and sole bookrunner,
and the lenders from time to time party thereto
The sum of our expenses from fuel and purchased energy expense, fuel
transportation expense, transmission expense and cash settlements from our
marketing, hedging and optimization activities that are included in our
mark-to-market activity in fuel and purchased energy expense, but excludes
the unrealized portion of our mark-to-market activity
iv
ABBREVIATION
Commodity Margin
Commodity revenue
Company
Confirmation Order
Convertible Senior Notes
CPUC
Creed
Deer Park
DEIP
DIP
DIP Facility
Disclosure Statement
EBITDA
Effective Date
EIA
DEFINITION
Non-GAAP financial measure that includes power and steam revenues,
sales of purchased power and natural gas, capacity revenue, REC revenue,
sales of surplus emission allowances, transmission revenue and expenses,
fuel and purchased energy expense, RGGI compliance costs, and cash
settlements from our marketing, hedging and optimization activities that are
included in mark-to-market activity, but excludes the unrealized portion of
our mark-to-market activity and other revenues
The sum of our revenues from power and steam sales, sales of purchased
power and natural gas, capacity revenue, REC revenue, sales of surplus
emission allowances, transmission revenue, and cash settlements from our
marketing, hedging and optimization activities that are included in our
mark-to-market activity in operating revenues but excludes the unrealized
portion of our mark-to-market activity
Calpine Corporation, a Delaware corporation, and subsidiaries
The order of the U.S. Bankruptcy Court entitled “Findings of Fact,
Conclusions of Law, and Order Confirming Sixth Amended Joint Plan of
Reorganization Pursuant to Chapter 11 of the Bankruptcy Code,” entered
December 19, 2007, confirming the Plan of Reorganization pursuant to
section 1129 of the Bankruptcy Code
Collectively, Calpine Corporation’s 4% Contingent Convertible Notes Due
2006, Contingent Convertible Notes Due 2014, 7 3/4% Contingent
Convertible Notes Due 2015 and 4 3/4% Contingent Convertible Senior
Notes Due 2023, all of which were terminated and settled with reorganized
Calpine Corporation common stock on the Effective Date
California Public Utilities Commission
Creed Energy Center, LLC
Deer Park Energy Center Limited Partnership
Calpine Corporation 2008 Director Incentive Plan, which provides for
grants of equity awards to non-employee members of Calpine’s Board of
Directors
Debtor-in-possession
The Revolving Credit, Term Loan and Guarantee Agreement, dated as of
March 29, 2007, among Calpine Corporation, as borrower, certain of
Calpine Corporation’s subsidiaries, as guarantors, the lenders party thereto,
and Credit Suisse, as administrative agent and collateral agent, and the other
agents, arrangers and bookrunners named therein
Disclosure Statement for the U.S. Debtors’ 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 June 20, 2007, as amended, modified or
supplemented through the filing of this Report pursuant to the Plan of
Reorganization
Earnings before interest, taxes, depreciation and amortization
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
Energy Information Administration of the U.S. Department of Energy
v
ABBREVIATION
Emergence Date Market
Capitalization
DEFINITION
The weighted average trading price of Calpine Corporation’s common stock
over the 30-day period following the date on which it emerged from
Chapter 11 bankruptcy protection, as defined in and calculated pursuant to
Calpine Corporation’s amended and restated certificate of incorporation and
reported in its Current Report on Form 8-K filed with the SEC on
March 25, 2008
EPA
ERCOT
EWG(s)
U.S. Environmental Protection Agency
Electric Reliability Council of Texas
Exempt wholesale generator(s)
Exchange Act
U.S. Securities Exchange Act of 1934, as amended
FDIC
FERC
First Lien Credit Facility
First Lien Facilities
First Lien Notes
First Priority Notes
FRCC
Fremont
GAAP
GE
GEC
Geysers Assets
GHG(s)
Gilroy
Goose Haven
Greenfield LP
Heat Rate(s)
Hg
Hillabee
IRC
U.S. Federal Deposit Insurance Corporation
U.S. Federal Energy Regulatory Commission
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
Together, our First Lien Credit Facility and $300 million Bridge Loan
Agreement dated January 31, 2008 repaid on March 6, 2008
$1.2 billion aggregate principal amount of 7 1/4% senior secured notes due
2017 issued October 21, 2009, in exchange for a like principal amount of
term loans under the First Lien Credit Facility
9 5/8% First Priority Senior Secured Notes Due 2014, repaid in May and
June 2006
Florida Reliability Coordinating Council
Fremont Energy Center, LLC
Generally accepted accounting principles
General Electric International, Inc.
Collectively, Gilroy Energy Center, LLC, Creed and Goose Haven
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
Greenhouse gas(es), primarily CO2, and including methane (CH4), nitrous
oxide (N2O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs) and
perfluorocarbons (PFCs)
Calpine Gilroy Cogen, L.P.
Goose Haven Energy Center, LLC
Greenfield Energy Centre LP
A measure of the amount of fuel required to produce a unit of power
Mercury
Hillabee Energy Center, LLC
Internal Revenue Code
vi
ABBREVIATION
DEFINITION
ISO(s)
ISO NE
Knock-in Facility
KWh
LIBOR
LSTC
LTSA(s)
Market Capitalization
Market Heat Rate(s)
MEIP
Metcalf
MISO
MMBtu
MRO
MW
MWh
NERC
NOL(s)
NOx
NPCC
NYISO
NYMEX
NYSE
OCI
OMEC
Original DIP Facility
Independent System Operator(s)
ISO New England
Letter of Credit Facility Agreement, dated as of June 25, 2008, among
Calpine Corporation as borrower and Morgan Stanley Capital Services Inc.,
as issuing bank which matured on June 30, 2009
Kilowatt hour(s), a measure of power produced
London Inter-Bank Offered Rate
Liabilities subject to compromise
Long-Term Service Agreement(s)
As of any date, Calpine Corporation’s then market capitalization calculated
using the rolling 30-day weighted average trading price of Calpine
Corporation’s common stock, as defined in and calculated in accordance
with the Calpine Corporation amended and restated certificate of
incorporation
The regional power price divided by the corresponding regional natural gas
price
Calpine Corporation 2008 Equity Incentive Plan, which provides for grants
of equity awards to Calpine employees and non-employee members of
Calpine’s Board of Directors
Metcalf Energy Center, LLC
Midwest ISO
Million Btu
Midwest Reliability Organization
Megawatt(s), a measure of plant capacity
Megawatt hour(s), a measure of power produced
North American Electric Reliability Council
Net operating loss(es)
Nitrogen oxide
Northeast Power Coordinating Council
New York ISO
New York Mercantile Exchange
New York Stock Exchange
Other Comprehensive Income
Otay Mesa Energy Center, LLC
The Revolving Credit, Term Loan and Guarantee Agreement, dated as of
December 22, 2005, as amended on January 26, 2006, and as amended and
restated by the Amended and Restated Revolving Credit, Term Loan and
Guarantee Agreement, dated as of February 23, 2006, among Calpine
Corporation, as borrower, the guarantors party thereto, the lenders from
time to time party thereto, Deutsche Bank Trust Company Americas, as
administrative agent for the First Priority Lenders, General Electric Capital
Corporation, as Sub-Agent for the Revolving Lenders, Credit Suisse, as
administrative agent for the Second Priority Term Lenders and the other
agents named therein, refinanced in March 2007 with the DIP Facility
vii
ABBREVIATION
DEFINITION
OTC
Panda
PCF
PCF III
Petition Date
PG&E
PJM
Plan of Reorganization
Pomifer
PPA(s)
PSM
PUCT
PUHCA 1935
PUHCA 2005
PURPA
QF(s)
REC(s)
Reserve margin(s)
RFC
RGGI
RMR Contract(s)
RockGen
RockGen Owner Lessors
Rosetta
RPS
SDG&E
Over-the-Counter
Panda Energy International, Inc., and related party PLC II, LLC
Power Contract Financing, L.L.C.
Power Contract Financing III, LLC
December 20, 2005
Pacific Gas & Electric Company
Pennsylvania-New Jersey-Maryland Interconnection
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 through the
filing of this Report
Pomifer Power Funding, LLC, a subsidiary of Arclight Energy Partners
Fund I, L.P.
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
Power Systems Manufacturing, LLC
Public Utility Commission of Texas
U.S. Public Utility Holding Company Act of 1935
U.S. Public Utility Holding Company Act of 2005
U.S. Public Utility Regulatory Policies Act of 1978
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 PUHCA 2005 and grants certain other benefits to the QF
Renewable energy credit(s)
The measure of how much the total generating capacity installed in a region
exceeds the peak demand for power in that region
ReliabilityFirst Corporation
Regional Greenhouse Gas Initiative
Reliability Must Run contract(s)
RockGen Energy LLC
Collectively, RockGen OL-1, LLC; RockGen OL-2, LLC; RockGen OL-3,
LLC and RockGen OL-4, LLC
Rosetta Resources Inc.
Renewable Portfolio Standards
San Diego Gas & Electric Company
viii
ABBREVIATION
DEFINITION
SEC
Second Circuit
Second Priority Debt
Securities Act
SERC
SO2
Spark spread(s)
U.S. Securities and Exchange Commission
U.S. Court of Appeals for the Second Circuit
Collectively, Calpine Corporation’s Second Priority Senior Secured
Floating Rate Notes Due 2007, 8 1/2% Second Priority Senior Secured
Notes Due 2010, 8 3/4% Second Priority Senior Secured Notes Due 2013
and 9 7/8% Second Priority Senior Secured Notes Due 2011 and Second
Priority Senior Secured Term Loans Due 2007; all of which were repaid on
the Effective Date
U.S. Securities Act of 1933, as amended
Southeastern Electric Reliability Council
Sulfur dioxide
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
Steamboat
Steamboat Amended Credit
Facility
TRE
ULC I
ULC II
Unsecured Notes
Unsecured Senior Notes
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
Calpine Steamboat Holdings, LLC, an indirect, wholly owned subsidiary of
Calpine Corporation
The Amended and Restated Credit Agreement dated November 24, 2009
between Steamboat, as borrower, the lenders named therein, Calyon New
York Branch as lead arranger, co-book runner, administrative agent,
collateral agent and Security Fund LC issuer and the other agents,
bookrunners and agents named therein amending and restating the Credit
Agreement, dated as of February 25, 2005, among the parties as defined
therein
Texas Regional Entity
Calpine Canada Energy Finance ULC
Calpine Canada Energy Finance II ULC
Collectively, Calpine Corporation’s 7 7/8% Senior Notes due 2008, 7 3/4%
Senior Notes due 2009, 8 5/8% Senior Notes due 2010 and 8 1/2% Senior
Notes due 2011, which constitute a portion of Calpine Corporation’s
Unsecured Senior Notes all of which were terminated and settled with
Calpine Corporation common stock on the Effective Date
Collectively, Calpine Corporation’s 7 5/8% Senior Notes due 2006,
10 1/2% Senior Notes due 2006, 8 3/4% Senior Notes due 2007, 7 7/8%
Senior Notes due 2008, 7 3/4% Senior Notes due 2009, 8 5/8% Senior
Notes due 2010 and 8 1/2% Senior Notes due 2011, all of which were
terminated and settled with Calpine Corporation common stock on the
Effective Date
U.S. Bankruptcy Court
U.S. Bankruptcy Court for the Southern District of New York
ix
ABBREVIATION
U.S. Debtor(s)
VAR
VIE(s)
WECC
Whitby
WP&L
DEFINITION
Calpine Corporation and each of its subsidiaries and affiliates that have
filed voluntary petitions for
the
Bankruptcy Code in the U.S. Bankruptcy Court, which matters are being
jointly administered in the U.S. Bankruptcy Court under the caption In re
Calpine Corporation, et al., Case No. 05-60200 (BRL)
Value-at-risk
reorganization under Chapter 11 of
Variable interest entity(ies)
Western Electricity Coordinating Council
Whitby Cogeneration Limited Partnership
Wisconsin Power & Light Company
x
Forward-Looking Statements
information,
In addition to historical
this Report contains “forward-looking statements” within the
meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. 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:
•
•
The uncertain length and severity of the current general financial and economic downturn, the timing
and strength of an economic recovery, if any, and their impacts on our business including demand for
our power and steam products, the ability of customers, suppliers, service providers and other
contractual counterparties to perform under their contracts with us and the cost and availability of
capital and credit;
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, fluctuations in liquidity and
volatility in the energy commodities markets and our ability to hedge risks;
• Our ability to manage our customer and counterparty exposure and credit risk,
including our
commodity positions;
• Our ability to manage our significant liquidity needs and to comply with covenants under our First
Lien Credit Facility, our First Lien Notes and other existing financing obligations;
• Competition, including risks associated with marketing and selling power in the evolving energy
markets;
• Regulation in the markets in which we participate and our ability to effectively respond to changes in
laws and regulations or the interpretation thereof including changing market rules and evolving
federal, state and regional laws and regulations including those related to GHG emissions and
derivative transactions;
• Natural disasters, such as hurricanes, earthquakes and floods, or acts of terrorism that may impact our
power plants or the markets our power plants serve;
•
Seasonal fluctuations of our results and exposure to variations in weather patterns;
• Disruptions in or limitations on the transportation of natural gas and transmission of power;
• Our ability to attract, retain and motivate key employees;
• Our ability to implement our business plan and strategy;
• 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;
• Risks associated with the operation, construction and development of power plants including
unscheduled outages or delays and plant efficiencies;
1
•
•
Present and possible future claims, litigation and enforcement actions;
The expiration or termination of our PPAs and the related results on revenues; 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 to the
SEC. Our SEC filings, including exhibits filed therewith, are also available at the SEC’s website at www.sec.gov.
You may obtain and copy any document we furnish or file with the SEC at the SEC’s public reference room at
100 F Street, NE, Room 1580, Washington, D.C. 20549-1004. You may obtain information on the operation of
the SEC’s public reference facilities by calling the SEC at 1-800-SEC-0330. You may request copies of these
documents, upon payment of a duplicating fee, by writing to the SEC at its principal office at 100 F Street, NE,
Room 1580, Washington, D.C. 20549-1004.
2
PART I
Item 1. Business
BUSINESS AND STRATEGY
Business
We aspire to be recognized as the premier independent power producer in the U.S. We seek to achieve
this objective by delivering operational excellence, effectively executing our hedging strategy, reinvigorating our
customer origination program, completing, on schedule and budget, our growth capital projects, and
strengthening our balance sheet. We are the largest independent wholesale power company in the U.S. measured
by power produced. We own and operate natural gas-fired and geothermal power plants in North America and
have a significant presence in major competitive power markets in the U.S., including California and Texas, and
to a lesser extent, in the competitive PJM, ISO NE and NYISO markets. Since our inception in 1984, we have
been a leader in environmental stewardship and have invested exclusively 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 comprised of two types of power generation technologies: natural gas-fired
combustion turbines, which are primarily 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 21% of all renewable energy produced in the
state of California during 2008. We sell wholesale power, steam, capacity, renewable energy credits and ancillary
services to our customers, including utilities, independent electric system operators, industrial and agricultural
companies, retail power providers, municipalities, power marketers and others. We purchase natural gas 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-related
commodity and derivative transactions to financially hedge certain business risks and optimize our portfolio of
power plants.
Our portfolio, including partnership interests, consists of 77 operating power plants, located throughout
16 states and Canada, with an aggregate generation capacity of approximately 24,802 MW. In addition, we are
actively pursuing the development of our Russell City Energy Center, in which we have a net interest of
approximately 400 MW, and an upgrade of 120 MW to our Los Esteros Critical Energy Facility, both located in
the San Francisco Bay Area. We also have begun geothermal exploration to increase our generation capability at
our Geysers Assets.
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 the lowest
GHG footprint per MWh of any major independent power producer in the U.S. 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. In addition, we
strive to preserve our nation’s valuable water and land resources. To condense steam, we 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 emissions, as well as water use
or emissions, than compared to our competitors who use other fossil fuels or steam condensation technologies.
We remain focused on increasing our earnings and generating cash flow sufficient to maintain adequate
levels of liquidity in order to service our debt, meet our collateral needs and fund our operations and growth. We
3
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 hedging
agreements within the guidelines of our commodity risk policy. Our fleet of natural gas-fired turbines is the
youngest in the U.S. among large independent power producers and utilities, with a weighted average age, based
upon MW capacities in operation, of about eight years. As a result, in the near term we do not expect that it will
be necessary to invest significant expenditures for environmental retrofits or repowering projects to comply with
current or reasonably anticipated GHG, other air emissions or water regulations. Our power plants taken as a
whole or by region, have an effective Heat Rate lower than that of our major competitors, which we believe gives
us a competitive edge in markets such as Texas, California and some northeastern states where natural gas-fired
generation generally sets the market price for power.
We sell a substantial portion of our power and other products under PPAs with a duration greater than one
year. The contracted sale of power, steam and capacity from our cogeneration power plants, combustion turbine
power plants and geothermal power plants, as well as the sale of renewable energy credits, or RECs, from
geothermal power plants, provide a stable source of revenue. Our portfolio also affords us the flexibility to sell
power and other products forward for shorter terms or on a merchant basis into the spot markets, where we are
able to realize attractive pricing particularly during peak demand periods. Additionally, we sell capacity or
similar products to retail power providers, utilities, municipalities and others required to acquire capacity and
similar products by regulatory or market rules and we sell ancillary services to independent system operators and
utilities to support power transmission system reliability. We believe we have substantially hedged our
Commodity Margin for 2010. By contrast, we remain exposed to significant commodity price movements for
2011 and beyond.
Our principal offices are located in Houston, Texas with a regional office in Dublin, California, an
engineering office in La Porte, Texas and representative 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 independent power company in the U.S. as measured by our
customers, regulators, shareholders and communities in which our power plants reside. We seek to achieve
sustainable growth through financially disciplined power plant development, construction, operations and
ownership. Our strategy to achieve this is reflected in the six major initiatives described below:
for
1. 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 outage management.
Throughout 2009, our plant operating personnel exceeded the first quartile performance for employee lost
time incident rate for fossil fuel electric power generation companies with 1,000 or more employees. In
addition,
the past nine consecutive years, our Geysers Assets have continued to generate
approximately 6 million MWh per year and achieved an exceptional equivalent availability factor of over
97% in 2009. Our natural gas-fired fleet achieved exceptional performance during 2009, with an
equivalent forced outage factor of 2.7%, an improvement of 35% over full year 2008. Lastly, we
completed 14 major inspections and 13 hot gas path inspections on schedule and on budget during 2009
and completed one of several planned natural gas-fired turbine upgrades and two steam turbine upgrades,
which not only added incremental capacity but improved the efficiency of the entire turbines.
2. Leader in Environmental Responsibility — Our focus is to utilize our modern, efficient fleet to deliver
lower carbon energy solutions. We continue to actively participate in legislative and regulatory processes
addressing environmental concerns and support legislative and regulatory action to address GHG and
other emissions from fossil fuel generation. We intend to leverage our baseload geothermal expertise to
to environmental
grow our renewable energy portfolio. Our strong and continuing commitment
responsibility and leadership is exemplified by our development of the Russell City Energy Center. On
4
February 4, 2010, we received the Prevention of Significant Deterioration, or PSD, air permit, the final
permit necessary, to begin construction of our Russell City Energy Center. Russell City Energy Center is
intended to become the first power plant in the U.S. with a federal limit on GHG emissions, and will be
designed to operate in a way that produces 25% fewer GHG emissions than the CPUC standard. The
power plant 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. We initiated and agreed to accept the GHG permit limit and
designed the plant to benefit local water resources.
3. Leverage our Scale with our Existing Portfolio of Power Plants — Our goal is to continue to grow our
presence in our core markets, particularly, our two largest markets, California and Texas, with an
emphasis on expansions or upgrades of existing power plants. We will consider selective acquisitions or
additions of new capacity supported by long-term hedging programs, including PPAs and natural gas
tolling agreements, particularly where limited or non-recourse project financing is available. We intend to
take an opportunistic approach to continue to design, develop, construct and operate the next generation
of highly efficient, operationally flexible and environmentally responsible power plants. During 2009, we
had the following notable achievements related to this initiative:
• OMEC, located in San Diego, California, achieved commercial operations on October 3, 2009, adding
608 MW of capacity to our fleet. OMEC is a state-of-the-art, environmentally friendly power plant
that operates one of the world’s largest air-cooled condenser thereby minimizing our water usage at
the site. OMEC operates under a ten-year tolling agreement with SDG&E.
• Under a new ten-year power contract with PG&E, we will modernize and upgrade our Los Esteros
Critical Energy Facility to add 120 MW by converting it from simple-cycle (peaking) to combined-
cycle technology, increasing the efficiency and environmental performance of the power plant.
• We received the Russell City Energy Center PSD air permit. We hope to complete financing and
break ground for this new state-of-the-art power plant during 2010 with commercial operations
scheduled to begin in 2013.
•
Turbine Upgrades — During the fourth quarter of 2009, we completed a natural gas-fired turbine
upgrade at our Deer Park Energy Center, and have an additional ten natural gas-fired turbine upgrades
scheduled. We have also upgraded the steam turbines at our McCabe and Ridgeline geothermal power
plants that improved the overall turbine efficiency. We have two additional steam turbine upgrades
scheduled for 2011 and 2012, and are considering others.
4. Three Scale Regions — We intend to grow our presence in the mid-Atlantic and northeast regions of the
U.S. through opportunistic and financially disciplined purchase of existing power plant assets as well as
new build projects. We believe this market will result in continued diversification of our asset portfolio,
significant near-term growth opportunity and accretive financial strengthening and value.
5. Customer-Oriented Origination Business — Our focus is to maximize and stabilize our Commodity Margin
through the utilization of physical forward sales and purchases, and financial tools such as collars, swaps and
options. During 2009, we reorganized our customer origination function to allow our dedicated group of
professionals to more effectively help manage this function. Their charter is to understand our customer’s
wants and needs and to rally our organization to develop unique, cost-effective solutions that benefit us and our
customers. This effort is beginning to deliver real, tangible results. For example, we entered into new PPAs and
amended certain PPAs with PG&E, and also entered into a new PPA with Southern California Edison related
to certain of our power plants in California. The amended and new PPAs are all on mutually beneficial terms,
many are subject to regulatory approvals and, among other things, provide for the following:
• We and PG&E have agreed to an extension of the term and an increase in the volume under the
existing contracts for delivery of power from our Geysers Assets. Our Geysers Assets currently
5
provide PG&E 375 MW of power under two contracts. We have agreed to increase the volume to 425
MW through 2017, and from 2018 through the end of 2021, our Geysers Assets will supply PG&E
250 MW of renewable energy.
• Our wholly owned subsidiaries, Gilroy Energy Center, LLC, Creed and Goose Haven, have entered
into a replacement contract with PG&E, whereby PG&E will have greater dispatch flexibility for all
11 of our peaking units in California through 2017 and for seven of our peaking units through 2021.
• We and PG&E negotiated a new agreement to replace the existing CDWR contract and facilitate the
upgrade of our Los Esteros Critical Energy Facility from a 188 MW simple-cycle generation power
plant to a 308 MW combined-cycle generation power plant. In addition to the increase in capacity, the
upgrade will increase the efficiency and environmental performance of the power plant by lowering
the Heat Rate. While the upgrade is under construction, we will provide capacity to PG&E from our
Gilroy Cogeneration Plant. Upon completion of the upgrade, PG&E will purchase all of the capacity
from our Los Esteros Critical Energy Facility for a term of ten years.
• We have entered into a new tolling arrangement with PG&E for all of the capacity from our Delta
Energy Center from 2011 through 2013.
• We executed a resource adequacy agreement for all of the capacity from our Pastoria Energy Center
with Southern California Edison for 2012 and 2013.
• We executed a contract for 500 MW of capacity from our Morgan Energy Center with the Tennessee
Valley Authority through 2011.
• We executed a contract for 485 MW of capacity from our Carville Energy Center with Entergy
Corporation through May 2012.
• We executed a contract for 200 MW of capacity from our Oneta Energy Center with American
Electric Power through 2010.
•
In addition to the suite of products we plan to supply through the agreements described above, our
commercial operations team is also identifying creative opportunities to match our capabilities with
the needs of our customers. During 2009, we entered into a PPA with the Los Angeles Department of
Water and Power to provide integration services of up to 270 MW, leveraging our quick-responding
natural gas-fired Hermiston Power Project located in Hermiston, Oregon, as well as its contracted
transmission resources in the northwest as back up for wind generated power.
The last transaction is an indication of the need our customers and more generally the market will have to
utilize flexible natural gas-fired generation to assure reliability of supply while integrating intermittent
and variable renewable resources, such as wind and solar power, that they are required to procure as part
of a renewable energy portfolio.
6. Continued Strengthening of Our Balance Sheet — We have opportunistically completed several financing
transactions for a total of approximately $3.0 billion to improve our flexibility and management of our
balance sheet. Significant transactions in 2009 include, but are not limited to, the following:
• On November 24, 2009, we amended and extended our Steamboat project debt which extended the
maturity date from December 2011 to November 24, 2017.
• On December 11, 2009, we amended the letter of credit facility related to our subsidiary, Calpine
Development Holdings, Inc., to extend the maturity from January 31, 2010 to December 11, 2012,
with an option to increase the letters of credit available from $150 million to $200 million by
satisfying certain conditions.
6
• On August 20, 2009, we amended our First Lien Credit Facility and related collateral agency and
intercreditor agreement in several respects to give us greater flexibility, including allowing us to
exchange First Lien Credit Facility term loans for First Lien Notes.
• On October 21, 2009, we issued approximately $1.2 billion aggregate principal amount of First Lien
Notes in a private placement as a permitted debt exchange pursuant to our First Lien Credit Facility,
which retired an aggregate principal amount of term loans under our First Lien Credit Facility equal
to the aggregate principal amount of First Lien Notes issued. As a result of the issuance of the First
Lien Notes, we were able to extend the maturities of approximately $1.2 billion in debt to 2017, at the
same time converting it from a variable to a fixed interest rate.
• On May 19, 2009, our wholly owned subsidiaries, CCFC and CCFC Finance, issued approximately
$1.0 billion aggregate principal amount of CCFC New Notes in a private placement. The net proceeds
were used to repay the CCFC Term Loans, CCFC Old Notes and CCFCP Preferred Shares. As a
result of the CCFC Refinancing transactions, we were able to extend the maturities of approximately
$1.0 billion of debt by several years, at the same time converting it from a variable to a fixed interest
rate and lowering our effective interest rates.
• On January 21, 2009, we closed on our Deer Park $156 million senior secured credit facilities, which
included a $150 million term facility and a $6 million letter of credit facility. Proceeds received were
used to settle an existing commodity contract of approximately $79 million, pay financing and legal
fees, fund additional restricted cash and for general corporate purposes.
THE MARKET FOR POWER
Overview
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 $357.1 billion in power sales in 2009 based on information
published by the EIA. Historically, vertically integrated power utilities with monopolistic control 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 independent wholesale power producers to compete to provide the power needed by customers
in many states. Although different regions of the country have very different models and rules of competition, all
of the markets in which we operate have some form of wholesale market competition. California (included in our
West segment) and Texas, which are two of our largest markets, have emerged as among the most competitive
wholesale markets in the U.S. We also operate, to a lesser extent, in the competitive PJM, ISO NE and NYISO
markets.
We produce several products for sale to our customers.
•
•
•
First, we produce power for sale to utilities, municipalities, retail power providers, independent
electric system operators, large end-use industrial or agricultural processing customers or power
marketers.
Second, we produce steam for sale to customers for use in industrial or other heating, ventilation and
air conditioning operations.
Third, we sell regulatory capacity. In various regional 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, which allows them to attribute the approved capacity of
existing power plants to satisfy the obligation. Electricity market administrators have acknowledged
7
that the markets for generating capacity do not provide sufficient revenues to enable existing
merchant generators to recover all of their costs or to encourage new generating capacity to be
constructed. Capacity auctions have been implemented in the northeast, mid-Atlantic and some
mid-west regional markets to address this issue. California has a bilateral capacity program. Texas
does not have a capacity market and there is no concrete proposal under consideration by the
regulators.
Fourth, we provide ancillary service products to wholesale power markets. These products include the
right for the purchaser to call on our generation units to provide flexibility to the market. As an
example, we are sometimes paid to reserve a portion of some capacity at some of our power plants
that could be deployed quickly should there be an unexpected increase in load.
Fifth, we sell RECs from our Geysers Assets in northern California. 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.
•
•
Although all of the products mentioned above contribute to our financial performance, the most important
is our sale of wholesale power whether by contract for some term or on a merchant basis into the spot market.
Our Power Market Economics
The market spark spread, sales of RECs, revenues from our steam sales and the results from our
marketing, hedging and optimization activities are the primary components of our Commodity Margin and
contribute significantly to our financial results. Our Commodity Margin from power and steam sales is largely
determined by the pricing associated with our customer contracts. For power that is not sold under customer
contracts, the short-term and spot market supply and demand fundamentals determine the sale price for our
power. All of our steam production is sold under long-term contracts with industrial customers or steam hosts.
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 units with lower costs
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. Our fleet is modern and more efficient than the average generation fleet; accordingly, we run more and
earn incremental margin in markets in which less efficient natural gas units frequently set the power price. In
such cases, our margin is positively correlated with how much more efficient our fleet is than our competitors’
fleets and with higher natural gas prices. Much of our generating capacity is in our West and Texas segments,
which are regional markets where natural gas-fired units set prices during most hours, although incremental
renewable generation has moderated this dynamic somewhat in off-peak hours over the last year. Due to natural
gas prices generally (although not always) being higher than most other input fuels for power production per
MMBtu, these regions generally have higher power prices than regions where coal-fired units set power prices.
Outside of the California (included in our West segment) and Texas markets (and some northeast markets), other
generating technologies, typically coal-fired power plants, tend to set power prices more often, reducing average
prices and our Commodity Margin.
Reserve Margins — Reserve margin, a measure of how much excess generation capacity is present 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. Holding other factors
constant, lower reserve margins typically lead to higher power prices because the less efficient capacity in the
8
region would be needed to satisfy power demand. Markets with tight demand and supply conditions often display
price spikes and improved bilateral contract 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.
Natural Gas Prices and Supply — Our fuel requirements are predominantly met with natural gas. We
procure natural gas from multiple suppliers and transportation sources. Although availability is generally not an
issue, localized shortages, transportation availability and supplier financial stability issues can and do occur.
In markets where natural gas is often the price-setting fuel, such as in Texas and California, increases in
natural gas prices may increase our unhedged Commodity Margin in any given year because our combined-cycle
power plants in those markets are more fuel-efficient than conventional gas-fired technologies and peaker power
plants. Conversely, decreases in natural gas prices tend to decrease our unhedged Commodity Margin. In other
cases, changes in natural gas prices can have a neutral impact on us in the short term, such as where we have
entered into tolling agreements under which the customer provides the natural gas and in return 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 may also affect our liquidity as we could
be required to post additional cash collateral or letters of credit during periods of increasing natural gas prices.
Despite some of these short-term dynamics, over the long run, more moderate natural gas prices may actually
enhance 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 could have 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 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 our third fiscal quarter during the summer months. 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 — Efficient operation of our fleet creates the opportunity to capture
Commodity Margin in a cost effective manner. However, unplanned outages during periods of positive
Commodity Margin can result in a loss of that opportunity. We generally 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 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.
Market Fundamentals
For much of the 1990’s, utilities invested relatively sparingly in new generating capacity. As a result, by the
late 1990’s, many regional markets had low reserve margins and were in need of new capacity to meet growing
power demand. Prices rose due to capacity shortages, and the emerging merchant power industry responded by
constructing significant amounts of new capacity. Between 2000 and 2003, more than 175,000 MW of new
generating capacity came “on line” in the U.S. In most regions, these capacity additions far outpaced the growth of
demand, resulting in “overbuilt” markets, that is, markets with excess capacity. In the West, for example,
approximately 24,000 MW of new generating capacity was added between 2000 and 2003, while demand only
increased by approximately 8,000 MW. This surge of generation investment subsided after 2003. Recent investment
in new generation capacity over the last several years has occurred, but on a smaller scale.
During 2009, the general supply and demand fundamentals were negatively impacted by the combination
of recent new generation investment coming on line and a general decline in weather adjusted load year-over-
year due to the economic recession. Lower weather adjusted demand and higher supply would, in a normal
9
weather year, lead to higher reserve margins and lower Market Heat Rates. While Texas and California
experienced very hot weather at certain times during 2009, which somewhat compensated for these fundamental
demand shifts, this was not the case across the U.S. Although it appears that the load is now returning in several
markets with the beginning of an economic recovery, it remains early in the recovery and it remains unclear from
current data sources how our future supply and demand fundamentals will be impacted. Reserve margins by
NERC region in 2009 for each of our segments are listed below:
West:
WECC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
28.2%
Texas:
TRE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
15.8%
Southeast:
SERC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SPP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
23.9%
14.7%
North:
NPCC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MRO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
RFC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
25.5%
21.8%
27.0%
Lower natural gas prices represent one of the biggest factors impacting the power industry in 2009.
Monthly average natural gas prices (NYMEX, Henry Hub) generally fluctuated between $6/MMBtu —
$8/MMBtu in 2007 and $6/MMBtu — $13/MMBtu in 2008 with spikes during the months of April through July
of $10/MMBtu — $13/MMBtu. In 2009, we experienced a significant decrease in monthly average natural gas
prices from a high of $5.35/MMBtu in December 2009 to a low of $3.31/MMBtu in August 2009.
Natural gas prices in some parts of the country in 2009 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. Owners of modern combined-cycle natural gas-fired fleets,
like ours, experienced
significantly increased production in the southeast and some other parts of the eastern U.S.
Although some of this lower pricing dynamic can certainly be attributed to the recent economic recession
(power load and natural gas demand fell off with the economic recession even while new resources were coming
on line), there is a growing school of thought that the availability of non-conventional natural gas supplies, in
particular shale gas, could have a longer-term and more profound impact on natural gas markets. The U.S.
Department of Energy estimates that shale 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 reserves to supply the U.S. for the next 90
years. Accordingly, there is an emerging view of potentially lower priced natural gas for the medium to long-
term future.
In addition to the immediate effects of weather and lower priced natural gas on our supply and demand
fundamentals, several other key factors, especially regulatory factors, are emerging that could impact the
wholesale power market fundamentals. We believe that we will be favorably impacted by these factors based
upon the characteristics of our power plant portfolio. These factors include, but are not limited to:
•
•
increased penetration of power generated from renewable sources;
increasing environmental pressures on generation, especially pressures on high GHG, NOx and Hg
emitting resources. A significant portion of the capacities within the regions we operate include
capacities from older, less efficient fossil-fuel power plants that emit much higher amounts of GHG,
NOx and Hg which we anticipate will be more negatively impacted by future potential GHG or other
10
air emission legislation. The estimated amounts of MW capacity for plants which are older than 50
years by NERC region are as follows:
West:
WECC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3,981 MW
Texas:
TRE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,354 MW
Southeast:
SERC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SPP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
17,362 MW
3,581 MW
North:
NPCC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MRO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
RFC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4,543 MW
3,015 MW
18,943 MW
•
•
•
an increasing focus in some markets, including California, on limiting the impact of using once-
through cooling technology that can be harmful to aquatic life;
an increasing focus by utilities on demand side management – managing the absolute level and timing
of power usage such as “smart grid” technologies that improve the efficiencies, dispatch usage and
reliability of electric grids; and
increasingly onerous permitting requirements,
markets.
including those in California, one of our major
With the exception of demand side management, many of these trends are generally positive for the
economic outlook of a modern, flexible natural gas-fired fleet. For a discussion of federal, state and regional
legislative and regulatory initiatives and how they might affect us, see “— Governmental and Regulatory
Matters.”
Ultimately, it is very difficult to predict the continued evolution of our markets due to the uncertainty of
the following:
•
•
•
•
•
•
•
•
•
•
number of market participants buying and selling;
amount of power normally available in the market;
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 used by generators, 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 and constructing new power plants;
availability and cost of power transmission;
creditworthiness and other risks associated with counterparties;
bidding behavior of market participants;
regulatory and ISO guidelines and rules;
11
structure of the commercial products transacted; and
ability to optimize the market’s mix of alternative sources of power such as renewable and
hydroelectric power.
•
•
Hedging
We seek to actively manage the commodity price risk to our economic performance with a variety of
tools, including the use of PPAs and other long-term contracts for the sale of both power and steam. We also
pursue other long-term sales opportunities, as well as shorter term market transactions, including bilateral
originated sales contracts, and purchase and sale of exchange-traded instruments. We actively monitor key
commodity price risks such as Market Heat Rate and natural gas price exposure, as well as other risks related to
the value of our generation such as regulatory capacity, REC and emission credit pricing. The relative quantity of
our products sold under longer term contracts compared to the quantity subject to shorter term price fluctuations
is determined by our need to manage our liquidity, the availability of forward product sales opportunities, and
our view of the attractiveness of the pricing available for forward sales. It is our strategy to seek stronger bilateral
relationships and longer term contracts with load serving entities that can benefit us and our customers.
We provide more detail on our hedging programs in “— Marketing, Hedging and Optimization
Activities” below.
COMPETITION
Wholesale power generation is a capital-intensive, commodity-driven business with numerous industry
participants. We compete against other independent power producers, power marketers or 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. In addition, in some markets, we compete against some of our customers.
In less regulated markets, such as California and Texas, our natural gas-fired power plants compete
directly with all other sources of power. Even though most new power plants are fueled by natural gas, the EIA
estimates that in 2009 only 24% of the power generated in the U.S. was fueled by natural gas and that
approximately 65% of power generated in the U.S. was still produced by coal and nuclear facilities, which
generated approximately 45% and 20%, respectively. The EIA estimates that the remaining 11% 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 how our business is regulated. The federal government is
expected to take action on climate change legislation, as well as other air pollutant emissions, and many states
and regions in the U.S. have implemented or are considering implementing regulations to reduce GHG
emissions. Although we cannot predict the ultimate effect any future climate change legislation or regulations
could have on our business, as a clean energy provider, we believe that we are well positioned on a net basis for
potential regulation of 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.”
As environmental regulations continue to evolve, the proportion of power generated by natural gas and
other low emissions resources is expected to increase in most markets. As a result, many of the existing coal-
fired power plants will likely have to install costly emission control devices or limit their operations. 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.
12
Competition from other sources of power, such as nuclear energy and renewables, is expected to increase
in the future. The combination of emerging air emissions regulations, federal and state financial incentives and
RPS requirements for renewables are expected to result in increased investment in cleaner sources of generation,
which could also cause some coal-fired power plants to be retired, thereby allowing a greater proportion of power
to be produced by power plants fueled by natural gas, nuclear, wind, solar, hydroelectric, geothermal or other
resources that have a less adverse environmental impact. Generation quantities from nuclear power plants and
renewable sources are not available in the quantities needed to meet energy demand. There are permitting
hurdles, long lead times and general resistance to nuclear generation and 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, longer-term, natural gas is still needed as baseload and “back-up” generation.
We believe our ability to compete effectively in our environment will be substantially driven by the
extent to which we are able to accomplish the following:
• maintain excellence in operations;
•
•
•
•
achieve and maintain a lower cost of production, primarily by maintaining unit availability and
efficiency;
benefit from future environmental regulation and legislation;
effectively manage and accurately assess our risk; and
provide reliable service to our customers.
MARKETING, HEDGING AND OPTIMIZATION ACTIVITIES
The majority of our marketing, hedging and optimization activities are related to risk exposures that arise
from our ownership and operation of power plants. Most of the power generated by our power plants is sold,
scheduled and settled by our energy marketing unit, which sells to entities such as 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 enter into physical and financial purchase
and sale transactions as part of our marketing, hedging and optimization activities. Our marketing, hedging and
optimization activities endeavor to protect and enhance our Commodity Margin.
We are one of the largest consumers of natural gas in the U.S. having consumed approximately 650 Bcf
(billion cubic feet) during 2009. We employ a variety of market transactions to satisfy most of our natural gas
fuel requirements. We enter into long-term, short-term and spot natural gas purchase agreements, as well as
storage and transport agreements, to achieve delivery flexibility and to enhance our optimization capabilities. We
continually evaluate our natural gas needs, adjusting our natural gas position in an effort to minimize the
delivered cost of natural gas, while adjusting for risk within the limitations prescribed in our commodity risk
policy.
We are exposed to commodity price volatility in the markets in which our power plants operate. Natural
gas prices and power prices are generally correlated in our two primary markets, California and Texas, because
power plants using natural gas-fired technology tend to be the marginal or price-setting generation units in these
regions. We actively seek to manage the commodity risks of our portfolio, using multiple strategies of buying
and selling power or natural gas to manage our spark spread, or selling Heat Rate transactions. We use derivative
instruments, 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) for the purchase and sale of power, natural gas, and
emission allowances to manage commodity price risk and to maximize the risk-adjusted returns from our power
13
and natural gas assets. We also use interest rate swaps to manage the interest rate risk of our variable rate debt.
We conduct these 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,
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.
Along with our portfolio of hedging transactions, we enter into power and natural gas positions that often
act as hedges to our asset portfolio, but do not qualify as hedges under hedge accounting guidelines, such as
commodity options transactions and instruments that settle on power price to natural gas price relationships (Heat
Rate swaps and options). While our selling and purchasing of power and natural gas is mostly physical in nature,
we also engage in marketing, hedging and optimization activities, particularly in natural gas, that are financial in
nature.
While we enter into these transactions primarily to provide us with improved price and price volatility
transparency, as well as greater market access, which benefits our hedging activities, 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 either hedge accounting or the normal
purchase normal sale exemption are recognized currently in earnings in mark-to- market activity within operating
revenues in the case of power transactions, and within fuel and purchased energy expense in the case of natural
gas transactions.
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 commodity risk policy which is approved by our Board of Directors and by
our Risk Management Committee comprised of members of our senior management and administered by our
Chief Risk Officer and his organization. The Chief Risk Officer’s organization is segregated from the
commercial operations unit and reports directly to our Audit Committee and Chief Executive Officer. Our risk
management policies limit our hedging activities to protect and optimize the value of our physical assets. While
this policy limits our potential upside from hedging activities, it is primarily intended to provide us with a degree
of protection from significant downside energy commodity price exposure to our cash flows.
We actively monitor and hedge our portfolio exposure to future market risks. As of December 31, 2009,
we have economically hedged a substantial portion of our generation and natural gas portfolio mostly through
power and natural gas forward physical and financial transactions for 2010; however, we remain susceptible to
significant price movements for 2011 and beyond. By entering into these transactions, we are able to
economically hedge a portion of our spark spread at pre-determined generation and price levels. Our future
hedged status and marketing and optimization activities are subject to change as determined by our commercial
operations group, Chief Risk Officer, Risk Management Committee of senior management and Board of
Directors.
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 is our fiscal third 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 18 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.
14
DESCRIPTION OF OUR POWER PLANTS
Geographic Diversity
Dispatch Flexibility
North
3,417 MW
14%
Southeast
6,083 MW
24%
West
7,910 MW
32%
Texas
7,392 MW
30%
Peaking
5,000 MW
20%
Baseload
4,114 MW
17%
Intermediate
15,688 MW
63%
15
Power Plants in Operation at December 31, 2009
We operate 77 power plants, with an aggregate operating generation capacity of approximately 24,802
MW.
Natural Gas-Fired Fleet
Our natural gas-fired power plants utilize two types of design: 3,216 MW of simple-cycle combustion
turbines and 20,861 MW of combined-cycle combustion turbines. Simple-cycle combustion turbines burn natural
gas to spin a single turbine to generate power. A combined-cycle combusts as a simple-cycle and also uses the
exhaust heat from the simple-cycle combustion to help 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 2009 for the power plants we operate was 7,263 Btu/KWh which results in a
power conversion efficiency of approximately 47%. The power conversion efficiency is a measure of how
efficiently a fossil fuel power plant converts thermal energy to electrical energy. Our “all in” 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
cogeneration 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 31% to 36%.
Each of our power plants currently in operation is capable of producing power for sale to a utility, other
third-party end user or an intermediary such as a marketing company. At some of our power plants we also produce
thermal energy (primarily steam and chilled water), which can be sold to industrial and governmental users.
Our natural gas fleet is relatively young with a weighted average age, based upon MW capacities in
operation, of approximately eight 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 independent power sector.
The majority of the combustion turbines in our fleet are one of two technologies: GE 7FA or Siemens 501FD
turbines. We maintain our fleet through a regular and rigorous maintenance program. As units reach certain targets
recommended by the original equipment manufacturer, which are typically based upon service hours, we perform the
maintenance that is required for that unit at that stage in its life. Our large fleet of similar technologies has enabled us
to build significant technical and engineering experience with these units. We leverage this experience by performing
much of our major maintenance ourselves with our Turbine Maintenance Group subsidiary.
Geothermal
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 nine 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 97% in 2009.
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
16
wastewater from the City of Santa Rosa Recharge Project and from Lake County. We currently receive an
average of 15 million gallons of reclaimed wastewater a day which is injected into the steam reservoir to
replenish the natural steam withdrawn for the production of power. As a result, steam flow decline rates have
become very small. 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.
We periodically obtain independent geothermal studies to help us assess the economic life of our
geothermal reserves. Our most recent independent geothermal reserve study was conducted in 2006. Our
evaluations of our geothermal reserves, including our review of any applicable independent studies conducted,
indicate that our Geysers Assets should continue to supply sufficient steam to generate positive cash flows at
least through 2050. In reaching this conclusion, our evaluation, consistent with the 2006 study, 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 used as our “given date forward” our projected schedule of development, operation and
investment for the period 2006 to 2050.
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 2009 is:
•
•
•
29% related to leases with the federal government via the Minerals Management Service,
27% related to leases with the California State Lands Commission, and
44% 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.
17
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. We are currently involved in litigation concerning our Glass Mountain leases and
expect further developments related to this litigation in 2010. See Note 17 of the Notes to Consolidated Financial
Statements for a description of litigation relating to our Glass Mountain area leases.
Table of Operating Power Plants and Projects Under Advanced Development
Set forth below is certain information regarding our operating power plants and projects under advanced
development as of December 31, 2009.
SEGMENT / Power Plant
WEST
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)
2009
Total
MWh
Generated(4)
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
Rocky Mountain Energy Center . . . . . . . . . . . . WECC
Hermiston Power Project
. . . . . . . . . . . . . . . . . WECC
. . . . . . . . . . . . . . . . . . . WECC
Metcalf Energy Center
Sutter Energy Center . . . . . . . . . . . . . . . . . . . . . WECC
Los Medanos Energy Center . . . . . . . . . . . . . . . WECC
South Point Energy Center . . . . . . . . . . . . . . . . WECC
Blue Spruce Energy Center . . . . . . . . . . . . . . . . WECC
Los Esteros Critical Energy Facility . . . . . . . . . WECC
Gilroy Energy Center
. . . . . . . . . . . . . . . . . . . . WECC
Gilroy Cogeneration Plant . . . . . . . . . . . . . . . . . WECC
King City Cogeneration Plant . . . . . . . . . . . . . . WECC
Pittsburg Power 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
Watsonville (Monterey) Cogeneration Plant . . . WECC
Agnews Power Plant . . . . . . . . . . . . . . . . . . . . . WECC
Otay Mesa Energy Center(5)
. . . . . . . . . . . . . . . WECC
Subtotal . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Geothermal
Geothermal
Geothermal
Geothermal
Geothermal
Geothermal
Geothermal
Geothermal
Geothermal
Geothermal
Geothermal
Geothermal
Geothermal
Geothermal
Geothermal
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CO
OR
CA
CA
CA
AZ
CO
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
CA
18
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%
100%
100%
100%
100%
100%
78
69
66
66
53
52
52
51
50
48
43
42
24
17
14
835
750
479
547
564
542
506
520
—
—
—
117
120
64
50
49
—
—
—
—
—
—
—
—
29
28
513
78
69
66
66
53
52
52
51
50
48
43
42
24
17
14
857
729
621
616
605
578
560
530
310
188
141
128
120
64
50
49
48
47
47
47
47
47
47
44
29
28
608
689,757
589,538
493,338
524,822
407,495
425,813
402,385
420,978
394,322
484,393
341,975
299,430
222,485
144,098
108,608
5,032,618
4,979,649
3,543,289
3,466,313
2,797,458
2,315,457
3,391,651
2,076,629
419,361
73,098
59,523
262,270
629,617
125,190
223,474
234,211
19,186
31,083
27,255
12,283
13,696
11,791
18,471
16,316
153,505
150,060
774,104
6,438
7,910 36,806,995
SEGMENT / Power Plant
TEXAS
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)
2009
Total
MWh
Generated(4)
Freestone Energy Center . . . . . . . . . . . . . . . . . . TRE
Deer Park Energy Center . . . . . . . . . . . . . . . . . . TRE
Baytown Energy Center
. . . . . . . . . . . . . . . . . . TRE
Pasadena Power Plant . . . . . . . . . . . . . . . . . . . . TRE
Magic Valley Generating Station . . . . . . . . . . . TRE
Brazos Valley Power Plant . . . . . . . . . . . . . . . . TRE
Channel Energy Center . . . . . . . . . . . . . . . . . . . TRE
Corpus Christi Energy Center . . . . . . . . . . . . . . TRE
Texas City Power Plant . . . . . . . . . . . . . . . . . . . TRE
Clear Lake Power Plant . . . . . . . . . . . . . . . . . . . TRE
Hidalgo Energy Center . . . . . . . . . . . . . . . . . . . TRE
Freeport Energy Center(6)
. . . . . . . . . . . . . . . . . TRE
Subtotal . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SOUTHEAST
Broad River Energy Center . . . . . . . . . . . . . . . . SERC
Morgan Energy Center . . . . . . . . . . . . . . . . . . . SERC
Decatur Energy Center . . . . . . . . . . . . . . . . . . . SERC
Columbia Energy Center . . . . . . . . . . . . . . . . . . SERC
Carville Energy Center . . . . . . . . . . . . . . . . . . . SERC
Santa Rosa Energy Center . . . . . . . . . . . . . . . . . SERC
Hog Bayou Energy Center
. . . . . . . . . . . . . . . . SERC
Pine Bluff Energy Center . . . . . . . . . . . . . . . . . SERC
Oneta Energy Center . . . . . . . . . . . . . . . . . . . . . SPP
Osprey Energy Center . . . . . . . . . . . . . . . . . . . . FRCC
Auburndale Peaking Energy Center . . . . . . . . . FRCC
Subtotal . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NORTH
Riverside Energy Center . . . . . . . . . . . . . . . . . . MRO
RockGen Energy Center . . . . . . . . . . . . . . . . . . MRO
Mankato Power Plant
. . . . . . . . . . . . . . . . . . . . MRO
Westbrook Energy Center . . . . . . . . . . . . . . . . . NPCC
Kennedy International Airport Power Plant
. . . NPCC
Bethpage Energy Center 3 . . . . . . . . . . . . . . . . . NPCC
Bethpage Power Plant . . . . . . . . . . . . . . . . . . . . NPCC
Bethpage Peaker . . . . . . . . . . . . . . . . . . . . . . . . NPCC
Stony Brook Power Plant
. . . . . . . . . . . . . . . . . NPCC
Whitby Cogeneration(7) . . . . . . . . . . . . . . . . . . . NPCC
Greenfield Energy Centre(8) . . . . . . . . . . . . . . . . NPCC
Zion Energy Center . . . . . . . . . . . . . . . . . . . . . . RFC
Subtotal . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total operating power plants (77) . . . . .
Projects under advanced development
TX
TX
TX
TX
TX
TX
TX
TX
TX
TX
TX
TX
SC
AL
AL
SC
LA
FL
AL
AR
OK
FL
FL
WI
WI
MN
ME
NY
NY
NY
NY
NY
ON
ON
IL
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
78.5%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
100%
50%
50%
100%
1,038
799
740
753
662
508
463
426
400
344
392
210
6,735
—
720
782
455
449
235
235
184
980
537
—
994
970
800
771
692
594
608
500
453
400
374
236
3,263,701
5,686,340
3,893,026
2,929,281
3,057,649
2,374,891
2,645,794
2,316,051
1,451,085
508,920
1,560,341
1,404,067
7,392 31,091,146
847
807
795
606
501
225
237
215
1,134
599
117
351,868
4,250,780
3,043,345
43,660
2,443,567
168,387
262,423
1,340,696
2,981,783
2,459,755
24,167
4,577
6,083 17,370,431
518
—
280
537
110
60
55
—
45
25
422
—
603
503
375
537
121
80
56
48
47
25
519
503
974,899
147,930
337,542
2,485,501
503,650
288,799
108,362
37,662
251,868
86,057
1,326,829
112,894
2,052
19,802
3,417
6,661,993
24,802 91,930,565
Russell City Energy Center . . . . . . . . . . . . . . . . WECC
Los Esteros Critical Energy Facility
(Upgrade)
. . . . . . . . . . . . . . . . . . . . . . . . . . . WECC
CA
CA
Natural Gas
Natural Gas
65%
100%
362
120
390
120
n/a
n/a
Total operating power plants and
projects . . . . . . . . . . . . . . . . . . . . . . . . .
20,284
25,312
(1) Natural gas-fired fleet capacities are 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.
19
(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) Otay Mesa Energy Center began commercial operation on October 3, 2009, and is an unconsolidated
subsidiary (see Note 4 of the Notes to Consolidated Financial Statements).
(6) Freeport Energy Center is owned by us; however, it is contracted and operated by The Dow Chemical
Company.
(7) We hold a less-than-majority owned (50%) equity interest in Whitby Cogeneration; however, it is operated
by Atlantic Packaging Products Ltd., and is an unconsolidated subsidiary (see Note 4 of the Notes to
Consolidated Financial Statements).
(8) We hold a 50% joint venture interest in Greenfield Energy Centre; however, it is operated by a third party,
and is an unconsolidated subsidiary (see Note 4 of the Notes to Consolidated Financial Statements).
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.
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 provides that the obligations to pay interest
and principal on the loans and 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 under certain of our debt instruments, including our First Lien Credit Facility and
First Lien Notes. 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.
Projects Under Advanced Development and Planned Upgrades at December 31, 2009
The development and construction of power generation projects involves numerous elements, including
evaluating and selecting development opportunities, designing and engineering the project, obtaining PPAs,
acquiring necessary land rights, permits and fuel resources, obtaining financing, procuring equipment and
managing construction. We generally expect to start development or construction on new projects only in cases
where power contracts and financing are available and attractive returns are expected.
Russell City Energy Center — This is a proposed 600 MW, natural gas-fired power plant to be located in
Hayward, California. In September 2006, we sold a 35% equity interest in the project to Aircraft Services for
approximately $44 million and Aircraft Services’ obligation to post a $37 million letter of credit. We own the
20
remaining 65% interest. Under the LLC agreement with Aircraft Services, Aircraft Services’ equity is to be
applied toward completion of development and construction of the power plant, and Aircraft Services is also to
provide related credit support for the project.
Russell City Energy Center remains under advanced development. The Russell City Energy Center is
currently contracted to deliver its full output to PG&E under a PPA, which was executed in December 2006 and
approved by the CPUC in January 2007. The PPA was amended in 2008 and was approved by the CPUC on
April 16, 2009. On February 4, 2010, we received the PSD air permit, the final permit necessary, to begin
construction of our Russell City Energy Center. Russell City Energy Center is intended to become the first power
plant in the U.S. with a federal limit on GHG emissions, and will be designed to operate in a way that produces
25% fewer GHG emissions than the CPUC standard. The power plant 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. We hope to
complete financing and break ground for this new state-of-the-art power plant during 2010 with commercial
operations scheduled to begin in 2013. Upon completion, this project would bring on line approximately 362
MW of net interest baseload capacity (390 MW with peaking capacity) representing our 65% interest.
Los Esteros Critical Energy Facility Upgrade — We and PG&E negotiated a new agreement, subject to
regulatory approval, to replace the existing CDWR contract and facilitate the upgrade of our Los Esteros Critical
Energy Facility from a 188 MW simple-cycle generation power plant to a 308 MW combined-cycle generation
power plant. In addition to the increase in capacity, the upgrade will increase the efficiency and environmental
performance of the power plant by lowering the operating Heat Rate. While the upgrade is under construction,
we will provide capacity to PG&E from our Gilroy Cogeneration Plant. Upon completion of the upgrade, PG&E
will purchase all of the capacity from our Los Esteros Critical Energy Facility for a term of ten years.
Turbine Upgrades — We are in the process of upgrading certain of our Siemens natural gas-fired turbines
to increase our generation capacity by approximately 180 MW and operating efficiencies, which began in the
fourth quarter of 2009 and are scheduled through 2014. We have also upgraded the steam turbines at our McCabe
and Ridgeline geothermal power plants that improved the overall turbine efficiency. We have two additional
steam turbine upgrades scheduled for 2011 and 2012, and are considering others.
ENVIRONMENTAL PROFILE
A founding principle of our Company at its inception in 1984 and continuing today is our commitment to
the generation of power in a cost effective and environmentally responsible manner. To achieve this we have
assembled the largest fleet of combined-cycle natural gas-fired power plants and the largest fleet of geothermal
power plants in North America.
We are committed to maintaining our fleet of clean, cost-effective and efficient power plants and to
reducing the environmental impact through water conservation and the reduction of CO2 emissions as well as
emissions of other air pollutants. We are also committed to supporting policymakers on legislation to reduce CO2
emissions and other air emission policies, and have been actively involved in the discussions and debates within
the industry and with policymakers as GHG policies are developed. We were involved in the development and
enactment of Assembly Bill 32 in California, and we have publicly supported the Regional Greenhouse Gas
Initiative (known as RGGI) in the northeast. In 2006, we were one of only two power generating companies to
file a brief of amicus curiae in support of the petitioners in the landmark case of Commonwealth of
Massachusetts, et al. v. U.S. Environmental Protection Agency, in which the U.S. Supreme Court held that CO2
was a pollutant potentially subject to the CAA. Our environmental record has been widely recognized: we are an
EPA Climate Leaders Partner with a stated goal to reduce GHG emissions, we became the first power producer
to earn the distinction of Climate Action Leader™, and we have certified our CO2 emissions inventory with the
California Climate Action Registry every year since 2003.
21
Natural Gas-Fired Generation — Our fleet consumes significantly less fuel to generate power than
conventional boiler/steam turbine power plants and emits less air pollution into the environment per MWh of
power produced as compared to coal-fired or oil-fired power plants. All of our natural gas-fired 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 lower air pollutant emissions per MWh of power generated.
The table below summarizes approximate air pollutant emission rates from our natural gas-fired power plants
compared to the average emission rates from U.S. coal-, oil- and 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)
Calpine
Natural Gas-Fired,
Combined-Cycle
Power Plant(2)
Compared to
Average U.S. Coal-, Oil-,
and Natural Gas-Fired
Power Plant
2.54
5.90
0.000030
1,873
0.13
94.9% less
0.0047
99.9% less
—
869
100.0% less
53.6% less
Air Pollutants
Nitrogen Oxide, NOx . . . . . . . . . . . . . . . . . . . .
Acid rain, smog and fine particulate
formation
Sulfur Dioxide, SO2 . . . . . . . . . . . . . . . . . . . . .
Acid rain and fine particulate formation
Mercury Compounds(3) . . . . . . . . . . . . . . . . . .
Neurotoxin
Carbon Dioxide, CO2 . . . . . . . . . . . . . . . . . . . .
Principal GHG—contributor to climate
change
(1) The average U.S. coal-, oil- and natural gas-fired power plant’s emission rates were obtained from the U.S.
Department of Energy’s Electric Power Annual Report for 2008. Emission rates are based on 2008
emissions and net generation. The U.S. Department of Energy has not yet released 2009 information.
(2) Our natural gas-fired power plant estimated emission rates are based on our 2008 emissions and power
generation data from our natural gas-fired combined-cycle power plants (excluding combined heat and
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 U.S. EPA Toxics Release Inventory for 2008. Emission rates are based on 2008 emissions and net
generation from U.S. Department of Energy’s Electric Power Annual Report for 2008.
Geothermal Generation — Our 725 MW fleet of geothermal power plants utilizes a natural, clean and
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 gas-fired power plant, our Geysers Assets emit 99.9%
less NOx, 100% less SO2 and 94.8% 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 wastewater from local municipalities is recycled into the
geothermal resource where it is converted by the Earth’s heat into steam for power production.
Climate Change and CO2 Emissions — Our combined-cycle, natural gas-fired power plants emit less than
half the CO2 per unit of power generated than a traditional coal-fired power plant. Although our Geysers Assets
22
do produce some emissions due to a natural geological process, the compliance burden compared to both coal-
fired and natural gas-fired generation is expected to be minimal. In 2008, our emissions of CO2 amounted to
about 39 million tons. For a more complete discussion of federal, state and regional climate change legislative
and regulatory initiatives and how they might affect us, see “— Governmental and Regulatory Matters —
Climate Change and Related Legislation and Regulations.”
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 15 million gallons of reclaimed wastewater 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 11 million gallons is
received from the Santa Rosa Geysers Recharge Project, developed by us and the City of Santa Rosa,
which was previously being discharged into the Russian River and we receive, on average,
approximately 4 million gallons a day from The Lake County Recharge Project from Lake County.
• We use cooling towers, which utilize a closed-circuit water cooling system, or air cooled condensers
to condense steam and do not employ once-through water cooling. Once-through water cooling,
unlike our towers and condensers, uses large quantities of water from adjacent waterways, negatively
impacting aquatic life.
•
Through separate agreements with several municipalities where we use cooling towers, we use treated
wastewater for cooling at several of our power plants. This eliminates the need to consume valuable
surface and/or groundwater supplies, in the amount of three to four million gallons per day for an
average power plant.
GOVERNMENTAL AND REGULATORY MATTERS
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. Such changes could have positive or negative impacts on our existing business.
Climate Change and Related Legislation and Regulations
As a clean energy provider, we believe that we are well positioned on a net basis for potential regulation
of GHG emissions. The federal government is expected to take action on climate change legislation, and many
states and regions in the U.S. have implemented or are considering implementing regulations to reduce GHG
emissions. Although we cannot predict the ultimate effect any future climate change legislation or regulations
could have on our business, we believe we face a lower compliance burden than some of our competitors due to
the relatively low GHG emission rates of our fleet.
Proposed Federal Climate Change Legislation
On June 26, 2009, the U.S. House of Representatives passed “The American Clean Energy and Security
Act of 2009,” a climate change and clean energy bill. The legislation includes, among other provisions:
• An economy-wide carbon cap-and-trade program that:
i.
sets reduction targets for carbon emissions from capped sources in several sectors of the economy,
including the power sector, starting at a 3% reduction from 2005 levels by 2012, increasing to
17% by 2020, 42% by 2030 and 83% by 2050;
23
ii.
starts in 2012 for the power sector and establishes the point of regulation at the power plant;
iii. distributes 85% of emissions allowances for free, with 35.85% going to the power sector,
including 1.5% to eligible generation facilities with qualifying long-term power and steam sales
contracts;
iv.
v.
requires an auction of the remaining 15% of emissions allowances with the proceeds of such
auctions distributed to low- and moderate-income families; and
delegates authority to FERC to regulate the cash market in emissions allowances and offsets and
to the CFTC to regulate the associated derivatives market.
• A federal energy efficiency and renewable electricity standard which requires retail electricity
suppliers to meet the needs of a specific percentage of their load from renewable energy resources
and electricity savings.
If this bill were to become law, we would have the obligation to obtain emissions allowances for the
operation of our fossil-fuel power plants. While we expect the costs to acquire allowances to be a factor that will
impact the market price of power, there can be no assurance that market price will fully reflect these costs. With
respect to our existing long-term steam and power contracts under which we would not be able to recover costs to
acquire allowances from our customers, the bill allocates a pool of free allowances to generators with qualifying
contracts to mitigate such costs. However, there can be no assurance there will be a sufficient number of free
allowances in the pool to fully cover emissions related to generation under such contracts.
On November 5, 2009, the Senate Environment and Public Works Committee passed climate change
legislation entitled the Clean Energy Jobs and American Power Act. The legislation is similar to the legislation
passed in the House of Representatives, though its focus is primarily on climate change, not energy. The
legislation sets reduction targets for carbon emissions of 20% by 2020; distributes a substantial portion of
emission allowances for free, though a lower amount than in The American Clean Energy and Security Act of
2009, with some emission allowances going to the power sector, including to eligible power plants with
qualifying long-term power and steam sales contracts; requires an auction of 25% of emissions allowances with
the proceeds dedicated for consumer protections and deficit reduction; states that there will be one regulatory
body that has market oversight authority; directs the administrator of the EPA to establish an incentive payment
program that promotes generation projects that have lower GHG emissions; and provides grants for research and
development for advanced natural gas-fired generation technology.
The Senate is expected to continue considering legislation addressing climate change; however, it is
becoming less likely that such legislation will be enacted in 2010. Although we cannot predict the effect and
ultimate content of final climate change legislation and regulations, if any, on our business, we continue to
monitor and actively participate in the process where we anticipate an impact on our business.
Federal Regulation of GHG under Existing Law
On April 2, 2007, the U.S. Supreme Court ruled that the EPA has the authority to regulate GHG issues
under language included in the CAA, and due to this ruling, the EPA is moving forward to regulate GHG
emissions pursuant to its existing authority under the CAA. On December 7, 2009, the EPA determined that
current and projected concentrations of the six key GHG emissions endanger the public health and welfare of
current and future generations. Additionally, on September 30, 2009, the EPA announced a proposal (the
“Tailoring Rule”) to require facilities emitting over 25,000 tons per year of GHG emissions to undergo major
new source review when such facilities make modifications that would increase their GHG emissions by an
additional 10,000 to 25,000 tons. Such modifications, or new construction, would be subject to the EPA’s
prevention of significant deterioration rules and subject to best available control technology for GHGs, as well as
public review and notice. The EPA expects to finalize the proposed rule by the end of March 2010, and if
finalized, these requirements would be applicable to power generators such as us.
24
The federal courts have also been active on GHG emission issues. Recent federal court decisions are
divided as to whether large emitters of GHGs may be sued under common law theories of nuisance and
negligence.
On September 21, 2009, the Second Circuit issued a ruling in State of Connecticut, et al. v. American
Electric Power Company Inc., et al., 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 per year of CO2 and
these emissions are causing and will continue to cause serious harms 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 ruling and remanded the cases to the lower court for
further proceedings. On October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit made a similar ruling,
finding that private property owners may bring claims of public and private nuisance against GHG-emitting oil
and chemical companies.
Conversely, on September 30, 2009, in the case Native Village of Kivalina v. ExxonMobil, a federal
district court in California sided with the defendants, 24 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, Kivalina is subject to coastal storm waves and surges. The court ruled in favor of the defendants
finding that the plaintiff’s global warming claim was based upon the emission of GHGs from innumerable
sources located throughout the world affecting the entire planet and its atmosphere and that no federal standards
limit the discharge of GHGs.
We cannot predict the outcome of these cases or what impact the precedent of these cases could have on
our business. However, these contrasting outcomes show that the federal courts are sharply divided over climate
change litigation; thus, increasing the likelihood that Congress will take action on GHG regulations at some point
in the future.
Regional and State Climate Change 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 implementation of its own GHG policy pursuant to Assembly
Bill 32, as well as its RPS. The evolution of these programs could have a material impact on our business.
On January 1, 2009, ten northeast and mid-Atlantic states implemented a cap-and-trade program, RGGI,
that affects our power plants in Maine, New York and New Jersey (together emitting about 1.8 million tons of
CO2 annually). 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 public auction. RGGI auctions
have recently cleared at approximately $2.00 per ton. 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 received an allocation 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 impact from
RGGI, given the efficiency of our power plants in RGGI states.
California’s Assembly Bill 32 and Senate Bill 1368 were signed into law in September 2006. Assembly
Bill 32 creates a statewide cap on GHG emissions and requires the state to return to 1990 emission levels by
2020. As part of Assembly Bill 32 implementation, California’s cap-and-trade program is slated to begin in 2012.
Other GHG regulatory policies promulgated under Assembly Bill 32 are ongoing. California regulators and
industry participants continue to work on the regulations to implement Assembly Bill 32. We are an active
participant in the development of these regulations.
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California is in the process of determining how allowances will be allocated under its cap-and-trade
program. A committee of outside academic advisors to the California Air and Resources Board, or CARB, has
recommended that all allowances be auctioned. CARB will
take the committee’s recommendation under
advisement and will develop and approve its allowance allocation regulations over the course of 2010. Under a full
auction methodology, certain of our contracts may not allow GHG costs to be passed through to the customers.
Our other power plants may also become subject to state or regional CO2 compliance requirements. The
Western Climate Initiative, launched in February 2007, is a collaboration of seven U.S. Governors and four
Canadian Premiers to reduce GHG emissions and could affect our power plants in California, Arizona, Oregon and
Ontario. The Western Climate Initiative’s goal is to establish a multi-sector cap-and-trade program effective for
most sectors of the economy by 2012 and regulation of the transportation sector by 2015. Some partner states, such
as Arizona, have indicated their participation will be delayed or dependent on further economic analysis and
recovery. To date, California is the only state that has reaffirmed its commitment to its participation and a 2012
start. In the Midwest, our power plants in Illinois, Wisconsin and Minnesota may become subject to CO2
compliance requirements depending on the ultimate outcome of the Midwestern Greenhouse Gas Reduction
Accord. This regional planning effort is not expected to lead to binding regulations; however, compliance
requirements will be subject to prospective individual regulatory and/or legislative action by the participating states.
Renewable Portfolio Standards
Policymakers have been considering RPS at the federal and state level. Generally, a 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 energy resources by a certain date.
Although there is currently no national RPS, President Obama has stated his goal is to have 10% of the nation’s
electricity provided from renewable sources by 2012, and 25% by 2025, and U.S. Congressional leaders have
committed to pass legislation to enact a national RPS in this Congress. 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 assets,
primarily in Texas and California. Conversely, our natural gas power plants could benefit by providing
complementary/back-up service for these intermittent renewable resources.
California is currently considering a range of options for a new and higher RPS. California’s existing RPS
requires certain retail power providers to generate or procure 20% of the power they sell to retail customers from
renewable resources by 2010. At the end of the 2009 California legislative session, the California state legislature
passed a bill to increase the state’s RPS to 33% by 2020. The governor of California vetoed the bill, but, in a
separate move, the governor signed an executive order directing CARB under its authority granted by Assembly
Bill 32 to adopt regulations consistent with a 33% RPS by 2020. Implementation details of the executive order
are yet to be determined; however, it directs CARB to adopt regulations by July 31, 2010. The executive order
directed CARB to develop implementation details by January 1, 2010, a deadline which was not met. CARB is
now actively working to release the initial draft regulation in late February or early March.
Currently, California does not allow RECs and power to be sold separately. The role of tradable renewable
energy credits, or TRECs, in California’s RPS remains uncertain. TRECs are claims to the renewable aspect of the
energy that is produced by a renewable resource and are traded separately from the underlying generic energy. The
CPUC is considering whether to allow retail power providers to use TRECs to meet RPS requirements and what
types of limits to place on their use in the event that they are allowed. We cannot predict at this time whether the
CPUC will allow the use of TRECs or what impact, if any, TRECs could have on our business.
A number of additional states have a RPS in place. These include Maine, Minnesota, New York, Texas
and Wisconsin. Individual programs vary widely. Maine has the most stringent RPS, requiring retail providers to
supply no less than 30% of their needs with qualified renewable resources. Other states, such as Texas, have a
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capacity-based standard that requires a specific amount of new renewable generation to be installed by certain
dates. 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
Our power plants and the equipment necessary to support them are subject to 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 air, and the use of
water, but can also include wetlands 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. Our general policy with respect to these laws attempts to take
advantage of our relatively clean portfolio of power plants as compared to our competitors.
Clean Air Act
The CAA provides for
largely through state
implementation of federal requirements. We believe that all of our operating power plants comply with federal
and state performance standards mandated under the CAA. Several CAA programs that affect our power plants
and/or our competitors are discussed below.
the regulation of air quality and air emissions,
Section 185 Fees — Section 185 of the CAA requires major stationary sources of NOx and volatile
organic compounds, or VOC(s), such as power plants and refineries, in areas that fail to attain the National
Ambient Air Quality Standards, or NAAQS, for ozone by the attainment date to pay a fee to the state or in the
absence of state action, the EPA. The fee was set by Congress in the CAA at $5,000 per ton of NOx or VOC
(adjusted for inflation or approximately $8,750 per ton in 2008) and is payable on emissions that exceed 80% of
each individual power plant’s baseline emissions, which were established in the year before the attainment date;
however, the EPA is considering alternative baseline calculations. The fee will remain in effect until the
designated area achieves attainment. We operate 13 power plants that are located within designated
nonattainment areas in Texas, New York and Louisiana, which are subject to this fee. On January 5, 2010, the
EPA issued guidance on developing fee programs required under Section 185 of the CAA. Texas issued a draft
rulemaking to collect the fees in late 2009 and we provided comments on the draft in January 2010. We estimate
that compliance with this fee could result in additional costs of approximately $3 million to $5 million on an
annual basis and our financial statements include accruals for our estimated Section 185 fees. Our estimate is
dependent upon a number of factors that could change in the future dependent upon, among other things:
implementation by the states of guidance from the EPA, state rulemakings, the designation of nonattainment
status, our number of power plants located in these areas and our level of NOx emissions.
Hazardous Air Pollutants — On October 22, 2009, the EPA signed a consent decree that was lodged in
the U. S. District Court for the District of Columbia by the EPA in settlement of a suit brought by several
environmental groups alleging that the EPA failed to promulgate final maximum achievable control technology
emissions standards for hazardous air pollutants from coal- and oil-fired power plants, pursuant to Section 112(d)
of the CAA, by the statutorily-mandated deadline. The consent decree requires the EPA to promulgate final
maximum achievable control technology standards by November 2011 that will likely require mercury and acid
gas control retrofits on marginal coal-fired power plants to be operational by 2014.
On November 16, 2009, the EPA issued a proposal to increase the NAAQS for SO2. The proposal seeks
to replace the current annual and 24-hour standards with a new 1-hour standard at a level between 50 and 100
parts per billion. Final ruling is expected in June of 2010. We emit little SO2 and do not expect to experience
significant operating costs, or retrofit obligations, from the new standards. Should coal-fired power plants in our
regional markets be forced to retrofit or retire, the new standards could benefit our competitive position.
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Houston/Galveston Nonattainment — Pursuant to authority granted under the CAA, regulations adopted
by the Texas Commission on Environmental Quality, or 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 generating facilities
in the Houston/Galveston 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.
However, the EPA revised downward the eight-hour NAAQS for ozone in 2008 from 0.080 parts per million
(ppm) to 0.075 ppm. The EPA subsequently announced on September 16, 2009, that the protectiveness of this
standard would be reconsidered and a new standard was proposed in December 2009 leading to the
implementation of control measures as early as 2014 for existing and newly designated areas under the revised
ozone standard. The dynamic nature of the ozone standard creates further uncertainty in the timing and nature of
future controls, but should allowance shortfalls occur, we would be required to purchase NOx allowances or
install emissions control equipment on certain power plants.
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. None of our power plants receive free SO2
allowances. Accordingly, we must purchase allowances to cover all SO2 emissions from our affected power
plants and satisfy our compliance obligations. Since our entire fleet emits about 200 tons of SO2 per year, we
believe that our compliance expense for this program will be relatively insignificant compared to many of our
competitors.
Multi-Pollutant Programs — 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 standards issued in 1997. When fully
implemented, 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 establishes annual cap-and-trade programs for SO2 and NOx as well as a
seasonal program for NOx. On July 11, 2008, a panel of the U.S. Court of Appeals for 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 will be
positive. The court did not set a definitive deadline for re-promulgation of a new rule, but the EPA has indicated
that it will be issuing a CAIR replacement rule proposal in April 2010. At this time, we cannot predict what
impact this proposal will have on us, if any.
On February 4, 2010, bipartisan multi-pollutant legislation, the Clean Air Act Amendments of 2010, was
introduced in the Senate. The legislation, which replaces the Clean Air Interstate Rule and the Clean Air Mercury
Rule, sets forth new regulations for SO2, NOx and Hg calling for: 80% reduction in SO2 emissions by 2018; 53%
reduction in NOx emissions by 2015; and reductions in Hg emission of at least 90% by 2015. It establishes
nationwide trading programs for SO2 and NOx, and requires maximum achievable control technology for Hg
reductions. While sponsors of the legislation hope to move this bill with comprehensive climate change and
energy legislation, they also plan to push it independently if such legislation does not move forward this year. At
this time, we are unsure of the timing for movement of this bill.
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Clean Water Act
The federal Clean Water Act establishes rules regulating 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 certain of our power plants. We are required to maintain a spill prevention control and
countermeasure plan with respect to certain of our natural gas power plants. We believe that we are in material
compliance with applicable discharge requirements of the federal Clean Water Act.
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, or EPAct 2005, we use
geothermal re-injection wells to inject reclaimed wastewater back into the steam reservoir, which are subject to
this regulation. We believe that we are in material compliance with Part C of this Act.
Resource Conservation and Recovery Act
The Resource Conservation and Recovery Act, or 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 all such
laws.
Comprehensive Environmental Response, Compensation and Liability Act
The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also
referred to as 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.
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, or FPA, and PUHCA 1935. These statutes have been amended and supplemented by
including PURPA and EPAct 2005. These particular statutes and regulations are
subsequent
discussed in more detail below.
legislation,
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
the interlocking directorates, and the uniform system of accounts and reporting
interstate commerce,
requirements for public utilities.
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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.
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 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, or FUCOs. If any single Calpine entity 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 proposals will continue to evolve, and FERC may amend or revise them, or may
introduce new policies or proposals in the future. The impact of such policies and proposals 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. This
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 were 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 Regional Transmission Organization 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.
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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. 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.
An electric utility may be relieved of the mandatory purchase obligation to purchase power from QFs at
the utility’s avoided cost if FERC determines that such QFs have access to a competitive wholesale power
market. Some entities maintain that the launch of CAISO’s Market Redesign and Technology Upgrade provides
the access that should obviate the California utilities’ mandatory purchase obligation, and triggers changes in
energy pricing for California QFs pursuant to existing QF contracts. These issues remain the topic of extensive
stakeholder negotiation.
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 the Electric Reliability Organization and 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
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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 must comply with different reliability standards, requirements and procedural rules in each region in which
we operate. It is expected that additional or modified NERC and regional 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 and
Texas 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, 2009.
West
We have 27 natural gas-fired power plants, excluding one under advanced development, with the capacity
to generate a total of 7,185 MW in the WECC NERC region, which extends from the Rocky Mountains
westward. In addition, we own and operate 15 geothermal power plants located in 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 power plants in Arizona, Colorado and Oregon.
CAISO is responsible for ensuring the safe and reliable operation of the transmission grid within
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 reference prices are exceeded. 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 congestion hedging instruments, a centralized day-ahead commitment process and current bid
caps of $500 per MWh, which are scheduled to increase to $750 per MWh on April 1, 2010. 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.
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 12 natural gas-fired power plants in the TRE NERC region with the capacity to generate a total
of 7,392 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 is
largely a bilateral wholesale power market, which allows buyers and sellers to competitively negotiate contracts
for energy, capacity and ancillary services. ERCOT meets its system needs by using ancillary service capacity
and running a balancing energy service. ERCOT manages transmission congestion with zonal and intra-zonal
type methods. ERCOT ensures resource adequacy through an energy-only model rather than the capacity-based
resource adequacy model that is more common among Regional Transmission Organizations or ISOs in the
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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.
ERCOT’s implementation of a nodal market structure was scheduled to have been implemented in late
2008. However, in 2008, ERCOT announced that it would delay implementation. The PUCT initiated an effort to
refresh the original cost-benefit study analysis that had justified moving to a nodal design. Based on the refreshed
analysis, ERCOT states that it intends to implement nodal design at the end of 2010, which ERCOT’s latest
progress report on the nodal project indicates that it remains on schedule for a December 2010 implementation
date. We anticipate a neutral business impact on us, but we are not able to rule out other impacts.
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. The Sunset Review Process began in September
2009 for the PUCT and ERCOT. It is expected to be concluded by April 2010. The Texas Commission on
Environmental Quality, or TCEQ, review will begin in April 2010 and is scheduled to be completed by
November 2010 when the compliance phase for all agencies will begin. We will monitor the Sunset Review
Process of these entities and will seek to participate in these processes where we anticipate an impact on our
business.
On July 17, 2008, the PUCT tentatively approved a transmission build plan, the Competitive Renewable
Energy Zones, or CREZ, to expand the delivery of wind-generated power from western Texas to service
approximately 18,500 MW of planned wind generation. Wind generation tends to supply more power during
off-peak hours and shoulder months, and is unpredictable. The PUCT’s selection of transmission providers to
build the transmission lines was challenged in Texas state court, and on January 15, 2010 the court reversed and
remanded the PUCT’s order selecting certain companies to build the CREZ lines, finding that the PUCT erred in
its selection process. As a consequence of the state court’s ruling, the PUCT established a new docket to
reconsider its order selecting the transmission providers. We do not know what, if any, delay the court’s decision
will have on any CREZ project. If completed as currently approved, the impact of the transmission upgrades and
associated wind generation on our Texas plants is unknown.
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 a Regional Transmission Organization approved by FERC that provides
independent administration of the electric power grid. SPP manages an energy-only locationally based real-time
wholesale energy market. This market provides both nominal load-following and transmission constraint relief.
SPP stakeholders are considering the creation of a day-ahead market and ancillary service markets.
We have ten natural gas-fired power plants with the capacity to generate a total of 4,949 MW operating
within the SERC and the FRCC NERC regions. Opportunities to negotiate bilateral, individual contracts and
long-term transactions with investor owned utilities, 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, SPP has been designated as the Independent Coordinator of Transmission. In this
capacity, the Independent Coordinator of Transmission provides oversight of the Entergy transmission system.
North
We have a total of eight natural gas-fired power plants with the capacity to generate a total of 1,433 MW
located 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.
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Our remaining U.S.-based power plant in the NPCC NERC region is located in Maine. ISO NE is the
Regional Transmission Organization 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 in two power plants, which includes a 50% interest and a 50% joint venture,
with the total capacity to generate 1,088 MW, located in the NPCC NERC region in Ontario, Canada. The
Independent Electricity System Operator, or 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. Effective December 2009, the
IESO implemented several rule changes that are expected to impact the financial performance in 2010 and beyond
for Greenfield Energy Centre, our joint venture. Greenfield Energy Centre’s power supply contract with the Ontario
Power Authority, or OPA, provides it with a right to recovery for financial consequences of market rule changes
that negatively impact Greenfield Energy Centre. OPA has not yet agreed to accept responsibility for the changes
and discussions continue between the parties.
We have one operating power plant, with the capacity to generate 503 MW, located in PJM, which is
located in the RFC NERC region. However, it is partially committed to load in MISO. 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.
We have three natural gas-fired power plants with the capacity to generate a total of 1,481 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 tariff. MISO implemented a monthly voluntary
capacity auction to help purchasers find suppliers with capacity to meet their incremental capacity needs.
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 California Investor Owned Utilities, or 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. The
CPUC is in the process of considering modifications to the Resource Adequacy program, including the potential
introduction of a multi-year forward centralized capacity markets, similar to those that exist in ISO NE and PJM.
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
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transportation pipelines in Texas are subject to dual jurisdiction by FERC and the Texas Railroad Commission.
These pipelines are intrastate pipelines within the meaning of Section 2(16) of the Natural Gas Policy Act, or
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. Additionally, under the Natural Gas Act, or NGA, the NGPA and the Outer
Continental Shelf Lands Act, 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. FERC is also authorized under the NGA to regulate the sale of natural gas at wholesale.
FERC also has the authority to regulate the quality of LNG deliveries into the pipeline system. Unless
appropriate natural gas specifications are implemented, LNG supplies could impact in the future our power plant
operations and the ability to meet emission limits.
FERC has civil penalty authority for violations of the NGA and NGPA, as well as any rule or order issued
thereunder. 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 FERC’s jurisdiction, to engage in fraudulent or deceptive practices. Similar to its
penalty authority under the FPA described above, 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.
We also operate proprietary pipelines in California, which are regulated by the California Department of
Transportation with regard to safety matters but are otherwise not regulated.
CFTC Regulation of Power and Natural Gas and Possible Derivatives Legislation
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 price reporting and record retention. Thus, transactions executed on an ECM generally are not
regulated directly by the CFTC. However, 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.
On December 11, 2009, the House of Representatives passed the Wall Street Financial Reform and
Consumer Protection Act of 2009. The legislation includes provisions to regulate certain types of OTC
derivatives that we use. Included in the bill is a provision which clarifies the definition of a “major swap
participant” that would otherwise have left it to future CFTC interpretation and definition which could have put
more end users, such as us, under mandatory clearing, position limits and margin despite an end user exemption
in the underlying bill.
The Senate Banking Committee is attempting to work in a bipartisan manner to craft comprehensive
financial reform legislation. The committee has organized bipartisan working groups to address various aspects
of reform. The Senate Agriculture Committee also continues to work on drafting bipartisan legislation.
Geothermal Operations
In 2009, as part of a joint private and federally funded geothermal technology research project, a
company unrelated to us commenced deepening an existing geothermal well on a property neighboring our
35
Geysers Assets. The company was reportedly attempting to drill into the hot, low or non-permeable base rock
that underlies the existing geothermal steam reservoir at The Geysers to engineer or create a “multilayered heat
extraction system” below the reservoir by injecting water under very high pressure, fracturing the rock. This
process has spawned public and political concern regarding increased seismicity risk. As a consequence, in July
2009, the Department of Energy halted funding of its portion of that research project pending further seismicity
studies. In addition, the Department of Energy and residents located near our Geysers Assets have expressed
concern regarding induced seismicity associated with geothermal operations. Also, we have become aware of a
letter and petition to the Board of Supervisors County of Lake from a local community homeowners association
located near our Geysers Assets entitled a “Complaint and Petition” and signed by “109 residents and property
owners.” The letter asks for county intervention to abate alleged public nuisance arising from induced seismicity
by governmental legal action, including litigation, regulation and ordinances to prevent induced seismicity;
however, the letter also states it is not their intent to suspend our geothermal operations. In response to those
concerns, it is possible that government entities or agencies will seek to more stringently regulate the exploration,
development, and operation of geothermal power plants, including our Geysers Assets, in order to mitigate
induced seismicity resulting from geothermal operations.
EMPLOYEES
As of December 31, 2009, we employed 2,046 full-time employees, of whom 46 were represented by
collective bargaining agreements. We have never experienced a work stoppage or strike.
Item 1A. Risk Factors
Operations
A prolonged economic downturn could result in a reduction in our revenue, 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 the current economic downturn continues to affect the markets in which we operate,
demand for power and power prices may remain depressed, our revenues and operating cash flows could be
negatively impacted. In addition, challenges currently 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
power 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.
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 and natural gas 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:
•
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;
36
•
•
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;
•
•
•
•
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 of power;
regulations and actions of the ISOs; and
federal and state power market and environmental regulation and legislation, including mandating a
RPS or creating financial incentives, each resulting in new renewable energy generation capacity
creating oversupply.
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 ability to 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 power 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. 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 derivative 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.
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 in
accordance with GAAP, which requires us to record all derivatives on the balance sheet at fair value unless they
qualify for the normal purchase normal sale exemption. Changes in the fair value resulting from fluctuations in
the underlying commodity prices are immediately recognized in earnings, unless the derivative qualifies for, and
is designated as, cash flow hedge accounting treatment. Sudden commodity price movements could create
financial losses. Whether a derivative qualifies for cash flow hedge accounting treatment depends upon it
meeting specific criteria used to determine if the cash flow hedge is and will remain effective for the term of the
derivative. Economic hedges will not necessarily qualify for cash flow hedge accounting treatment, or for
economic hedges that currently qualify for cash flow hedge accounting treatment; we may lose cash flow hedge
accounting treatment in the future if the forecasted transactions are no longer considered probable of occurring.
As a result, we may be 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 results are subject to quarterly and seasonal fluctuations.
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 (see Note 19 of the Notes to Consolidated Financial Statements for our 2009 and
2008 quarterly operating results), including:
•
•
•
•
•
•
•
seasonal variations in power and natural gas prices and capacity payments;
seasonal fluctuations in weather, in particular unseasonable weather conditions;
production levels of hydroelectric power in the West;
variations in levels of production, including from both planned and unplanned outages;
availability of emissions credits;
natural disasters, wars, sabotage, terrorist acts, earthquakes, hurricanes and other catastrophic events;
and
the completion of development and construction projects.
In particular, a disproportionate amount of our total revenue has historically been realized during the third
fiscal quarter and we expect this trend to continue in the future as demand for power in our markets peaks in our
third fiscal quarter. If our total revenue were below seasonal expectations during that quarter, by reason of power
plant operational performance issues, cool summers, or other factors, it could have a disproportionate effect on
our annual operating results.
We rely on power transmission and natural gas 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 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.
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We may be unable to obtain an adequate supply of natural gas in the future at prices acceptable to us.
We obtain substantially all of our physical natural gas supply from third parties pursuant to arrangements
that vary in term, pricing structure, firmness and delivery flexibility. Our physical natural gas supply
arrangements must be coordinated with transportation agreements, balancing agreements, storage services,
financial hedging transactions and other contracts so that the natural gas 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 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 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 by our power plants including the following:
•
•
•
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 supply;
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 or availability of natural gas services (e.g. storage) may be
insufficient or available only at prices that are not acceptable to us;
•
•
natural gas quality variation may adversely affect our power plant operations; and
our natural gas operations capability may be compromised due to various events such as natural
disaster, loss of key personnel or loss of critical infrastructure.
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:
•
•
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; and
some of our competitors’ (mainly utilities) entitlement-guaranteed rates of return on their capital
investments, which returns may in some instances exceed market returns, may impact our ability to
sell our power at economical rates.
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.
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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. 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.
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. A successful claim against us that is not fully insured could have a material adverse effect on our
financial condition, results of operations and cash flows.
Our power plants and development 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 materially and adversely affect
our financial condition, results of operations and cash flows.
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:
•
•
•
•
•
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
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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.
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:
•
•
•
•
•
•
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.
Claims that some geothermal power plants cause increased risk of seismic activity could impact our
operating procedures and increase our operating costs or, delay or increase the cost of further development
at The Geysers.
In 2009, as part of a joint private and federally-funded geothermal technology research project, a
company unrelated to us commenced deepening an existing geothermal well on a property neighboring our
Geysers Assets. The company was reportedly attempting to drill into the hot, low or non-permeable base rock
that underlies the existing geothermal steam reservoir at The Geysers to engineer or create a “multilayered heat
extraction system” below the reservoir by injecting water under very high pressure, fracturing the rock. This
process has spawned public and political concern regarding increased seismicity risk. As a consequence, in
July 2009, the Department of Energy temporarily halted funding of its portion of that research project pending
further seismicity studies. Although our geothermal operations do not include attempts to engineer or create new
reservoirs from hot, low or non-permeable rock, the concerns regarding induced seismicity from geothermal
operations could delay or otherwise adversely impact our Department of Energy grant applications. Also, we
have become aware of a letter and petition to the Board of Supervisors County of Lake from a local community
homeowners association located near our Geysers Assets entitled a “Complaint and Petition” and signed by “109
41
residents and property owners.” The letter asks for county intervention to abate alleged public nuisance arising
from induced seismicity by governmental legal action, including litigation, regulation and ordinances to prevent
induced seismicity; however, the letter also states it is not their intent to suspend our geothermal operations. It is
possible that government entities or agencies will seek to more stringently regulate the exploration, development
and operation of geothermal power plants, including operations of our Geysers Assets, in order to mitigate
induced seismicity resulting from geothermal operations, or that operators of geothermal power plants could be
subject to property damage claims resulting from increased seismic activity. Any of these events could increase
the cost of operating the existing Geysers Assets and may delay or increase further exploration and any further
development of our Geysers Assets.
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, which has
led to tight liquidity in the power trading markets, putting downward pressure on prices.
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.
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. In addition, approximately 46 employees are represented by collective bargaining agreements.
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:
•
the cessation or abandonment of the development, construction, maintenance or operation of a power
plant;
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•
•
•
•
•
•
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
deadlines;
to obtain material permits and regulatory approvals by agreed-upon
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 power we generate from our existing portfolio is sold under long-term PPAs that expire at
various times. We also sell power under short- to intermediate-term (one day to five years) PPAs. 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 on the spot market 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 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 power generated by
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 (measured over the next five years).
The aggregate notional value of these PPAs is approximately $3.2 billion at December 31, 2009. Values for our
long-term commodity contracts are calculated using discounted cash flows derived as the difference between
contractually based cash flows and the cash flows to buy or sell similar amounts of the commodity on market
terms. Inherent
in these valuations are significant assumptions regarding future prices, correlations and
volatilities, as applicable. The aggregate value of such contracts could decrease in response to changes in the
market. We are at risk of loss in 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.
We may be subject to claims that were not discharged in our Chapter 11 cases, which could have a material
adverse effect on our results of operations and profitability.
On December 20, 2005 (the Petition Date), Calpine Corporation and 274 of its wholly owned U.S.
subsidiaries filed for voluntary petitions of relief under Chapter 11 of the Bankruptcy Code. From the Petition
Date through our emergence from Chapter 11 on the Effective Date (January 31, 2008), we operated as a
debtor-in-possession under the protection of the U.S. Bankruptcy Court. In general, all claims that arose prior to
the Petition Date and before confirmation of our Plan of Reorganization were discharged in accordance with the
there are certain exceptions.
Bankruptcy Code and the terms of our Plan of Reorganization; however,
Circumstances in which claims and other obligations, that arose prior to the Petition Date, were not discharged
primarily relate to certain actions by governmental units under police power authority or where we have agreed
to preserve a claimant’s claims or a claimant has received court approval to proceed with their claim such as the
settlement of the CalGen Third Lien Debt claims. The ultimate resolution of such claims and other obligations
may have a material adverse effect on our results of operations and profitability.
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We depend on computer and telecommunications systems we do not own or control.
We have entered into agreements with third parties for hardware, software, telecommunications, and
database 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. 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, 2009, our consolidated debt outstanding was $9.5 billion, of which approximately
$4.7 billion was outstanding under our First Lien Credit Facility and $1.2 billion was outstanding under our First
Lien Notes. In addition we had $412 million issued in letters of credit and our pro rata share of unconsolidated
subsidiary debt was approximately $624 million. Although we have reduced our debt as a result of our
reorganization, 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 “— Operations” above. Our
borrowing capacity under our existing credit facilities remains limited. Although we are permitted to enter into
new project financing credit facilities to fund our development and construction activities and we are allowed to
offer first lien notes in exchange for term loans under our First Lien Credit Facility under certain circumstances,
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 of those transactions.
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 Credit Facility and other credit and financing arrangements as we routinely execute transactions in
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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 or refinance 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 are dependent upon numerous factors, including general economic and
capital market conditions. Market disruptions such as those experienced in the U.S. and abroad in 2008 and 2009,
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. These disruptions may continue throughout 2010 or
longer. Other factors include:
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low credit ratings may prevent us from obtaining any material amount of additional debt financing;
our restrictions against additional borrowing in our First Lien Credit Facility may limit additional
indebtedness other than through refinancing outstanding debt, or through project financings where we
are able to pledge the project assets as security;
conditions in power 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 Credit Facility, First Lien Notes and our other debt instruments impose significant
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 Credit Facility and First Lien Notes 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 our First Lien Credit Facility. These
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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 additional indebtedness and issue certain stock;
• make prepayments on or purchase certain indebtedness in whole or in part;
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pay dividends and other distributions with respect to our stock, or repurchase our stock or make other
restricted payments;
use money borrowed under our First Lien Credit Facility for non-guarantors (including foreign
subsidiaries);
• make certain investments;
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create or incur liens;
consolidate or merge with another entity, or allow one of our subsidiaries to do so;
lease, transfer or sell assets and use proceeds of permitted asset leases, transfers or sales;
pay dividends or make other distributions from certain subsidiaries up to Calpine Corporation;
• make capital expenditures beyond specified limits;
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engage in certain business activities;
enter into certain transactions with our affiliates; and
acquire power plants or other businesses.
Our First Lien Credit Facility, First Lien 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 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 Credit Facility, First Lien 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.
A significant portion of our indebtedness contains floating rate interest provisions, which could impact our
financial health if interest rates were to rise significantly.
A significant portion of our indebtedness contains floating rate interest, which we pay on a current basis.
If we are unable to satisfy our obligations under our floating rate debt, particularly on our First Lien Credit
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Facility, it could result in defaults under our First Lien Credit Facility and other debt instruments. We manage
our interest rate risk through the use of derivative instruments, including interest rate swaps. See also Item 7.
“Management’s Discussion and Analysis of Financial Condition and Results of Operations — Risk Management
and Commodity Accounting — Interest Rate Risk.”
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 has had certain
adverse impacts on 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 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.
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, 2009, we had $412 million issued in letters of credit under our First Lien Credit Facility and other
facilities, with $794 million remaining available for borrowing or for letter of credit support under our First Lien
Credit 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 First Lien Credit Facility with the
assets currently subject to liens under our First Lien Credit Facility.
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
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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 Credit Facility and our First Lien Notes.
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 substantial leverage.
Our First Lien Credit Facility, First Lien Notes and other parent-company debt is 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, 2009, our
subsidiaries had approximately $1.6 billion of secured project financing and approximately $1.0 billion in debt
from our CCFC subsidiary, which are effectively senior to our First Lien Credit Facility, First Lien Notes and
other parent-company debt. We may incur additional project financing indebtedness in the future, which will be
effectively senior to our other secured and unsecured debt.
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Governmental Regulation
Existing and future anticipated GHG/Carbon legislation could adversely affect our operations.
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 is in the process of creating implementation plans for
Assembly Bill 32 which places a statewide cap on GHG emissions and requires the state to return to 1990
emission levels by 2020.
In 2008, there were several bills introduced in the U.S. Congress concerning climate change. On June 26,
2009, the House of Representatives passed The American Clean Energy and Security Act of 2009, a climate
change and clean energy bill, which, among other provisions, would establish an economy-wide carbon
cap-and-trade program and set carbon emission reduction targets in several sectors of the economy, including the
power sector. For the power sector, 2012 is set as the initial year for compliance. On October 23, 2009, draft
climate change legislation entitled the Clean Energy Jobs and American Power Act, was released in the Senate.
The legislation is similar to The American Clean Energy and Security Act of 2009 in that it also includes, among
other provisions, an economy-wide carbon cap-and-trade program.
If either bill were to become law, we would have the obligation to obtain emissions allowances for the
operation of our fossil-fuel power plants. While we expect the costs to acquire allowances to be a factor that will
impact market price, there can be no assurance that market price will fully reflect these costs which could
adversely affect our Commodity Margin. With respect to our existing long-term steam and power contracts under
which we would not be able to recover costs to acquire allowances from our customers, the bill allocates a pool
of free allowances to generators with qualifying contracts to mitigate such costs. However, there can be no
assurance there will be a sufficient number of free allowances in the pool to fully cover emissions related to
generation under such contracts which could adversely impact our Commodity Margin.
Although we cannot predict the effect and ultimate content of final climate change legislation and
regulations, if any, on our business, we continue to expect climate change legislation efforts to proceed at the
federal level, and that proposed legislation will take the form of a cap-and-trade program, although it is possible
that legislation may take other forms, such as a carbon tax on each unit of CO2 or GHG emitted in excess of
mandated limits. As a result of requirements for GHG emissions reduction, we could be required under any
climate change legislation or related regulations ultimately enacted to purchase allowances or offsets to emit
GHGs or other regulated pollutants or to pay taxes on such emissions. These requirements, as well as the
possibility that market or contract prices will not fully reflect costs of compliance, or that we may not be able to
obtain free allowances or recoup our costs to obtain allowances or to reduce emissions, could have a material
impact on our financial condition, results of operations and cash flows.
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 is currently considering new and higher RPS. 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
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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 assets, 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 gas assets, primarily in Texas and California.
Proposed financial reform 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 price reporting and record retention. Thus, transactions executed on an ECM generally are not
regulated directly by the CFTC. However, 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.
On December 11, 2009, the House of Representatives passed the Wall Street Financial Reform and
Consumer Protection Act of 2009. The legislation includes provisions to regulate certain types of OTC
derivatives that we use. Included in the bill is a provision which clarifies the definition of a “major swap
participant” that would otherwise have left it to future CFTC interpretation and definition which could have put
more end users, such as us, under mandatory clearing, position limits and margin despite an end user exemption
in the underlying bill.
The Senate Banking Committee is attempting to work in a bipartisan manner to craft comprehensive
financial reform legislation. The committee has organized bipartisan working groups to address various aspects
of reform. The Senate Agriculture Committee also continues to work on drafting bipartisan legislation.
In January 2010, the Obama Administration requested Congress to place new restrictions on financial
institutions as part of comprehensive financial reform legislation. Specifically, the Obama Administration is
requesting that “no bank or financial institution that contains a bank will own, invest in or sponsor a hedge fund
or a private equity fund, or proprietary trading operations unrelated to serving customers for its own profit.” If
enacted into law, banks would be banned from owning trading operations that trade in physical and financial
derivative energy products. As several major financial institutions own such trading operations and provide
significant liquidity to the energy markets in which we participate, if this or similar legislation is enacted the
pricing and availability of derivative transactions related to our hedging activity could be adversely impacted.
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 and Texas. While
these markets are largely de-regulated, these markets continue to evolve. In 2009, implementation of CAISO’s
Market Redesign and Technology Upgrade in California had a neutral to slightly positive impact on our operations.
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.
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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 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. FERC has
ruled that we do not have market power as a consequence of their ownership of our common stock. However, 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 were 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 such as California,
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.
Four 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 53% of our
common stock at December 31, 2009, may be able to exercise substantial influence over all matters requiring
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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, two members of our Board of Directors, including the Chairman
of our Board, are 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, your ability to
influence us through voting your 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 two of the four 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. During 2009, one of these shareholders, who had reported holdings of
greater than 10% of our securities as of January 1, 2009, elected to sell approximately 67 million shares in a
series of offerings and market transactions during 2009, bringing its shareholdings below 10% of our common
stock. These sales, and additional sales by the other three 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 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.
To manage the risk of significant limitations on our ability to utilize our tax NOL carryforwards, our
amended and restated certificate of incorporation permits our Board of Directors to meet to determine whether to
impose certain transfer restrictions on our common stock in the following circumstances: if, prior to February 1,
2013, our Market Capitalization declines by at least 35% from our Emergence Date Market Capitalization of
approximately $8.6 billion (in each case, as defined in and calculated pursuant to our amended and restated
certificate of incorporation) and at least 25 percentage points of shift in ownership has occurred with respect to
our equity for purposes of Section 382 of the IRC. We believe, as of the filing of this Report, we have
experienced declines in our stock price of more than 35% from our Emergence Date Market Capitalization.
While we don’t believe an ownership change of 25 percentage points has occurred, the change in ownership is
only slighty less than 25%. Accordingly, the transfer restrictions have not been put in place by our Board of
Directors; however, if both of the foregoing events were to occur together and our Board of Directors were to
the
elect
circumstances will not be met in the future, or in the event that they are met, that our Board of Directors would
choose to impose these restrictions or that, if imposed, such restrictions would prevent an ownership change from
occurring.
they could become operative in the future. There can be no assurance that
to impose them,
52
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
Our principal executive offices are located in Houston, Texas. This facility is leased until 2013. We also
have a regional office in Dublin, California, an engineering office in La Porte, Texas and representative 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 17 of the Notes to Consolidated Financial Statements for a description of our legal proceedings.
Item 4. Submission of Matters to a Vote of Security Holders
None.
53
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Market Information and Stockholder Matters
On January 31, 2008, pursuant to our Plan of Reorganization, our previously outstanding common stock
was canceled and we authorized and began issuance of 485 million shares of reorganized Calpine Corporation
common stock to settle unsecured claims pursuant to our Plan of Reorganization. On January 16, 2008, the shares
of reorganized Calpine Corporation common stock were admitted to listing on the NYSE and began “when
issued” trading under the symbol “CPN-WI.” The reorganized Calpine Corporation common stock began
“regular way” trading on the NYSE under the symbol “CPN” on February 7, 2008.
The following table sets forth the high and low bid prices for our common stock for each quarter of the
calendar years 2009 and 2008, as reported on the NYSE.
2009
First Quarter
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2008
First Quarter
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
High
Low
$
$
$
$
9.34
14.95
13.75
12.25
19.51
23.36
22.83
13.48
4.76
6.64
10.10
10.14
15.00
17.77
12.08
6.35
As of December 31, 2009, there were 114 stockholders on record of our common stock. See Note 16 of
the Notes to Consolidated Financial Statements for a discussion of the effects of emergence from Chapter 11 on
our capital structure.
To manage the risk of significant limitations on our ability to utilize our tax NOL carryforwards, our
amended and restated certificate of incorporation permits our Board of Directors to meet to determine whether to
impose certain transfer restrictions on our common stock in the following circumstances: if, prior to February 1,
2013, our Market Capitalization declines by at least 35% from our Emergence Date Market Capitalization of
approximately $8.6 billion (in each case as defined and calculated pursuant to our amended and restated certificate
of incorporation) and at least 25 percentage points of shift in ownership has occurred with respect to our equity for
purposes of Section 382 of the IRC. We believe, as of the filing of this Report, we have experienced declines in our
stock price of more than 35% from our Emergence Date Market Capitalization. While we don’t believe an
ownership change of 25 percentage points has occurred, the change in ownership is only slightly less than 25%.
Accordingly, the transfer restrictions have not been put in place by our Board of Directors; however, if both of the
foregoing events were to occur together and our Board of Directors were to elect to impose them, they could
become operative in the future. There can be no assurance that the circumstances will not be met in the future, or in
the event that they are met, that our Board of Directors would choose to impose these restrictions or that, if imposed,
such restrictions would prevent an ownership change from occurring.
Should our Board of Directors elect to impose these restrictions, they shall have the authority and
discretion to determine and establish the definitive terms of the transfer restrictions provided that they apply to
purchases by owners of 5% or more of our common stock including any owners who would become owners of
5% or more of our common stock via such purchase. The transfer restrictions will not apply to the disposition of
54
shares provided they are not purchased by a 5% or more owner. If these transfer restrictions are imposed, any
increase in the value of our common stock shall not result in the lapse of the transfer restrictions unless the
increase in value of our common stock (determined on a weighted average 30-day trading period) shall be at least
10% greater than the trigger price. Our Board of Directors’ ability to impose transfer restrictions will terminate
on the fifth anniversary of our Emergence Date; however, any transfer restrictions imposed prior to such fifth
anniversary will remain in effect until one of the trigger provisions is no longer satisfied.
We have never paid cash dividends on our common stock. As our ability to pay cash dividends on our
common stock is restricted under our First Lien Credit Facility and certain of our other debt agreements, it is not
anticipated that any cash dividends will be paid on our common stock in the near future. 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 — 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
make tax withholding payments in cash. We withheld a total of 262,540 shares during 2009 that are included in
treasury stock. We do not have a stock repurchase program. As set forth in the table below, we withheld 240
shares during the fourth quarter of 2009.
Period
(a)
Total Number of
Shares Purchased
(b)
Average Price
Paid Per Share
(c)
Total Number of
Shares Purchased
as Part of
Publicly Announced
Plans or Programs
(d)
Maximum Number
of Shares That May
Yet Be Purchased
Under the
Plans or Programs
November . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . .
December
Total
. . . . . . . . . . . . . . . . . . . . . . . . .
100
140
240
$
$
$
10.97
11.23
11.12
—
—
—
n/a
n/a
n/a
55
Stock Performance Graph
The performance graph below compares cumulative return on our common stock for the period
February 7, 2008 through December 31, 2009, with the cumulative return of Standard & Poor’s 500 Index (S&P
500) and the S&P 500 Utility 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.
COMPARISON OF CUMULATIVE TOTAL RETURN
$120
$100
$80
$60
$40
$20
$-
2/7/08
12/31/08
12/31/09
CALPINE CORP
S&P 500 Total Return Index
S&P Utility Index
Company / Index
February 7, 2008 December 31, 2008 December 31, 2009
Calpine Corporation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
S&P 500 Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
S&P Utility Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
100
100
100
$
43.86
67.56
74.38
66.27
83.41
79.44
Copyright© 2010 Standard & Poor’s, Inc., Zacks Investments Research, Inc., All rights reserved
56
Item 6. Selected Financial Data
SELECTED CONSOLIDATED FINANCIAL DATA
Years Ended December 31,
2009
2008
2007
2006
2005
(in millions, except earnings (loss) per share)
Statement of Operations data:
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . $
6,564 $
9,937 $
7,970 $
6,937 $
10,302
Income (loss) before discontinued operations
attributable to Calpine(1) . . . . . . . . . . . . . . . . . . . . $
149 $
(13) $
2,693 $
(1,765) $
(9,881)
Discontinued operations, net of tax, attributable to
Calpine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
23
—
—
(58)
Net income (loss) attributable to Calpine(1)
. . . . . $
149 $
10 $
2,693 $
(1,765) $
(9,939)
Basic earnings (loss) per common share(2):
Income (loss) before discontinued operations
attributable to Calpine (1)
. . . . . . . . . . . . . . . . . . . $
0.31 $
(0.03) $
5.62 $
(3.68) $
(21.32)
Discontinued operations, net of tax, attributable to
Calpine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
0.05
—
—
(0.12)
Net income (loss) per common share attributable
to Calpine(1)
. . . . . . . . . . . . . . . . . . . . . . . . . . . $
0.31 $
0.02 $
5.62 $
(3.68) $
(21.44)
Diluted earnings (loss) per common share(2):
Income (loss) before discontinued operations
attributable to Calpine (1)
. . . . . . . . . . . . . . . . . . . $
0.31 $
(0.03) $
5.62 $
(3.68) $
(21.32)
Discontinued operations, net of tax, attributable to
Calpine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
0.05
—
—
(0.12)
Net income (loss) per common share attributable
to Calpine(1)
. . . . . . . . . . . . . . . . . . . . . . . . . . . $
0.31 $
0.02 $
5.62 $
(3.68) $
(21.44)
Balance Sheet data(3):
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Short-term debt and capital lease obligations(4) . . . .
Long-term debt and capital lease obligations(4)(5)
Liabilities subject to compromise(5) . . . . . . . . . . . . .
16,650 $
463
8,996
—
20,738 $
716
9,756
—
19,050 $
1,710
9,946
8,788
18,590 $
4,569
3,352
14,757
20,545
5,414
2,462
14,610
(1) As a result of our Chapter 11 and CCAA filings, for the year ended December 31, 2005, we recorded $5.0
billion of reorganization items primarily related to the provisions for expected allowed claims, impairment
of our Canadian subsidiaries, guarantees, write-off of unamortized deferred financing costs and losses on
terminated contracts. During 2007, we were released from a portion of our direct and indirect Canadian
guarantee of the ULC I notes, ULC II notes and redundant Canadian claims and recorded a $4.1 billion
credit for the reversal of these redundant claims.
(2) Although earnings (loss) per share information for the years ended December 31, 2007, 2006 and 2005 is
presented, it is not comparable to the information presented for the years ended December 31, 2009 and
2008, due to the changes in our capital structure on the Effective Date, which also included termination of
all outstanding convertible securities.
(3) See Note 16 of the Notes to Consolidated Financial Statements regarding certain “plan effect” adjustments
to our Consolidated Balance Sheet as of the Effective Date.
(4) As a result of our Chapter 11 filings, we reclassified approximately $5.1 billion of long-term debt and
capital lease obligations to short-term at December 31, 2006 and 2005, as our Chapter 11 filings constituted
57
events of default or otherwise triggered repayment obligations for the Calpine Debtors and certain
Non-Debtor entities. We classified our long-term debt and capital lease obligations at December 31, 2007,
based upon the refinanced terms of our First Lien Facilities.
(5) LSTC included unsecured and under secured liabilities incurred prior to the Petition Date and excluded
liabilities that are fully secured or liabilities of our subsidiaries or affiliates that did not make Chapter 11
filings and other approved payments such as taxes and payroll. As a result of our Chapter 11 filings, we
reclassified approximately $7.5 billion of long-term debt to LSTC at December 31, 2005. We subsequently
reclassified $3.7 billion from LSTC back to long-term debt based upon the terms of our Plan of
Reorganization at December 31, 2007. See Note 16 of the Notes to Consolidated Financial Statements for
more information.
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 the largest independent wholesale power company in the U.S. measured by power produced. We
own and operate natural gas-fired and geothermal power plants in North America and have a significant presence
in major competitive power markets in the U.S., including California and Texas, and to a lesser extent, in the
competitive PJM, ISO NE and NYISO markets. We sell wholesale power, steam, capacity, renewable energy
credits and ancillary services to our customers,
independent electric system operators,
industrial and agricultural companies, retail power providers, municipalities, power marketers and others. We
purchase natural gas 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-related commodity and derivative transactions to financially hedge certain business risks
and optimize our portfolio of power plants. Our goal is to be recognized as the premier independent power
company in the U.S. as measured by our customers, regulators, shareholders and communities in which our
power plants reside. We seek to achieve sustainable growth through financially disciplined power plant
development, construction, operations and ownership.
including utilities,
Our portfolio, including partnership interests, consists of 77 operating power plants, located throughout
16 states and Canada, with an aggregate generation capacity of approximately 24,802 MW. It is comprised of
two types of power generation technologies: natural gas-fired combustion turbines, which are primarily
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 21% of all renewable energy produced in the state of California during 2008.
Geothermal energy is one of the only baseload renewable energy supplies that exists today.
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, Southeast and North
(including Canada). In these segments we have an aggregate generation capacity of 7,910 MW in the West, 7,392
MW in Texas, 6,083 MW in the Southeast and 3,417 MW in the North. Our Geysers Assets, included in our
West segment, have generation capacity of approximately 725 MW from 15 operating power plants.
58
We remain focused on increasing our earnings and generating cash flow sufficient to maintain adequate
levels of liquidity in order to service our debt, meet our collateral needs and fund our operations and growth. 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 hedging
agreements within the guidelines of our commodity risk policy.
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 federal government is expected to take action on climate change legislation, as well as other air
pollutant emissions, and many 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 legislation or regulations 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
exclusively 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 independent power producer in the U.S.
In addition, we strive to preserve our nation’s valuable water and land resources. To condense steam, we 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.
Our Market and Our Key Financial Performance Drivers
The market spark spread, sales of RECs, revenues from our steam sales and the results from our
marketing, hedging and optimization activities are the primary components of our Commodity Margin and
contribute significantly to our financial results. The market spark spread is primarily impacted by natural gas
prices, weather and reserve margins, which impact both 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.
Depending upon our hedge levels and holding other factors constant, increases in natural gas prices tend
to increase our Commodity Margin and decreases in natural gas prices tend to decrease our Commodity Margin
because we generally have lower Heat Rates and are more efficient than our competitors. Efficient operation of
our fleet creates the opportunity to capture Commodity Margin in a cost effective manner. However, unplanned
outages during periods of positive Commodity Margin 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
59
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 Market Economics” in Item 1. of this
Report for additional information on how these factors impact our Commodity Margin.
Current Year Operational Developments
During 2009, we have continued to implement our strategy to become the premier independent power
company in the U.S. and achieve sustainable growth through financially disciplined power plant development,
construction, operations and ownership. We have made some notable achievements that are listed below:
• On February 4, 2010, we received the Prevention of Significant Deterioration, or PSD, air permit, the
final permit necessary, to begin construction of our Russell City Energy Center. We hope to complete
financing and break ground for this new state-of-the-art power plant during 2010 with commercial
operations scheduled to begin in 2013. Russell City Energy Center is intended to become the first
power plant in the U.S. with a federal limit on GHG emissions, and will be designed to operate in a
way that produces 25% fewer GHG emissions than the CPUC standard.
•
Throughout 2009, our plant operating personnel exceeded the first quartile performance for employee
lost time incident rate for fossil fuel electric power generation companies with 1,000 or more
employees.
• Our Geysers Assets generated approximately 6 million MWh and achieved an exceptional equivalent
availability factor of over 97%. Our natural gas-fired fleet achieved exceptional performance during
2009, with an equivalent forced outage factor of 2.7%, an improvement of 35% over full year 2008.
• We completed 14 major inspections and 13 hot gas path inspections on schedule and on budget during
2009 and completed one of several planned natural gas-fired turbine upgrades and two steam turbine
upgrades, which not only added incremental capacity but improved the efficiency of the entire
turbines.
• OMEC, located in San Diego, California, achieved commercial operations on October 3, 2009, adding
608 MW of capacity to our fleet.
• Under one of our new PPAs, we will modernize and upgrade our Los Esteros Critical Energy Facility
to add 120 MW by converting it from simple-cycle (peaking) to combined-cycle technology,
increasing the efficiency and environmental performance of the power plant.
• We successfully restructured and streamlined our power and commercial operations, as well as our
corporate functions, to more effectively manage our business and reduce expenses.
Customer-Oriented Origination Business
During 2009, we reorganized our customer origination function to allow our dedicated group of
professionals to more effectively help manage this function. This effort is beginning to deliver real, tangible
results and we, through certain of our wholly owned subsidiaries, entered into new PPAs and amended certain
PPAs, which are all on mutually beneficial terms and many are subject to regulatory approvals. They include the
following:
• We and PG&E have agreed to an extension of the term and an increase in the volume under the
existing contracts for delivery of power from our Geysers Assets. Our Geysers Assets currently
provide PG&E 375 MW of power under two contracts. We have agreed to increase the volume to 425
MW through 2017, and from 2018 through the end of 2021, our Geysers Assets will supply PG&E
250 MW of renewable energy.
60
• Our wholly owned subsidiaries, Gilroy Energy Center, LLC, Creed and Goose Haven, have entered
into a replacement contract with PG&E, whereby PG&E will have greater dispatch flexibility for all
11 of our peaking units in California through 2017 and for seven of our peaking units through 2021.
• We and PG&E negotiated a new agreement to replace the existing CDWR contract and facilitate the
upgrade of our Los Esteros Critical Energy Facility from a 188 MW simple-cycle generation power
plant to a 308 MW combined-cycle generation power plant. In addition to the increase in capacity, the
upgrade will increase the efficiency and environmental performance of the power plant by lowering
the Heat Rate. While the upgrade is under construction, we will provide capacity to PG&E from our
Gilroy Cogeneration Plant. Upon completion of the upgrade, PG&E will purchase all of the capacity
from our Los Esteros Critical Energy Facility for a term of ten years.
• We have entered into a new tolling arrangement with PG&E for all of the capacity from our Delta
Energy Center from 2011 through 2013.
• We executed a resource adequacy agreement for all of the capacity from our Pastoria Energy Center
with Southern California Edison for 2012 and 2013.
• We executed a contract for 500 MW of capacity from our Morgan Energy Center with the Tennessee
Valley Authority through 2011.
• We executed a contract for 485 MW of capacity from our Carville Energy Center with Entergy
Corporation through May 2012.
• We executed a contract for 200 MW of capacity from our Oneta Energy Center with American
Electric Power through 2010.
•
In addition to the suite of products we plan to supply through the agreements described above, our
commercial operations team is also identifying creative opportunities to match our capabilities with
the needs of our customers. During 2009, we entered into a PPA with the Los Angeles Department of
Water and Power to provide integration services of up to 270 MW, leveraging our quick-responding
natural gas-fired Hermiston Power Project located in Hermiston, Oregon, as well as its contracted
transmission resources in the northwest as back up for wind generated power.
The last transaction is an indication of the need our customers and more generally the market will have to
utilize flexible natural gas-fired generation to assure reliability of supply while integrating intermittent and
variable renewable resources, such as wind and solar power, that they are required to procure as part of a
renewable energy portfolio.
Capital Management
We have opportunistically completed several financing transactions for a total of approximately $3.0
billion to improve our flexibility and management of our balance sheet. Significant transactions in 2009 include,
but are not limited to, the following:
• On November 24, 2009, we amended and extended our Steamboat project debt which extended the
maturity date from December 2011 to November 24, 2017.
• On December 11, 2009, we amended the letter of credit facility related to our subsidiary, Calpine
Development Holdings, Inc., to extend the maturity from January 31, 2010 to December 11, 2012,
with an option to increase the letters of credit available from $150 million to $200 million by
satisfying certain conditions.
61
• On August 20, 2009, we amended our First Lien Credit Facility and related collateral agency and
intercreditor agreement in several respects to give us greater flexibility, including allowing us to
exchange First Lien Credit Facility term loans for First Lien Notes.
• On October 21, 2009, we issued approximately $1.2 billion aggregate principal amount of First Lien
Notes in a private placement as a permitted debt exchange pursuant to our First Lien Credit Facility,
which retired an aggregate principal amount of term loans under our First Lien Credit Facility equal
to the aggregate principal amount of First Lien Notes issued. As a result of the issuance of the First
Lien Notes, we were able to extend the maturities of approximately $1.2 billion in debt to 2017, at the
same time converting it from a variable to a fixed interest rate.
• On May 19, 2009, our wholly owned subsidiaries, CCFC and CCFC Finance, issued approximately
$1.0 billion aggregate principal amount of CCFC New Notes in a private placement. The net proceeds
were used to repay the CCFC Term Loans, CCFC Old Notes and CCFCP Preferred Shares. As a
result of the CCFC Refinancing transactions, we were able to extend the maturities of approximately
$1.0 billion of debt by several years, at the same time converting it from a variable to a fixed interest
rate and lowering our effective interest rates.
• On January 21, 2009, we closed on our Deer Park $156 million senior secured credit facilities, which
included a $150 million term facility and a $6 million letter of credit facility. Proceeds received were
used to settle an existing commodity contract of approximately $79 million, pay financing and legal
fees, fund additional restricted cash and for general corporate purposes.
For a further discussion of our 2009 significant financing transactions, see “— Liquidity and Capital
Resources.”
62
RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2009 AND 2008
Below are our results of operations for the year ended December 31, 2009, as compared to the same
period in 2008 (in millions, except for percentages and operating performance metrics). We have modified our
presentation of commodity revenue and commodity expense to include cash settlements from our commodity
marketing, hedging and optimization activities that were previously included in mark-to-market activity. Our
2008 commodity revenue and commodity expense information has been reclassified to conform to the current
year presentation. 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 in the “Change” and “% Change” columns.
Operating revenues:
Commodity revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mark-to-market activity(1)
Other revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
6,463
80
21
6,564
$
9,876
4
57
9,937
(3,413)
76
(36)
(3,373)
(35)%
#
(63)
(34)
2009
2008
Change
% Change
Cost of revenue:
Fuel and purchased energy expense:
Commodity expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mark-to-market activity(1)
Fuel and purchased energy expense . . . . . . . . . . . . . . . . . . . . . . . . .
Plant operating expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization expense . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating asset impairments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other cost of revenue(2)
Total cost of revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross profit
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales, general and other administrative expense . . . . . . . . . . . . . . . . . . . . .
(Income) loss from unconsolidated investments in power plants . . . . . . . .
Other operating expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest (income)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Debt extinguishment costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other (income) expense, net
Income (loss) before reorganization items, income taxes and
discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reorganization items . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) before income taxes and discontinued operations . . . . . . .
Income tax expense (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) before discontinued operations . . . . . . . . . . . . . . . . . . . . .
Discontinued operations, net of tax expense of $14 in 2008 . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . .
Net income attributable to Calpine . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net loss attributable to the noncontrolling interest
$
3,896
1
3,897
897
467
4
84
5,349
1,215
183
(50)
18
1,064
829
(16)
76
16
159
(1)
160
15
145
—
145
4
149
7,352
(71)
7,281
918
433
33
114
8,779
1,158
215
229
26
688
1,071
(47)
13
14
(363)
(302)
(61)
(47)
(14)
23
9
1
10
$
$
3,456
(72)
3,384
21
(34)
29
30
3,430
57
32
279
8
376
242
(31)
(63)
(2)
522
(301)
221
(62)
159
(23)
136
3
139
47
#
46
2
(8)
88
26
39
5
15
#
31
55
23
(66)
#
(14)
#
#
#
#
#
#
#
#
#
Operating Performance Metrics:
MWh generated (in thousands)(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average availability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average total MW in operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average capacity factor, excluding peakers . . . . . . . . . . . . . . . . . . . . . . . .
Steam Adjusted Heat Rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
# Variance of 100% or greater
63
2009
2008
Change
% Change
88,339
87,762
92.1% 90.5 %
23,414
23,037
48.7% 47.9 %
7,263
7,231
577
1.6
377
0.8
(32)
1%
2
2
2
—
(1) Amount represents the unrealized portion of our commodity mark-to-market activity as well as a non-cash
gain from amortization of prepaid power sales agreements.
(2)
Includes $5 million and nil of RGGI compliance costs for the years ended December 31, 2009 and 2008,
respectively, which is a component of Commodity Margin.
(3) Represents generation from power plants that we both consolidate and operate.
Commodity revenue and commodity expense decreased for the year ended December 31, 2009 compared
to 2008, largely due to lower natural gas prices which decreased 53% in 2009 compared to 2008; however,
commodity revenue, net of commodity expense, increased $43 million for the year ended December 31, 2009
compared to 2008, primarily due to:
•
•
•
higher average hedge margins in 2009 compared to 2008;
average annual Market Heat Rates were relatively unchanged for the year ended December 31, 2009
compared to 2008, with the exception of our Southeast segment which experienced a 35% increase in
generation in 2009 compared to 2008 largely due to higher natural gas generation displacement of
coal generation in certain sub-markets in our Southeast segment caused by lower natural gas prices
resulting in higher Market Heat Rates; partially offset by
lower natural gas prices in 2009 compared to 2008 and the resulting negative impact on our open
positions.
These factors were also positively impacted by our operational performance where we experienced a 1%
increase in generation as well as a 2% increase in both our average availability and average capacity factor,
excluding peakers, for the year ended December 31, 2009 compared to 2008.
Revenues from mark-to-market activity increased for the year ended December 31, 2009 compared to
2008, which is consistent with a falling commodity price environment. Expenses from mark-to-market activity
increased for the year ended December 31, 2009 compared to 2008, due to the impact of natural gas market price
volatility on our natural gas hedge position for our generation portfolio.
Other revenue decreased for the year ended December 31, 2009 compared to 2008, primarily related to a
$14 million decrease in revenue from operation and maintenance contracts and a $7 million decrease in revenue
from construction management projects completed in 2008. Also contributing to the decrease was an $11 million
decrease in other revenue related to royalty income on oil and gas producing properties.
Normal, recurring plant operating expenses decreased by $24 million for the year ended December 31,
2009 compared to 2008, after accounting for $29 million in reimbursements for insurance claims from prior
periods that reduced our 2008 and, to a much lesser extent, 2009 expenses. Additionally, major maintenance
costs resulting from our plant outage schedule decreased $16 million and plant personnel costs related to stock-
based compensation expense decreased $9 million for the year ended December 31, 2009 compared to 2008.
Depreciation and amortization expense increased for the year ended December 31, 2009 compared to
2008, primarily resulting from an increase of $25 million in the fourth quarter of 2009 related to a revision in the
estimated useful lives and salvage values of our power plants and related equipment and changing our Geysers
Assets depreciation from the units of production method to the straight line method as well as a $9 million
increase resulting from an upward revision in the rate used to depreciate our Geysers Assets due to changes in
our estimate of our future development costs for the first nine months of 2009. See Note 3 of the Notes to
Consolidated Financial Statements for further information regarding our change in useful lives and salvage
values as well as our change from the units of production method to the straight line depreciation method for our
Geysers Assets.
64
Our operating asset impairments decreased for the year ended December 31, 2009 compared to 2008,
primarily from a $33 million impairment recorded in 2008 relating to our Auburndale Peaking Energy Center
resulting from lower forecasted future cash flows.
Other cost of revenue decreased for the year ended December 31, 2009 compared to 2008, as a result of a
decrease of $17 million related to the discontinuation of the amortization of other assets associated with the
deconsolidation and subsequent sale of Auburndale in 2008 as well as an $11 million decrease in royalty expense
due to lower revenues from our Geysers Assets resulting from lower spot market power prices in the year ended
December 31, 2009 compared to 2008. The decrease was partially offset by an increase of $5 million in expenses
related to RGGI compliance costs in the Northeast which was initiated in 2009.
Sales, general and other administrative expense decreased for the year ended December 31, 2009
compared to 2008, due to a $10 million decrease in personnel costs and stock-based compensation expense
resulting primarily from a lower headcount in 2009 as well as a $13 million decrease in legal and consulting
expenses. In addition, we experienced a $5 million favorable year over year change in our bad debt expense.
Our (income) loss from unconsolidated investments in power plants increased for the year ended
December 31, 2009 compared to 2008, primarily due to an impairment loss of $180 million related to our equity
interest in Auburndale recorded during the year ended December 31, 2008. Also contributing to the increase was
income from our investment in Greenfield LP of $16 million for the year ended December 31, 2009 compared to
a loss of $5 million for the year ended December 31, 2008, which is due to Greenfield LP achieving commercial
operations in October 2008. We also had income of $32 million related to our investment of OMEC, of which, $4
million related to OMEC achieving commercial operation in October 2009 and a $28 million gain related to
mark-to-market activities from interest rate swap contracts compared to a loss of $55 million incurred for the
year ended December 31, 2008, related to unrealized mark-to-market losses from interest rate swap contracts.
information regarding our
See Note 4 of
unconsolidated investments.
the Notes to Consolidated Financial Statements for
further
Other operating expense decreased for the year ended December 31, 2009 compared to 2008, due to
impairments of $13 million related to development projects recorded in 2008 which was partially offset by an
increase of $6 million in project development expense for the year ended December 31, 2009 compared to 2008,
related to Russell City Energy Center which is under advanced development.
Due to the changes in our capital structure on the Effective Date, our interest expense for the years ended
December 31, 2009 and 2008, is not directly comparable. Interest expense decreased primarily due to $135
million in post-petition interest related to pre-emergence debt recorded in the first quarter of 2008 and $27
million for settlement obligations related to the Canadian Debtors and other deconsolidated foreign entities
recorded prior to their reconsolidation in February 2008. In addition, interest expense decreased for the year
ended December 31, 2009 compared to 2008, due to lower average interest rates on our variable rate debt
resulting from a decrease in LIBOR over the same periods. The annualized effective interest rates on our
consolidated debt, excluding the impacts of capitalized interest and unrealized mark-to-market gains (losses) on
interest rate swaps, after amortization of deferred financing costs and debt discounts, were 8.0% and 8.8% for the
year ended December 31, 2009 and 2008, respectively. The decrease in interest expense was partially offset by
the negative period over period impact of $153 million related to interest rate swap settlements resulting from a
decrease in LIBOR.
Interest income decreased for the year ended December 31, 2009 compared to 2008, largely resulting
from lower average interest rates earned on our cash balances which were primarily invested in U.S. Treasury
securities or government-backed securities for the year ended December 31, 2009 compared to primarily invested
in institutional-backed money market accounts for the year ended December 31, 2008.
65
Debt extinguishment costs increased for the year ended December 31, 2009 compared to 2008, primarily
due to $76 million in debt extinguishment costs associated with the retirement of the term loans under the First
Lien Credit Facility in October 2009, the refinancing of our CCFC Old Notes and CCFC Term Loans in May and
June 2009 and the CCFCP Preferred Shares that were redeemed on or before July 1, 2009. This increase was
partially offset by $13 million in debt extinguishment costs for the write-off of unamortized deferred financing
costs and other costs associated with the refinancing of all outstanding indebtedness under the existing Blue
Spruce term loan facility in February 2008 as well as the refinancing of our Metcalf term loan facility and
preferred interests in June 2008.
During the year ended December 31, 2009, reorganization items primarily consisted of settlements of
various disputed claims. During the year ended December 31, 2008, reorganization items primarily consisted of
$206 million in gains on asset sales, a $71 million gain on the reconsolidation of the Canadian Debtors and other
deconsolidated foreign entities, a $62 million credit related to the settlement of claims with the Canadian Debtors
and other deconsolidated foreign entities, a $34 million credit for RockGen related to a prior period which we
determined was not material to any period, a $12 million credit related to the settlement with Rosetta of our
fraudulent conveyance claim and $85 million in professional and trustee fees related to activity managed by our
third party advisors for our Chapter 11 and CCAA cases.
For the year ended December 31, 2009, we recorded tax expense of $15 million before discontinued
operations compared to a benefit of $47 million for the year ended December 31, 2008. Due to the valuation
allowances recorded against certain deferred tax assets, our effective tax rate differs considerably from the
federal statutory rate. Our tax structure is comprised primarily of two taxable groups, CCFC and its subsidiaries
and Calpine Corporation and its subsidiaries other than CCFC. CCFC and its subsidiaries no longer have a
valuation allowance recorded against its deferred tax assets due to its ability to generate sufficient income to
utilize its NOLs. Our 2009 income tax expense primarily relates to a foreign tax expense of $2 million and $43
million expense relating to the reversal of prior years intraperiod tax allocation due to OCI gains partially offset
by a $30 million tax benefit from the CCFC group. Our 2008 benefit for income taxes before discontinued
operations primarily relates to a foreign tax benefit of $70 million recorded as a result of the Canadian Settlement
Agreement, and intraperiod tax allocation benefit of $90 million, which was comprised of a $76 million tax
benefit to continuing operations due to current OCI gains and a $14 million tax benefit in income from
discontinued operations, offset by tax expense of approximately $100 million on CCFC’s income. See Note 11 of
the Notes to Consolidated Financial Statements for further information.
During the year ended December 31, 2008, we recorded $23 million in discontinued operations, net of
taxes of $14 million, related to the settlement with Rosetta of all of our outstanding claims related to our
domestic oil and gas assets we sold to Rosetta for $1.1 billion in 2005. See Note 6 of the Notes to Consolidated
Financial Statements for further information.
66
RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2008 AND 2007
Below are our results of operations for the year ended December 31, 2008, as compared to the same
period in 2007 (in millions, except for percentages and operating performance metrics). We have modified our
presentation of commodity revenue and commodity expense to include cash settlements from our commodity
marketing, hedging and optimization activities that were previously included in mark-to-market activity. Our
2008 and 2007 commodity revenue and commodity expense information has been reclassified to conform to the
current year presentation. 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 in the “Change” and “% Change” columns.
Operating revenues:
Commodity revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mark-to-market activity(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
9,876
4
57
9,937
$
7,903
10
57
7,970
1,973
(6)
—
1,967
25%
(60)
—
25
2008
2007
Change
% Change
Cost of revenue:
Fuel and purchased energy expense:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commodity expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Mark-to-market activity(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fuel and purchased energy expense . . . . . . . . . . . . . . . . . . . . . . . . . .
Plant operating expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization expense . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating asset impairments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other cost of revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total cost of revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales, general and other administrative expense . . . . . . . . . . . . . . . . . . . . . .
Loss from unconsolidated investments in power plants . . . . . . . . . . . . . . . . .
Other operating expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest (income) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Debt extinguishment costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other (income) expense, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss before reorganization items, income taxes and discontinued
Income tax benefit
operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reorganization items . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) before income taxes and discontinued operations . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) before discontinued operations . . . . . . . . . . . . . . . . . . . . . .
Discontinued operations, net of tax expense of $14 in 2008 . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net loss attributable to the noncontrolling interest . . . . . . . . . . . . . . . . . . . . .
Net income attributable to Calpine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
7,352
(71)
5,692
(9)
7,281
918
433
33
114
8,779
1,158
215
229
26
688
1,071
(47)
13
14
(363)
(302)
(61)
(47)
(14)
23
9
1
10
5,683
749
463
44
136
7,075
895
146
21
23
705
2,019
(64)
(1)
(138)
(1,111)
(3,258)
2,147
(546)
2,693
—
2,693
—
$ 2,693
$
(1,660)
62
(1,598)
(169)
30
11
22
(1,704)
263
(69)
(208)
(3)
(17)
948
(17)
(14)
(152)
748
(2,956)
(2,208)
(499)
(2,707)
23
(2,684)
1
(2,683)
(29)
#
(28)
(23)
6
25
16
(24)
29
(47)
#
(13)
(2)
47
(27)
#
#
67
(91)
#
(91)
#
—
#
—
#
Operating Performance Metrics:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
MWh generated (in thousands)(2)
Average availability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average total MW in operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average capacity factor, excluding peakers . . . . . . . . . . . . . . . . . . . . . . . . . .
Steam Adjusted Heat Rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
# Variance of 100% or greater
67
2008
2007
Change
% Change
87,762
90,811
90.5%
90.8%
23,037
24,679
47.9%
7,231
46.9%
7,190
(3,049)
(0.3)
(1,642)
1.0
(41)
(3)%
—
(7)
2
(1)
(1) Amount represents the unrealized portion of our mark-to-market activity as well as a non-cash gain from
amortization of prepaid power sales agreements.
(2) Represents generation from power plants that we both consolidate and operate.
Commodity revenue and commodity expense increased for the year ended December 31, 2008 compared
to 2007, largely due to higher natural gas prices which increased 25% in 2008 compared to 2007. In addition,
commodity revenue, net of commodity expense, increased $313 million for the year ended December 31, 2008,
compared to 2007 primarily due to:
•
•
•
•
higher market spark spreads on open positions due to higher natural gas prices throughout the first
three quarters of 2008 in our key Texas and West markets which benefited our power plants in these
regions as they operated more efficiently against corresponding Market Heat Rates;
higher Market Heat Rates in the second quarter of 2008, particularly in Texas which resulted from
higher temperatures and transmission congestion in the South and Houston zones;
higher realized spark spreads for our generally higher levels of hedging in all regions; and
earnings from settlement of dedesignated hedges, the value for which was previously reflected in
OCI.
Generation decreased 3% despite a 2% increase in our average capacity factor, excluding peakers, due to
a 7%, or 1,642 MW, decrease in our average total MW in operation for the year ended December 31, 2008,
the
compared to 2007. The generation decrease primarily resulted from power plant sales in 2007,
deconsolidation and subsequent sale of Auburndale in 2008 and an increase in the number of unscheduled
outages in 2008 compared to 2007.
Results of net unrealized mark-to-market activity are driven primarily from our commodity hedging
activities that do not qualify for hedge accounting. The $56 million increase for the year ended December 31,
2008 compared to 2007, is largely due to a decrease in expenses from mark-to-market activity primarily driven
by the impact of natural gas market price volatility on our natural gas hedge position for our generation portfolio.
Plant operating expense increased during the year ended December 31, 2008, compared to the year ended
December 31, 2007, primarily as a result of a $92 million increase in expense for major maintenance for
scheduled outages related to the life cycle of our power plant fleet and an increase of $25 million in plant
personnel costs related to stock-based compensation expense for equity awards issued in 2008. The increase in
major maintenance is driven by the fact that we placed 23 power plants in service in the 2001-2002 time frame
and many have reached their 24,000 or 48,000 hour major inspection operating intervals. Routine operating and
repair costs also contributed $31 million to the increase in plant operating expense which related to increases in
chemical costs and other consumables, and increases in routine repairs. A $16 million increase in expense for
outages, many of which occurred in 2007 and equipment repairs made in 2008, caused by equipment failures, net
of insurance recoveries, also contributed to the increase in plant operating expense for the year ended
December 31, 2008, compared to 2007.
Depreciation and amortization expense decreased for the year ended December 31, 2008, compared to the
year ended December 31, 2007, primarily due to an upward revision in the estimated useful life of our Geysers
Assets as well as the sale of Acadia PP in September 2007. The upward revision in the estimated useful life of
our Geysers Assets relates to our reservoir replenishment activities which extends the estimated economic life of
our Geysers Assets from 2034 to 2050.
68
Our operating asset impairments for the year ended December 31, 2008, consisted of a $33 million
impairment relating to our Auburndale Peaking Energy Center resulting from lower forecasted future cash flows.
Operating asset impairments of $44 million during the year ended December 31, 2007, were recorded primarily
for the Bethpage Power Plant resulting from the expected adverse impact on power pricing of new power
transmission capacity from the PJM market into Long Island.
Other cost of revenue decreased for the year ended December 31, 2008, compared to the year ended
December 31, 2007, as a result of an $8 million decrease for the sale of PSM in March 2007, a $10 million
decrease in operating lease expense due to the termination of the lease associated with our purchase of the
RockGen Energy Center in January 2008 and a decrease of $8 million related to the discontinuation of the
amortization of other assets associated with the deconsolidation and subsequent sale of Auburndale in 2008.
These decreases were partially offset by a $5 million increase in royalty expense due to higher spot market power
prices in 2008 compared to 2007.
Sales, general and other administrative expense was higher for the year ended December 31, 2008,
compared to the same period in 2007 due to a $42 million increase in personnel costs resulting primarily from
higher stock-based compensation expense arising from the grant of equity awards during the first quarter of 2008
and a $15 million increase in legal and consulting expenses.
Our loss from unconsolidated investments in power plants increased in 2008 compared to 2007 primarily
due to an impairment loss of $180 million related to our equity interest in Auburndale during the year ended
December 31, 2008. We also incurred an increase of $47 million in unrealized mark-to-market losses from
interest rate swap contracts related to our investment in OMEC. The increase was partially offset by $9 million in
income from our investment in RockGen and an $8 million reduction in losses related to our investment in
Greenfield LP for the year ended December 31, 2008, compared to 2007. See Note 4 of the Notes to
Consolidated Financial Statements for further information regarding our unconsolidated investments.
Due to the changes in our capital structure on the Effective Date, our interest expense for the years ended
December 31, 2008 and 2007, is not directly comparable. Interest expense decreased primarily due to $376
million in post-petition interest related to pre-emergence debt recorded in 2007, resulting from the Canadian
Settlement Agreement as well as $347 million in post-petition interest related to other pre-petition obligations
recorded during the year ended December 31, 2007, which was partially offset by $135 million in post-petition
interest recorded during the year ended December 31, 2008. In addition, interest expense decreased for the year
ended December 31, 2008, compared to the year ended December 31, 2007, due to lower average debt balances
and lower average interest rates. During the first quarter of 2008, we settled a portion of our debt through
payment of cash and issuance of reorganized Calpine Corporation common stock pursuant to our Plan of
Reorganization. Additionally, interest rates on our variable rate debt were lower for the year ended December 31,
2008, compared to 2007, due to a decrease in LIBOR over the same periods. The annualized effective interest
rates on our consolidated debt, excluding the impacts of items not directly attributed to the cost of the debt
instruments, after amortization of deferred financing costs and debt discounts, were 8.8% and 11.0% for the years
ended December 31, 2008 and 2007, respectively. The decrease was partially offset by the negative period over
period impact of $89 million related to interest rate swap settlements resulting from a decrease in LIBOR as well
as $27 million for settlement obligations related to our Canadian subsidiaries recorded prior to their
reconsolidation in February 2008.
Interest income decreased primarily due to lower average cash balances for the year ended December 31,
2008, compared to the same period in 2007 resulting from the distribution of cash pursuant to our Plan of
Reorganization in the first quarter of 2008, and due to lower average interest rates.
Other (income) expense, net had an unfavorable variance primarily as a result of the non-recurrence of
$135 million in income pertaining to a claim settlement with a customer which received court approval and was
recorded during the third quarter of 2007. The claim related to the customer’s rejection of our energy services
69
agreement following the customer’s bankruptcy filing and was unrelated to our Chapter 11 cases. Also
contributing to the decrease was a loss of $13 million incurred during 2008 related to our settlement with Panda.
Debt extinguishment costs increased for the year ended December 31, 2008 compared to 2007, primarily
due to $13 million in debt extinguishment costs for the write-off of unamortized deferred financing costs and
other costs associated with the refinancing of all outstanding indebtedness under the existing Blue Spruce term
loan facility in February 2008 as well as the refinancing of our Metcalf term loan facility and preferred interests
in June 2008.
The table below lists the significant components of
reorganization items for
the years ended
December 31, 2008 and 2007 (in millions):
Provision for expected allowed claims . . . . . . . . . . . . . . . . . . .
Professional and trustee fees . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gains on asset sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset impairments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain on reconsolidation of Canadian Debtors and other
2008
2007
Change
% Change
$
(95) $
85
(206)
—
(3,687) $
217
(285)
120
(3,592)
132
(79)
120
(97)%
61
(28)
#
deconsolidated foreign entities . . . . . . . . . . . . . . . . . . . . . . .
(71)
DIP Facility and First Lien Facilities financing and CalGen
Secured Debt repayment costs
Interest (income) on accumulated cash . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(4)
(7)
(4)
—
202
(59)
234
Total reorganization items . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(302)
$
(3,258) $
(2,956)
71
—
206
(52)
238
#
(88)
#
(91)
# Variance of 100% or greater
Provision for Expected Allowed Claims — During the year ended December 31, 2008, our provision for
expected allowed claims consisted primarily of a $62 million credit related to the settlement of claims with the
Canadian Debtors and other deconsolidated foreign entities, a $12 million credit related to the settlement with
Rosetta of our fraudulent conveyance claim and a $34 million credit for RockGen related to a prior period which
we determined was not material to any period. During the year ended December 31, 2007, our provision for
expected allowed claims consisted primarily of a $4.1 billion credit related to the settlement of claims related to
Calpine Corporation’s guarantee of the ULC I notes and the release of our guarantee of the ULC II notes
following repayment of those notes in September 2007, accruals totaling $275 million for make whole premiums
and/or damages related to the First Priority Notes, Second Priority Debt and Unsecured Notes settlements, $141
million resulting from the termination of the RockGen operating lease agreement and write-off of the related
prepaid lease expense, $98 million resulting from settlements and repudiation of certain natural gas
transportation and PPA contracts, and an additional accrual of $79 million resulting from the rejection of certain
leases and other agreements related to the Rumford and Tiverton power plants for which we agreed to allow
general unsecured claims in the aggregate of $190 million.
Professional and Trustee Fees — The decrease in professional fees for the year ended December 31,
2008, over the comparable period in 2007 resulted primarily from a decrease in activity managed by our third
party advisors related to our Chapter 11 and CCAA cases.
Gains on Asset Sales — During the year ended December 31, 2008, gains on asset sales primarily resulted
from the sales of the Hillabee and Fremont development project assets. During the year ended December 31,
2007, gains on asset sales primarily resulted from the sale of the Aries Power Plant, Goldendale Energy Center,
PSM and Parlin Power Plant during 2007. See Note 6 of the Notes to Consolidated Financial Statements for
further information.
70
Asset Impairments — During the year ended December 31, 2007, asset impairment charges were
primarily due to a pre-tax impairment charge of approximately $89 million to record our interest in Acadia PP at
fair value less cost to sell.
Gain on Reconsolidation of Canadian Debtors and Other Deconsolidated Foreign Entities — During the
year ended December 31, 2008, we recorded a gain of $71 million related to the reconsolidation of our Canadian
subsidiaries. See Note 2 of the Notes to Consolidated Financial Statements for further information.
DIP Facility and First Lien Facilities Financing and CalGen Secured Debt Repayment Costs — During
the year ended December 31, 2008, we recorded a $4 million credit related to a valuation revision for secured
shortfall claims related to our Second Priority Debt. During the year ended December 31, 2007, we recorded
costs related to the refinancing of our Original DIP Facility and repayment of the CalGen Secured Debt
consisting of $52 million of DIP Facility transaction costs, the write-off of $32 million in unamortized discount
and deferred financing costs related to the CalGen Secured Debt, and $76 million as our estimate of the expected
allowed claims resulting from the unsecured claims for damages granted to the holders of the CalGen Secured
Debt. We also recorded transaction costs of $22 million related to the execution of a commitment letter to fund
our First Lien Facilities as well as $13 million for secured shortfall claims relating to settlements for the First
Priority Notes and the CalGen First Lien Debt during the year ended December 31, 2007.
Interest (Income) on Accumulated Cash — The decrease in interest income on accumulated cash for the
year ended December 31, 2008, over the comparable period in 2007 related to our emergence from Chapter 11 at
which time we ceased allocating a portion of interest income to reorganization items.
Other — Other reorganization items decreased primarily due to recording a gain of $4 million during the
year ended December 31, 2008, versus a loss of $164 million in the year ended December 31, 2007, related to
foreign exchange movements on LSTC denominated in a foreign currency and the non-recurrence of a charge of
$14 million during the year ended December 31, 2007, resulting from debt pre-payment and make whole
premium fees to the project lenders related to the sale of the Aries Power Plant. Also contributing to the decrease
was $53 million in emergence incentive cost accruals related to our emergence from Chapter 11 recorded during
the year ended December 31, 2007, while no such accruals were recorded in 2008.
For the year ended December 31, 2008, we recorded a tax benefit of $47 million before discontinued
operations compared to a benefit of $546 million for the year ended December 31, 2007. Due to the valuation
allowances recorded against certain deferred tax assets, our effective tax rate differs considerably from the
federal statutory rate. Our tax structure is comprised primarily of two taxable groups, CCFC and its subsidiaries
and Calpine Corporation and its subsidiaries other than CCFC. CCFC and its subsidiaries no longer have a
valuation allowance recorded against its deferred tax assets due to its ability to generate sufficient income to
utilize its NOLs. Our 2008 benefit for income taxes before discontinued operations primarily relates to a foreign
tax benefit of $70 million recorded as a result of the Canadian Settlement Agreement, and intraperiod tax
allocation benefit of $90 million, which was comprised of a $76 million tax benefit to continuing operations due
to current OCI gains and a $14 million tax benefit in income from discontinued operations, offset by tax expense
of approximately $100 million on CCFC’s income. Our 2007 benefit for income taxes consisting primarily of
$485 million related to the release of valuation allowance in 2007. See Note 11 of the Notes to Consolidated
Financial Statements for further information.
During the year ended December 31, 2008, we recorded $23 million in discontinued operations, net of
taxes of $14 million, related to the settlement with Rosetta of all of our outstanding claims related to our
domestic oil and gas assets we sold to Rosetta for $1.1 billion in 2005. See Note 6 of the Notes to Consolidated
Financial Statements for further information.
71
COMMODITY MARGIN AND ADJUSTED EBITDA
Management’s Discussion and Analysis of Financial Condition and Results of Operations includes
financial
information prepared in accordance with GAAP, as well as the non-GAAP financial measures,
Commodity Margin and Adjusted EBITDA, discussed below, which we use as a measure 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 GAAP.
Commodity Margin by Segment for the Years Ended December 31, 2009 and 2008
We use the non-GAAP financial measure “Commodity Margin” to assess our performance by our
reportable segments. Commodity Margin includes our power and steam revenues, sales of purchased power and
natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and
expenses, fuel and purchased energy expense, RGGI compliance costs, and cash settlements from our marketing,
hedging and optimization activities that are included in mark-to-market activity, 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 GAAP, and should
be viewed as a supplement to and not a substitute for our results of operations presented in accordance with
GAAP. Commodity Margin does not intend to represent gross profit (loss), the most comparable GAAP measure,
as an indicator of operating performance and is not necessarily comparable to similarly-titled measures reported
by other companies. See Note 18 of the Notes to Consolidated Financial Statements for a reconciliation of
Commodity Margin to income (loss) from operations by segment.
The following tables show our Commodity Margin and related operating performance metrics by segment
for the years ended December 31, 2009 and 2008. During the first quarter of 2009, we began assessing the
performance of our regional segments to include the allocation (based upon each regional segment’s MWh) of
revenues and expenses from our fuel management, Turbine Maintenance Group and certain non-region specific
natural gas marketing and optimization and other corporate activities, which had formerly been separately
reported as our “Other” segment. Additionally, we have modified our definition of Commodity Margin to include
cash settlements from our marketing, hedging and optimization activities that were previously included in
mark-to-market activity. Our 2008 Commodity Margin by segment information has been recast to conform to the
current year presentation. In the “Change” and “% Change” columns below, favorable variances are shown
without brackets while unfavorable variances are shown with brackets. The MWh generated by segment below
represents generation from power plants that we both consolidated and operate.
West:
2009
2008
Change
% Change
Commodity Margin (in millions) . . . . . . . . . . . . . . . . .
Commodity Margin per MWh generated . . . . . . . . . . .
$
$
1,346
37.35
$
$
1,255
33.79
$
$
91
3.56
7%
11
MWh generated (in thousands) . . . . . . . . . . . . . . . . . . .
Average availability . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average total MW in operation . . . . . . . . . . . . . . . . . .
Average capacity factor, excluding peakers . . . . . . . . .
Steam Adjusted Heat Rate . . . . . . . . . . . . . . . . . . . . . .
36,033
92.3%
7,302
64.1%
7,304
37,137
89.1%
7,295
65.9%
7,267
(1,104)
3.2
7
(1.8)
(37)
(3)
4
—
(3)
(1)
West — Commodity Margin in our West segment increased by $91 million, or 7%, for the year ended
December 31, 2009 compared to the year ended December 31, 2008. The increase was primarily a result of
higher hedge levels and prices, sales of surplus emission allowances in the first quarter of 2009 and higher
resource adequacy and REC revenues in 2009 compared to 2008. Market Heat Rates remained relatively
72
unchanged across periods, and lower natural gas prices resulted in lower market spark spreads for the year ended
December 31, 2009 compared to 2008. In addition, the current period benefited from the non-recurrence in 2009
of an unfavorable natural gas storage inventory price adjustment in September 2008. Consistent with the weaker
price conditions, generation decreased 3% for the year ended December 31, 2009 compared to 2008, despite a
4% increase in our average availability. Commodity Margin per MWh generated increased 11% due in part to the
effect of our positive portfolio hedge value being allocated across a reduced number of generated MWh for the
year ended December 31, 2009 as compared to 2008.
Texas:
2009
2008
Change
% Change
Commodity Margin (in millions) . . . . . . . . . . . . . . . . . . . .
Commodity Margin per MWh generated . . . . . . . . . . . . .
$
$
644
21.69
$
$
726
22.40
$
$
MWh generated (in thousands) . . . . . . . . . . . . . . . . . . . . .
Average availability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average total MW in operation . . . . . . . . . . . . . . . . . . . . .
Average capacity factor, excluding peakers . . . . . . . . . . .
Steam Adjusted Heat Rate . . . . . . . . . . . . . . . . . . . . . . . . .
29,687
32,408
90.0%
7,156
47.4%
7,142
88.8%
7,147
51.6%
7,082
(82)
(0.71)
(2,721)
1.2
9
(4.2)
(60)
(11)%
(3)
(8)
1
—
(8)
(1)
Texas — Commodity Margin in our Texas segment decreased by $82 million, or 11%, for the year ended
December 31, 2009 compared to 2008. This decrease is primarily attributable to weaker natural gas prices that
were 56% lower in 2009 compared to 2008. Overall, Market Heat Rates were relatively unchanged in 2009
compared to 2008; however, Market Heat Rates were higher in the third quarter of 2009 compared to the same
period in 2008 due to warmer than average weather and lower in the second quarter of 2009 compared to the
same period in 2008 due to the congestion-driven pricing environment of the second quarter of 2008. Also
contributing to the overall decrease in Commodity Margin was lower steam sales resulting from weaker
industrial demand in 2009 compared to 2008. Despite a 1% increase in average availability, generation decreased
8% on softer demand in the first half of 2009 and weaker Market Heat Rates in the second quarter of 2009. We
experienced a 1% increase in our Steam Adjusted Heat Rate for the year ended December 31, 2009 compared to
2008, resulting from lower steam sales in 2009 compared to 2008.
Southeast:
2009
2008
Change
% Change
Commodity Margin (in millions) . . . . . . . . . . . . . . . . . . . .
Commodity Margin per MWh generated . . . . . . . . . . . . . .
$
$
304
17.50
$
$
264
20.59
$
$
MWh generated (in thousands) . . . . . . . . . . . . . . . . . . . . . .
Average availability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average total MW in operation . . . . . . . . . . . . . . . . . . . . .
Average capacity factor, excluding peakers . . . . . . . . . . . .
Steam Adjusted Heat Rate . . . . . . . . . . . . . . . . . . . . . . . . .
17,370
12,820
93.2%
6,083
37.9%
7,299
93.6%
6,183
26.6%
7,388
40
(3.09)
4,550
(0.4)
(100)
11.3
89
15%
(15)
35
—
(2)
42
1
Southeast — Commodity Margin in our Southeast segment increased by $40 million, or 15%, for the year
ended December 31, 2009 compared to 2008. The increase was driven by a 35% increase in generation which
resulted from higher natural gas generation displacement of coal generation in certain sub-markets in our
Southeast segment primarily caused by lower natural gas prices resulting in higher Market Heat Rates in 2009
compared to 2008. Commodity Margin in the Southeast was also positively affected in 2009 compared to 2008,
by the favorable impact of an off-take agreement at one of our power plants and incremental natural gas hedges.
The benefit from these positive performance factors was partially offset by the negative impact from the
settlement of a disputed steam contract, which adversely impacted operating revenues in 2009. In addition, a gain
of $21 million related to the temporary assignment of a transmission capacity contract in the second quarter of
2008 led to a reduction in relative year over year performance. We experienced a 1% decrease in our Steam
Adjusted Heat Rate in 2009 compared to 2008, resulting from increased generation. The 100 MW, or 2%,
decrease in our average total MW in operation for the year ended December 31, 2009 compared to 2008, was due
to the deconsolidation of Auburndale in the third quarter of 2008.
73
North:
2009
2008
Change
% Change
Commodity Margin (in millions)
. . . . . . . . . . . . . . . . . . .
Commodity Margin per MWh generated . . . . . . . . . . . . .
$
$
268
51.06
$
$
279
51.70
$
$
(11)
(0.64)
(4)%
(1)
MWh generated (in thousands) . . . . . . . . . . . . . . . . . . . . .
Average availability . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average total MW in operation . . . . . . . . . . . . . . . . . . . . .
Average capacity factor, excluding peakers . . . . . . . . . . .
Steam Adjusted Heat Rate . . . . . . . . . . . . . . . . . . . . . . . . .
5,249
94.7%
2,873
31.1%
7,614
5,397
92.6%
2,412
32.8%
7,584
(3)
(148)
2
2.1
19
461
(1.7)
(5)
(30) —
North — Commodity Margin in our North segment decreased by $11 million, or 4%, for the year ended
December 31, 2009 compared to 2008. Although market spark spreads were lower in 2009 compared to 2008, the
impact was largely mitigated by our hedge position as well as the favorable impact of the reconsolidation of
RockGen in December 2008. In addition, despite a 2% increase in our average availability, generation decreased
3% due primarily to lower Market Heat Rates in certain sub-markets in our North segment for the year ended
December 31, 2009 compared to 2008. The 461 MW, or 19%, increase in our average total MW in operation for
the year ended December 31, 2009 compared to 2008, was due to the reconsolidation of RockGen in December
2008.
Commodity Margin by Segment for the Years Ended December 31, 2008 and 2007
The following tables show our Commodity Margin and related operating performance metrics by segment
for the years ended December 31, 2008 and 2007. Our 2008 and 2007 Commodity Margin by segment
information has been recast to conform to the current year presentation. In the “Change” and “% Change”
columns below, favorable variances are shown without brackets while unfavorable variances are shown with
brackets. The MWh generated by segment below represents generation from power plants that we both
consolidated and operate.
West:
2008
2007
Change % Change
Commodity Margin (in millions) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commodity Margin per MWh generated . . . . . . . . . . . . . . . . . . . . . . . . .
$ 1,255
$ 33.79
$ 1,172
$ 31.82
$ 83
$1.97
7%
6
MWh generated (in thousands)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average availability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average total MW in operation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average capacity factor, excluding peakers . . . . . . . . . . . . . . . . . . . . . . .
Steam Adjusted Heat Rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
37,137
89.1%
7,295
65.9%
7,267
36,837
300
90.8% (1.7)
7,320
65.2% 0.7
69
7,336
1
(2)
(25) —
1
1
West — Commodity Margin in our West segment increased by $83 million, or 7%, for the year ended
December 31, 2008, compared to the year ended December 31, 2007. The increase resulted primarily from higher
on-peak market spark spreads driven by higher natural gas prices and the favorable impact of new and
renegotiated power contracts for 2008. The Commodity Margin increase associated with the much stronger
commodity price environment was largely reflected in an $88 million year over year increase in the realized
value of non-region specific gas hedges and the settlement of commodity derivative instruments. The increase in
Commodity Margin was partially offset by lower realized margins in the fourth quarter of 2008 as compared to
the same period in 2007, and a negative year on year variance associated with natural gas storage inventory. In
2008, we recorded a loss on natural gas storage resulting from the decrease in market natural gas prices in late
summer through the fourth quarter of 2008, while in the fourth quarter of 2007 we recognized a positive impact
from sales of natural gas storage inventory.
74
Texas:
2008
2007
Change
% Change
Commodity Margin (in millions) . . . . . . . . . . . . . . . . . . .
Commodity Margin per MWh generated . . . . . . . . . . . . .
$
$
726
22.40
$
$
505
15.23
$
$
MWh generated (in thousands) . . . . . . . . . . . . . . . . . . . . .
Average availability . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average total MW in operation . . . . . . . . . . . . . . . . . . . .
Average capacity factor, excluding peakers . . . . . . . . . . .
Steam Adjusted Heat Rate . . . . . . . . . . . . . . . . . . . . . . . .
32,408
33,154
88.8%
7,147
51.6%
7,082
90.8%
7,146
53.0%
6,830
221
7.17
(746)
(2.0)
1
(1.4)
(252)
44%
47
(2)
(2)
—
(3)
(4)
Texas — Commodity Margin in our Texas segment increased by $221 million, or 44%, for the year ended
December 31, 2008, compared to 2007, due primarily to higher market spark spreads driven by higher natural gas
prices during the second and third quarters of 2008 and congestion pricing in the South and Houston zones in the
second quarter of 2008. Commodity Margin was also improved by higher realized spark spreads on hedged
positions in the fourth quarter of 2008 despite lower market spark spreads during the same period. Market spark
spreads decreased in September 2008 as compared to the same period in 2007 due to the impact of Hurricane Ike;
however, we were able to purchase replacement power at prices below our generation cost and hedged prices
during the same period, which had a favorable impact in September 2008. Included in the favorable year on year
comparison is a decrease in Commodity Margin as a result of an unfavorable year over year impact of $94
million from the allocation of non-region specific natural gas hedges and the settlement of commodity derivative
instruments. Generation in our Texas segment decreased by 2% due to an increase in planned outages for major
maintenance for the year ended December 31, 2008 compared to 2007. We experienced a 4% increase in our
Steam Adjusted Heat Rate for the year ended December 31, 2008 compared to 2007, resulting from the loss of
steam load due to the impact of Hurricane Ike, an extended outage at our Baytown power plant in the first and
second quarters of 2008 and lower steam demand from our customers during the second half of 2008.
Southeast:
2008
2007
Change
% Change
Commodity Margin (in millions) . . . . . . . . . . . . . . . . . . . . .
Commodity Margin per MWh generated . . . . . . . . . . . . . . .
$
$
264
20.59
$
$
256
17.30
$
$
8
3.29
MWh generated (in thousands) . . . . . . . . . . . . . . . . . . . . . . .
Average availability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average total MW in operation . . . . . . . . . . . . . . . . . . . . . .
Average capacity factor, excluding peakers . . . . . . . . . . . . .
Steam Adjusted Heat Rate . . . . . . . . . . . . . . . . . . . . . . . . . .
12,820
14,795
93.6%
6,183
26.6%
7,388
92.1%
7,204
25.6%
7,544
(1,975)
1.5
(1,021)
1.0
156
3%
19
(13)
2
(14)
4
2
75
Southeast — Commodity Margin in our Southeast segment increased by $8 million, or 3%, for the year
ended December 31, 2008 compared to 2007, resulting from the impact of more favorable hedge pricing, the
favorable impact of new power contracts and a gain of $21 million during the second quarter of 2008 related to
the temporary assignment of a transmission capacity contract. These increases were partially offset by a decrease
in market spark spreads realized on open positions for 2008 compared to 2007 and an unfavorable year over year
impact of $24 million from the allocation of non-region specific natural gas hedges and the settlement of
commodity derivative instruments. We experienced a 4% increase in our average capacity factor, excluding
peakers, and a 2% increase in our average availability for the year ended December 31, 2008 compared to 2007.
Despite higher availability, generation decreased 13% due to a 1,021 MW decrease in our average total MW in
operation following the sale of our interest in Acadia PP in 2007, the sale of Auburndale in 2008 and an
unplanned outage at our Carville power plant due to Hurricane Gustav during the third quarter of 2008.
North:
2008
2007
Change
% Change
Commodity Margin (in millions) . . . . . . . . . . . . . . . . . . . . .
Commodity Margin per MWh generated . . . . . . . . . . . . . . .
$
$
279
51.70
$
$
278
46.14
$
$
MWh generated (in thousands) . . . . . . . . . . . . . . . . . . . . . . .
Average availability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average total MW in operation . . . . . . . . . . . . . . . . . . . . . .
Average capacity factor, excluding peakers . . . . . . . . . . . . .
Steam Adjusted Heat Rate . . . . . . . . . . . . . . . . . . . . . . . . . .
5,397
92.6%
2,412
32.8%
7,584
6,025
87.4%
3,009
33.2%
7,646
1
5.56
(628)
5.2
(597)
(0.4)
62
—%
12
(10)
6
(20)
(1)
1
North — Commodity Margin in our North segment increased by $1 million resulting from higher hedged
levels at more favorable pricing during the third quarter of 2008 compared to the same period in 2007 and a $4
million favorable year over year impact from the allocation of non-region specific natural gas hedges and the
settlement of commodity derivative hedging instruments. These gains were largely offset by lower realized spark
spreads during the fourth quarter of 2008 compared to the same period in 2007 and the deconsolidation of
RockGen in January 2008. Generation in the North decreased 10% due primarily to lower generation at power
plants whose generation is contracted and controlled by third parties and outages at our Westbrook Energy
Center power plant during the second quarter of 2008.
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 GAAP, and
should be viewed as a supplement to and not a substitute for our results of operations presented in accordance
with GAAP. Our First Lien Credit Facility and certain of our other debt instruments, including the Commodity
Collateral Revolver, include a similar measure as a basis for our material covenants under those debt agreements
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 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.
76
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 income effects of impairment charges, non-cash
gains or losses on sales or dispositions of assets, any unrealized gains or losses and any non-cash realized gains
or losses from accounting for derivatives, stock-based compensation expense, operating lease expense, non-cash
gains and losses from intercompany foreign currency translations, reorganization items, major maintenance
expense, gains or losses on the repurchase or extinguishment of debt and any other extraordinary, unusual or
non-recurring items plus adjustments to reflect the Adjusted EBITDA from our unconsolidated investments. We
exclude these items from 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 attributable to Calpine on a consolidated basis for years ended December 31,
2009, 2008 and 2007 (in millions).
Net income attributable to Calpine . . . . . . . . .
Net loss attributable to noncontrolling
interest
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax expense . . . . . . . . . . . . . . . . . . . . .
Reorganization items . . . . . . . . . . . . . . . . . . . .
Other (income) expense and debt
extinguishment costs, net . . . . . . . . . . . . . . .
Interest expense, net . . . . . . . . . . . . . . . . . . . . .
Income from operations . . . . . . . . . . . . . . . . . . $
Add:
Adjustments to reconcile income from
operations to Adjusted EBITDA:
Depreciation and amortization expense,
excluding deferred financing costs(1)
. . . .
Impairment loss . . . . . . . . . . . . . . . . . . . . . .
Major maintenance expense . . . . . . . . . . . . .
Operating lease expense . . . . . . . . . . . . . . . .
Unrealized (gains) losses on commodity
derivative mark-to-market activity . . . . . .
(110)
Adjustments to reflect Adjusted EBITDA
from unconsolidated investments(2)(3) . . . .
Stock-based compensation expense . . . . . . .
Non-cash loss on dispositions of assets . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(16)
17
11
5
2009
West
Texas
Southeast
North
Consolidation
and
Elimination
Total
$
149
(4)
15
(1)
92
813
732 $
166 $
47 $
126
$
(7) $
1,064
207
4
88
21
130
—
49
—
59
—
12
14
—
84
—
32
—
14
—
6
5
—
67
—
5
26
(42)
33
3
2
—
(8)
—
—
—
—
—
—
—
—
480
4
174
47
(79)
17
38
32
5
Adjusted EBITDA . . . . . . . . . . . . . . . . . . $
959 $
430 $
188 $
220
$
(15) $
1,782
77
Net income attributable to Calpine . . . . . . . . . .
Net loss attributable to noncontrolling
interest
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Discontinued operations, net of tax expense . . .
Income tax benefit
. . . . . . . . . . . . . . . . . . . . . . .
Reorganization items . . . . . . . . . . . . . . . . . . . . .
Other (income) expense and debt
extinguishment costs, net . . . . . . . . . . . . . . . .
Interest expense, net . . . . . . . . . . . . . . . . . . . . . .
Income (loss) from operations . . . . . . . . . . . . . . $
Add:
Adjustments to reconcile income (loss) from
operations to Adjusted EBITDA:
Depreciation and amortization expense,
excluding deferred financing costs(1)
. . . . .
Impairment loss . . . . . . . . . . . . . . . . . . . . . . .
Major maintenance expense . . . . . . . . . . . . . .
Operating lease expense . . . . . . . . . . . . . . . . .
Non-cash realized gains on derivatives . . . . .
Unrealized (gains) losses on commodity
derivative mark-to-market activity . . . . . . .
Adjustments to reflect Adjusted EBITDA
from unconsolidated investments(2)(3) . . . . .
Stock-based compensation expense . . . . . . . .
Non-cash loss on dispositions of assets . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2008(4)
West
Texas
Southeast
North
Consolidation
and
Elimination
Total
$
10
(1)
(23)
(47)
(302)
27
1,024
374 $
427 $
(168) $
37 $
18 $
688
195
13
95
21
—
86
55
23
10
(5)
129
—
62
—
(40)
92
213
20
—
—
(138)
(27)
—
16
12
3
6
8
10
—
56
—
14
25
—
44
15
3
3
(1)
(5)
—
(1)
—
—
—
—
—
(1)
—
467
226
190
46
(40)
(35)
76
50
34
(3)
Adjusted EBITDA . . . . . . . . . . . . . . . . . . . $
867 $
471 $
154 $
196 $
11 $ 1,699
78
Net income attributable to Calpine . . . . . . . .
Net loss attributable to noncontrolling
interest
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax benefit
. . . . . . . . . . . . . . . . . . . . .
Reorganization items . . . . . . . . . . . . . . . . . . .
Other (income) expense and debt
extinguishment costs, net . . . . . . . . . . . . . .
Interest expense, net . . . . . . . . . . . . . . . . . . . .
Income (loss) from operations . . . . . . . . . . . . $
Add:
Adjustments to reconcile income (loss)
from operations to Adjusted EBITDA:
Depreciation and amortization expense,
. . .
excluding deferred financing costs(1)
Impairment loss . . . . . . . . . . . . . . . . . . . . .
Major maintenance expense . . . . . . . . . . . .
Operating lease expense . . . . . . . . . . . . . . .
Non-cash realized (gains) losses on
derivatives . . . . . . . . . . . . . . . . . . . . . . .
Unrealized (gains) losses on commodity
derivative mark-to-market activity . . . . .
Adjustments to reflect Adjusted EBITDA
from unconsolidated investments(2)(3) . . .
Stock-based compensation expense
(income) . . . . . . . . . . . . . . . . . . . . . . . . .
Non-cash loss on dispositions of assets . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2007(4)
West
Texas
Southeast
North
Consolidation
and
Elimination
Total
$
2,693
—
(546)
(3,258)
(139)
1,955
507 $
175 $
(12) $
38 $
(3) $
705
213
10
35
20
4
15
8
(1)
12
—
129
—
38
—
(62)
16
—
—
11
(5)
113
2
14
—
3
2
—
—
5
9
55
34
12
34
1
2
13
—
5
(3)
(3)
—
(1)
—
—
—
—
—
—
—
507
46
98
54
(54)
35
21
(1)
33
1
Adjusted EBITDA . . . . . . . . . . . . . . . . . $
823 $
302 $
136 $
191 $
(7) $
1,445
(1) Depreciation and amortization expense in the income (loss) from operations calculation on our Consolidated
Statements of Operations excludes amortization of other assets and amounts classified as sales, general and
other administrative expenses.
(2)
Included in our Consolidated Statements of Operations in (income) loss from unconsolidated investments in
power plants.
(3) Adjustments to reflect Adjusted EBITDA from unconsolidated investments include $(47) million, $55
million and $17 million in unrealized (gains) losses on mark-to-market activity for the years ended
December 31, 2009, 2008 and 2007, respectively.
(4) Adjusted EBITDA for years ended December 31, 2008 and 2007, has been recast to conform to the current
year presentation.
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
and to meet certain near-term debt repayment obligations is dependent on maintaining sufficient liquidity.
79
Liquidity
As of December 31, 2009, we had $989 million in cash and cash equivalents and $562 million of
restricted cash. Our availability under our First Lien Credit Facility revolver as of December 31, 2009, is $794
million for future letters of credit or cash borrowings. The following table provides a summary of our liquidity
position at December 31, 2009 and 2008 (in millions):
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents, corporate(1)
Cash and cash equivalents, non-corporate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restricted cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Letter of credit availability(2)
Revolver availability(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
725
264
989
562
34
794
Total current liquidity availability(4)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
2,379
$
1,361
296
1,657
503
2
16
2,178
2009
2008
(1)
Includes $9 million and $169 million of margin deposits held by us posted by our counterparties as of
December 31, 2009 and 2008, respectively.
(2) Additional available balances for Calpine Development Holdings, Inc. As of December 31, 2009, we have
the option to increase our availability by an additional $50 million under this letter of credit facility by
satisfying certain conditions.
(3) We repaid $725 million previously drawn on our First Lien Credit Facility revolver on September 28, 2009.
(4) Excludes contingent amounts of $150 million under the Knock-in Facility and $200 million under the
Commodity Collateral Revolver as of December 31, 2008.
Volatility in the financial markets in late 2008 and continuing into 2009, including the failure or merger
of certain financial institutions and continued uncertainty surrounding the stability of others continues to constrict
access to capital and credit markets in the U.S. and worldwide, including within our industry, for us and for our
counterparties. As a result, we and the industry have experienced increased credit and liquidity risk over the past
year. Although there have been some signs of economic recovery, we are unable to predict the timing, strength or
related impacts that a recovery, if any, will have on us, our counterparties or the current volatility in the financial
markets. Additionally, while we have been successful in completing significant financing transactions in 2009,
we cannot provide any assurance that we will continue to be successful in the future. Consequently, current
uncertain economic conditions and volatile financial markets may persist during 2010 or possibly longer. Even if
we are not impacted directly, we could be impacted indirectly in the event our counterparties are unable to
perform under their contractual obligations with us. We actively monitor our exposure to our counterparties
including their credit status.
Downward pressure on our Commodity Margin continues to be a risk as a result of the current economic
conditions. As of December 31, 2009, we have economically hedged a substantial portion of our generation and
natural gas portfolio mostly through power and natural gas forward physical and financial transactions for 2010;
however, we remain susceptible to significant price movements for 2011 and beyond. The future impact on our
Commodity Margin, primarily beyond 2010, is highly dependent on the severity and duration of the economic
downturn, the speed, strength and duration of an economic recovery, if any, and our continued ability to
successfully hedge our Commodity Margin. During pronounced recessionary periods, there can be a decrease in
power demand primarily driven by decreased usage by the industrial and manufacturing sectors. This “softening”
of demand typically results in more demand satisfied by baseload and intermediate units using lower variable
cost fuel sources, such as coal and nuclear fuel, and less demand served by higher variable cost units such as
80
natural gas-fired peaker power plants. Additionally, a recessionary environment can result in lower natural gas
prices, which may adversely impact our Commodity Margin as our cost of production advantage relative to less
efficient natural gas-fired generation is diminished on an absolute basis.
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 February 5, 2010, an
increase of $1/MMBtu in natural gas prices would result in an increase of collateral required by approximately
$46 million. If natural gas prices decreased by $1/MMBtu, we estimate that our collateral requirements would
decrease by approximately $19 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; therefore, we derived a statistical analysis that implies that a
change of $1/MMBtu in natural gas approximates an average Market Heat Rate change of 170 Btu/KWh. We
estimate that as of February 5, 2010, an increase of 170 Btu/KWh in the Market Heat Rate would result in an
increase in collateral required by approximately $23 million. If Market Heat Rates were to fall at a similar rate,
we estimate that our collateral required would decrease by $23 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.
In order to reduce the cash collateral and letters of credit that we would otherwise be required to provide
to our counterparties, we have granted additional liens on the assets currently subject to liens under our First Lien
Credit Facility to collateralize our obligations under certain of our power and natural gas agreements that qualify
as “eligible commodity hedge agreements” under our First Lien Credit Facility and First Lien Notes, and certain
of our interest rate swap agreements. The counterparties under such agreements will share the benefits of the
collateral subject to such liens ratably with the lenders under our First Lien Credit Facility. During 2009, we have
increased our usage of these additional liens in order to help manage cash collateral that would otherwise be
required. See Note 10 of the Notes to Consolidated Financial Statements for further information on our margin
deposits and collateral used for commodity procurement and risk management activities.
It is difficult to predict future developments and the amount of credit support that we may need to provide
as part of our business operations should financial market and commodity price volatility and the economic
downturn persist for a significant period of time; however, 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. Our ability to generate sufficient cash is dependent upon,
among other things:
•
•
•
•
improving the profitability of our operations;
continued compliance with the covenants under our First Lien Credit Facility, First Lien Notes and
other existing financing obligations;
stabilizing and increasing future contractual cash flows; and
our significant counterparties performing under their contracts with us.
Capital Resources and Management
During 2009, we have opportunistically completed several financing transactions to strengthen our
balance sheet and improve our flexibility and management of our capital structure. For a more detailed
discussion of our 2009 financing transactions, our debt and related terms, see Note 7 of the Notes to Consolidated
Financial Statements. Significant 2009 financing transactions are summarized below.
81
Steamboat Amended Credit Facility — On November 24, 2009, Steamboat amended and extended the
terms of its credit agreement. The Steamboat Amended Credit Facility increases the amount of term loans
outstanding by $17 million from $448 million to $465 million. The increase in the borrowing was used to pay
accrued and unpaid interest, breakage costs and other fees in connection with closing the Steamboat Amended
Credit Facility. The Steamboat Amended Credit Facility also provides for a “security fund” letter of credit
facility of up to $11 million and a “DSR” letter of credit facility of up to approximately $23 million. The
maturity date of the term loans has been extended from December 2011 to November 24, 2017. The security fund
letter of credit facility matures on November 24, 2017 with the term loans and the DSR letter of credit facility
matures on September 29, 2017.
Amendment of First Lien Credit Facility and Issuance of First Lien Notes due 2017 — We executed the First
Amendment to Credit Agreement and Second Amendment to Collateral Agency and Intercreditor Agreement dated
as of August 20, 2009, which amended both the First Lien Credit Facility Credit Agreement and the First Lien
Credit Facility Collateral Agency and Intercreditor Agreement. The amendment provides additional flexibility with
our capital structure and First Lien Credit Facility by granting us the option, subject to certain conditions, to buy
back debt at a discount using cash on hand via an auction process; to offer first lien bonds in exchange for or to
retire First Lien Credit Facility term loans; to issue up to $2.0 billion of first lien bonds in lieu of issuing first lien
term loans under the accordion provision of our First Lien Credit Facility; and to extend all or a portion of the
revolver and term loan maturities, on revised terms, subject to acceptance by applicable lenders. In addition, the
amendment provides for the aggregation of various investment and capital expenditure baskets for covenant
purposes. We subsequently issued approximately $1.2 billion aggregate principal amount of First Lien Notes in a
private placement on October 21, 2009. We received no net cash proceeds from the transaction. The offer and sale
of our First Lien Notes was consummated as a permitted debt exchange pursuant to our First Lien Credit Facility in
exchange for a like principal amount of First Lien Credit Facility term loans. Upon their exchange for First Lien
Notes, such term loans were canceled and may not be redrawn.
CCFC Refinancing — On May 19, 2009, our wholly owned subsidiaries, CCFC and CCFC Finance,
issued approximately $1.0 billion aggregate principal amount of CCFC New Notes in a private placement. The
CCFC New Notes mature on June 1, 2016. The CCFC New 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. The net proceeds received of $939 million, together with CCFC cash on hand of $271 million, were used
to:
•
•
•
•
repay the $364 million outstanding under the CCFC Term Loans on May 19, 2009;
redeem the $415 million outstanding principal amount of CCFC Old Notes on June 18, 2009;
distribute $327 million to CCFC’s indirect parent, CCFCP, which was used by CCFCP to redeem its
$300 million CCFCP Preferred Shares on or before July 1, 2009; and
in each case, pay any interest, prepayment penalties and other amounts due through the date of such
repayment or redemption.
As a result of the CCFC Refinancing transactions, we were able to extend the maturities of approximately
$1.0 billion of debt by several years, at the same time converting it from a floating to a fixed interest rate and
lowering our effective interest rate on such debt to 8.0% from a current weighted average interest rate of
approximately 9.4% with respect to the CCFC Term Loans, CCFC Old Notes and CCFCP Preferred Shares.
Concurrent with the CCFC Refinancing, we replaced various intercompany agreements with our CCFC
subsidiaries for the related sales and purchases of power, natural gas and the operation and maintenance of our
CCFC power plants, which did not materially impact our results of operations, financial condition or cash flows
on a consolidated basis. While there is no direct recourse by holders of the CCFC New Notes to Calpine
Corporation, a substantial portion of the commodity price risk related to CCFC’s power generation is absorbed
by Calpine Corporation as an indirect wholly owned subsidiary of Calpine Corporation purchases the power
generated by CCFC under an intercompany tolling agreement, which is also guaranteed by Calpine Corporation.
82
Deer Park Financing — On January 21, 2009, Deer Park, our indirect wholly owned subsidiary, closed
on $156 million of senior secured credit facilities, which include a $150 million term facility and a $6 million
letter of credit facility. Proceeds received were used to settle an existing commodity contract of approximately
$79 million, pay financing and legal fees of approximately $8 million and fund approximately $22 million in
restricted cash. The remainder was distributed to Calpine Corporation for general corporate purposes. The senior
term loan facility matures on January 21, 2012.
Letter of Credit Facilities — The table below represents amounts issued under our letter of credit facilities
as of December 31, 2009 (in millions):
First Lien Credit Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Calpine Development Holdings, Inc.
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Various project financing facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
2009
206
116
90
412
Cash Management — We manage our cash in accordance with our intercompany cash management
system subject to the requirements of our First Lien Credit 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, generally exceed FDIC insured limits or 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
credit-worthy 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 do not expect to pay any cash dividends on our common stock for the foreseeable future because we
are currently prohibited under our First Lien Credit Facility and certain of our other debt agreements from paying
cash dividends. 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.
NOLs — We have significant NOLs that will provide future tax deductions if we generate sufficient
taxable income, and do not become subject to significant limitations under Section 382 of the IRC during the
applicable carryover periods. Our federal and state income tax reporting group is comprised primarily of two
groups, CCFC and its subsidiaries, which we refer to as the CCFC group and Calpine Corporation and its
subsidiaries other than CCFC, which we refer to as the Calpine group. As of December 31, 2009, our
consolidated federal NOLs totaled approximately $7.5 billion, which consists of approximately $7.0 billion from
the Calpine group and approximately $513 million from the CCFC group. Approximately $5.5 billion of our
NOLs have annual limitations under Section 382 of the IRC. Subject to limitations, Section 382 amounts not
used can be carried forward to succeeding years. In addition, as of December 31, 2009, we have approximately
$1.1 billion in foreign NOLs and $4.6 billion in state NOLs on a consolidated basis. The Calpine group has
recorded a valuation allowance against the deferred taxes related to most of their NOLs as we determined it is
more likely than not that they will expire unutilized.
Project Development, Upgrades and Growth Initiatives
We continue to review development opportunities, which were put on hold during the pendency of our
Chapter 11 cases, to determine whether future actions are appropriate and we may pursue new opportunities that
arise, particularly if power contracts and financing are available and attractive returns are expected.
OMEC — OMEC began commercial operations on October 3, 2009. The completion of OMEC added
approximately 608 MW of baseload (with peaking) capacity representing our unconsolidated net interest in the
power plant.
83
Russell City Energy Center — Russell City Energy Center remains under advanced development. The
Russell City Energy Center is currently contracted to deliver its full output to PG&E under a PPA, which was
executed in December 2006 and approved by the CPUC in January 2007. The PPA was amended in 2008 and
was approved by the CPUC on April 16, 2009. On February 4, 2010, we received the PSD air permit, the final
permit necessary, to begin construction of our Russell City Energy Center. We hope to complete financing and
break ground for this new state-of-the-art power plant during 2010 with commercial operations scheduled to
begin in 2013. We do not expect the costs to complete the Russell City Energy Center to be material to us on a
consolidated basis. Upon completion, this project would bring on line approximately 362 MW of net interest
baseload capacity (390 MW with peaking capacity) representing our 65% interest.
Los Esteros Critical Energy Center — During 2009, we and PG&E negotiated a new agreement to
replace the existing CDWR contract and facilitate the upgrade of our Los Esteros Critical Energy Facility from a
188 MW simple-cycle generation power plant to a 308 MW combined-cycle generation power plant. In addition
to the increase in capacity, the upgrade will increase the efficiency and environmental performance of the power
plant by lowering the Heat Rate.
Geysers Development and Investment Tax Credits — We are currently seeking to take advantage of
certain incentives under the American Recovery and Reinvestment Act of 2009, also referred to as the Stimulus
Bill, that could impact our growth and development of our Geysers Assets. Specifically, the Stimulus Bill:
•
•
•
extends the placed-in-service deadline through 2013 for geothermal projects to qualify for
“production tax credits”;
allows geothermal developers to elect to receive a 30% “investment tax credit” in lieu of production
tax credits with respect to certain new construction of “qualified property” placed in service during
2009 or 2010 (or, in certain cases, after 2010), or 10% on re-powering of existing power plants or a
cash grant in lieu of investment tax credits or production tax credits with respect to such qualified
property (subject to satisfying certain procedural and other requirements mandated by recently-issued
Department of Treasury guidance); and
designates $6.0 billion in funds to serve as a loss reserve and source of funding for a federal loan
guarantee program anticipated to backstop renewable energy project financing.
In December 2009, we filed for cash grants of approximately $2 million in lieu of the 10% investment tax
credit on two of our re-power projects. We expect that any new geothermal power plant development of our
Geysers Assets will qualify for the 30% investment tax credit from the U.S. Internal Revenue Service, and our
additional projects for the re-powering of our existing power plants will qualify for the 10% investment tax
credit.
Major Maintenance and Capital Spending — Our major maintenance and capital spending remains an
important part of our business. Our expected expenditures for 2010 are the following (in millions):
Major maintenance expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital expenditures, operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Turbine upgrades and Geysers Assets expansion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total major maintenance expense and capital spending . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
2010
178
112
290
50
340
We believe that upgrades and expansions to our current assets offer proven and financially disciplined
opportunities to improve our operations, capacity and efficiencies. We are in the process of upgrading certain of
84
our Siemens turbines to increase our generation capacity by approximately 180 MW. These upgrades began in
the fourth quarter of 2009 and are scheduled through 2014 with estimated remaining capital expenditures of
approximately $87 million as of December 31, 2009. Our expected capital expenditures for each of the next five
years for major maintenance and for operations are expected to average approximately $300 million.
These amounts do not include approximately $85 million, which we expect to incur in 2010 for the new
construction for Russell City Energy Center and upgrade of the Los Esteros Critical Energy Facility.
Prior Asset Sales and Purchase — A significant component of our restructuring activities was to return
our focus to our core strategic assets. As a result of the review of our asset portfolio performed during our
Chapter 11 restructuring, during 2008 and 2007, we have sold or otherwise disposed of the Fremont and Hillabee
development projects, our equity interests in Auburndale and Acadia PP and our assets related to the Parlin
Power Plant, PSM, Goldendale Energy Center and the Aries Power Plant. In addition, we purchased the assets of
the RockGen Energy Center in 2008. See Notes 4 and 6 of the Notes to Consolidated Financial Statements for
additional discussion of these asset sales and purchase. While we have made no significant asset dispositions or
purchases in 2009, we continually evaluate our portfolio of assets and may take such actions in the future if we
believe they will optimize our existing assets.
Cash Flow Activities
The following table summarizes our cash flow activities for the years ended December 31, 2009, 2008
and 2007 (in millions):
2009
2008
2007
Beginning cash and cash equivalents . . . . . . . . . . . . . . . . . . . . .
$
1,657
$
1,915
$
1,077
Net cash provided by (used in):
Operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net (decrease) increase in cash and cash equivalents . . . .
761
(250)
(1,179)
(668)
494
516
(1,268)
(258)
187
473
178
838
Ending cash and cash equivalents . . . . . . . . . . . . . . . . .
$
989
$
1,657
$
1,915
2009 — 2008
Net Cash Provided By Operating Activities
Cash provided by operating activities for the year ended December 31, 2009, improved to $761 million
compared to $494 million for the year ended December 31, 2008. Our improvement in cash provided by
operating activities was primarily due to:
• Gross profit — Gross profit, excluding changes in unrealized mark-to-market activity, depreciation
expense and loss on asset disposals, increased by $26 million for the year ended December 31, 2009,
as compared to 2008. This was attributable to higher Commodity Margin and lower cash operating
costs in 2009.
•
Interest paid — Cash paid for interest decreased by $299 million to $761 million for the year ended
December 31, 2009, as compared to $1,060 million for 2008, primarily due to the repayment of the
Second Priority Debt, and, to a lesser extent, lower interest rates for the comparable period in 2009.
•
Reorganization items — Cash payments for reorganization items decreased by $115 million.
• Cash taxes — Net cash received for taxes increased by $33 million.
85
Our improvements in cash provided by operating activities were partially offset by the following:
• Working capital — Working capital employed, after adjusting for debt related balances and derivative
activities which did not impact cash provided by operating activities, increased by approximately
$152 million for the year ended December 31, 2009 compared to 2008. The increase was primarily
due to the sale during 2008 of assets previously reflected as assets held for sale at December 31, 2007
offset by a net reduction in working capital employed in 2009 for margins and net accounts receivable
and payable.
• Debt extinguishment costs — Cash payments for debt extinguishment costs in 2009 were $39 million
related to the CCFC Refinancing, compared to cash payments of $6 million related to the refinancing
of Blue Spruce and Metcalf in 2008.
Net Cash Provided By (Used In) Investing Activities
Cash flows used in investing activities for the year ended December 31, 2009, were $250 million
compared to cash flows provided by investing activities of $516 million for the year ended December 31, 2008.
The decrease in cash flows from investing activities was primarily due to:
•
•
•
Sales of power plants, turbines and investments — We had no significant asset sales in 2009
compared to $413 million of cash received primarily from the sales of the Fremont and Hillabee
development projects in 2008.
Sales of discontinued operations — We had no significant asset sales in 2009 compared to $79
million of cash received from the sale of Rosetta in 2008.
Reconsolidation of our Canadian Debtors and other deconsolidated foreign entities — In 2008, we
had a favorable cash effect of $64 million from the reconsolidation of our Canadian Debtors and other
deconsolidated foreign entities.
• Contributions to unconsolidated investments — Contributions increased by $2 million in 2009
primarily due to the funding of OMEC offset by reduced contributions to Greenfield LP.
•
Return of investment from unconsolidated investments — For the year ended December 31, 2009, we
received distributions of $9 million compared to $27 million for the year ended December 31, 2008.
• Capital expenditures — Capital expenditures increased by $36 million resulting from our
maintenance programs and turbine upgrades.
•
Increase in restricted cash — Restricted cash increased $59 million in 2009 compared to a $78
million decrease in 2008 primarily due to our refinancing activities.
Net Cash Used In Financing Activities
Due to our emergence from Chapter 11 during the first quarter of 2008, our financing activities are not
directly comparable. Cash used in financing activities for the year ended December 31, 2009, resulted in a net
outflow of $1.2 billion compared to a net outflow of $1.3 billion for the same period in 2008. Our significant
cash flows from our 2009 and 2008 financing transactions are described below:
• During the year ended December 31, 2009, we repaid approximately $725 million previously drawn
on our First Lien Credit Facility revolver and we made a net pay down of approximately $119 million
when we refinanced the CCFC Old Notes, CCFC Term Loans and CCFC Preferred Shares with the
86
CCFC New Notes. We also made scheduled repayments of approximately $60 million under our First
Lien Credit Facility term loans and $280 million on notes payable, other project debt and capital lease
obligations.
• During 2008, we borrowed approximately $4.2 billion under our First Lien Facilities and used that
borrowing and cash on hand to repay approximately $3.7 billion of the Second Priority Debt, $1.1
billion on the senior secured revolver, $300 million on the bridge facility, and $143 million of First
Lien Credit Facility term loans. In addition, we received proceeds of $355 million from refinancing
Metcalf and Blue Spruce and repaid $585 million of other project debt, capital leases and notes
payable.
• We incurred finance costs of $65 million in 2009 to facilitate an amendment to our First Lien Credit
Facility term loans and to refinance CCFC, Deer Park and other project debt. During the year ended
December 31, 2008, we incurred $207 million of finance costs primarily related to closing on our
First Lien Facilities.
• We received $64 million from the settlement of derivatives with an other-than-insignificant financing
element for the year ended December 31, 2008.
2008 — 2007
Net Cash Provided By Operating Activities
Cash flows provided by operating activities for the year ended December 31, 2008, resulted in net inflows
of $494 million as compared to net inflows of $187 million for the same period in 2007. Cash flows from
operating activities were primarily due to increases in:
• Gross profit — Gross profit, excluding changes in depreciation and impairments, increased by $222
million in 2008 primarily due to higher spark spreads resulting from high gas prices during the first
half of the year. The favorable margins were partially offset by higher plant operating expenses.
•
Interest paid — Cash paid for interest decreased by $83 million to $1,060 million for the year ended
December 31, 2008, as compared to $1,143 million in 2007, primarily due to additional adequate
protection payments required while in Chapter 11 to holders of our Second Priority Debt in 2007.
• Working capital — Working capital employed relating to operating assets and liabilities changed by
approximately $53 million during the year, after adjusting for actual cash flows from derivative
activities that are included in net derivative assets and liabilities. This increase in 2008 was primarily
the result of a slight increase in inventory levels as compared to 2007.
Net Cash Provided By Investing Activities
Cash flows provided by investing activities for the year ended December 31, 2008, increased by $43
million to $516 million from $473 million for the year ended December 31, 2007. The difference was primarily
due to:
• Capital expenditures — Purchases for property, plant and equipment decreased by $53 million in
2008 as compared to 2007.
•
Sales of power plants, turbines and investments — Proceeds from asset sales decreased by $128
million in 2008 compared to 2007. See Note 6 of the Notes to Consolidated Financial Statements for
a list of assets sold during 2008 and 2007.
87
•
Sale of discontinued operations — Proceeds of $79 million were received in 2008 from the sale of
Rosetta.
• Deconsolidation and reconsolidation — We experienced a favorable effect on cash of $64 million
from the reconsolidation of our Canadian Debtors and other deconsolidated foreign entities in 2008,
as compared to an unfavorable effect on cash of $29 million for the deconsolidation of OMEC in
2007.
• Contributions to unconsolidated investments — Contributions decreased by $51 million in 2008
primarily due to the completion of the Greenfield LP project financing in May 2007.
•
Return of investment from unconsolidated investments — For the year ended December 31, 2008, we
received cash of $27 million as a partial return of investment compared to $104 million received from
Greenfield LP and $75 million related to the Canadian Debtors and other deconsolidated foreign
entities for the year ended December 31, 2007.
• Decrease in restricted cash — The net reduction in restricted cash was $78 million, compared to a
$37 million decrease in 2007. Restricted cash decreased in 2008 mainly due to paying down debt and
refinancing activities.
Net Cash Provided By (Used In) Financing Activities
Cash flows used in financing activities for the year ended December 31, 2008, resulted in net outflows of
approximately $1.3 billion, as compared to cash provided by financing activities of $178 million for the year
ended December 31, 2007; because of our emergence from Chapter 11 in 2008, our cash flows provided by (used
in) our financing activities are not directly comparable to 2007. The significant transactions and changes in our
financing activities as compared to 2007 are described below:
•
•
•
•
Borrowings and repayments under our First Lien Facilities — On and subsequent to the Effective
Date, we borrowed $4.2 billion under our First Lien Facilities and used cash on hand to repay a
portion of the Second Priority Debt and to fund other cash payment obligations under our Plan of
Reorganization, working capital and other general corporate purposes. In addition, for the year ended
December 31, 2008, we repaid approximately $1.5 billion of borrowings under our First Lien
Facilities consisting of the repayment of the $300 million bridge facility, with the remainder applied
to repayments under our First Lien Credit Facility, primarily the revolving facility thereunder, and
$725 million of which amount was subsequently reborrowed in October 2008. For the year ended
December 31, 2007, borrowings under our DIP Facility resulted in cash inflows of $614 million.
Repayment of debt obligations — During 2008 we repaid $275 million for project financing, which
primarily related to the Metcalf and Blue Spruce refinancings. During 2007, the repayment of debt
obligations, in general, related to only those project finance facilities and other borrowings associated
with our subsidiaries and affiliates that were not Calpine Debtors, except as otherwise ordered by the
U.S. Bankruptcy Court or the Canadian Court such as the repayment of $224 million of CalGen
Secured Debt pursuant to a settlement approved by the U.S. Bankruptcy Court.
Financing costs — We incurred financing costs of $207 million, primarily related to closing on our
First Lien Facilities in 2008, as compared to financing costs incurred in 2007 of $81 million primarily
related to the refinancing in March 2007 of the Original DIP Facility with the DIP Facility.
Preferred interests — For the year ended December 31, 2008, we paid $166 million for the
redemption or repayment of preferred interests primarily consisting of the repayment of $155 million
in preferred interests related to Metcalf, as compared to $9 million for the year ended December 31,
2007.
88
• Derivative contracts — We received $64 million from the settlement of derivatives with an other-
than-insignificant financing element for the year ended December 31, 2008.
Emergence from Chapter 11 and Implementation of Our Plan of Reorganization
We emerged from Chapter 11 on January 31, 2008. At the Petition Date, we carried $17.4 billion of debt
with an average interest rate of 10.3%. As a result of retiring unsecured debt with reorganized Calpine
Corporation common stock, proceeds received from the sale of certain of our assets and the repayment or
refinancing of certain of our project debt, we reduced our pre-petition debt by approximately $7.0 billion. Upon
our emergence from Chapter 11, we carried $10.4 billion of debt with an average interest rate of 8.1%.
In connection with our emergence from Chapter 11, we recorded certain “plan effect” adjustments to our
Consolidated Balance Sheet as of the Effective Date in order to reflect certain provisions of our Plan of
Reorganization. These adjustments included the distribution of approximately $4.1 billion in cash and the
authorized issuance of 485 million shares of reorganized Calpine Corporation common stock primarily for the
discharge of LSTC, repayment of the Second Priority Debt and for various other administrative and other post-
petition claims. As a result, our equity increased by approximately $8.9 billion. We borrowed approximately $6.4
billion under our First Lien Facilities, which was used to repay the outstanding term loan balance of $3.9 billion
(excluding the unused portion under the $1.0 billion revolver) under our DIP Facility. The remaining net
proceeds of approximately $2.5 billion were used to fund cash payment obligations under our Plan of
Reorganization including the repayment of a portion of the Second Priority Debt and the payment of
administrative claims. The reorganization items on our Consolidated Statements of Operations are primarily
driven by our financing and restructuring activities. Our historical financial performance during the pendency of
our Chapter 11 cases and CCAA proceedings is likely not indicative of our future financial performance.
See Note 16 of the Notes to Consolidated Financial Statements for further information regarding our
Chapter 11 proceedings and our emergence from Chapter 11.
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 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 marketing
counterparties. Currently, certain of our marketing counterparties within the energy industry have below
investment grade credit ratings. However, we do not currently have any significant exposures to counterparties
that are not paying on a current basis.
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 10 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.
As of December 31, 2009, our First Lien Credit Facility and our corporate rating had the following ratings
and commentary from Standard and Poor’s and Moody’s Investors Service:
First Lien Credit Facility rating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Corporate rating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commentary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
B+
B
Stable
Standard and Poor’s
Moody’s Investors
Service
B2
B2
Positive Watch
89
Off Balance Sheet Commitments of Our Power Plant Operating Leases and Our Unconsolidated
Subsidiaries
Some of our power plant operating leases include certain sale/leaseback transactions that are not reflected
on our balance sheet. All counterparties in these transactions are third parties that are unrelated to us. The sale/
leaseback transactions utilize special purpose entities formed by the equity investors with the sole purpose of
owning a power plant. Some of these operating leases contain customary restrictions on dividends, additional
debt and further encumbrances similar to those typically found in project finance debt instruments. We have no
ownership or other interest in any of these special purpose entities. See Note 17 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
is not reflected on our
Consolidated Balance Sheets. As of December 31, 2009, our equity method investees (Greenfield LP, OMEC and
Whitby) had aggregate debt outstanding of $873 million. Based on our pro rata share of each of the investments,
our share of such debt would be approximately $624 million. All such debt is non-recourse to us. See Note 4 of
the Notes to Consolidated Financial Statements for additional information on our investments.
that
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, 2009, are as follows (in millions):
Guarantee Commitments
2010
2011
2012
2013
2014 Thereafter
Total
Amounts
Committed
Amounts of Commitment Expiration per Period
Guarantee of subsidiary debt(1)
Standby letters of credit(2)(4) . . . . . . . . . . . . . . . . . . . . . .
Surety bonds(3)(4)(5) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Guarantee of subsidiary operating lease payments(4) . . .
. . . . . . . . . . . . . . . . . . . $
73 $
384
—
10
72 $
28
—
67
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 467 $ 167 $
70 $
—
—
5
75 $
66 $
—
—
5
71 $
54 $
—
—
5
647 $
—
4
216
982
412
4
308
59 $
867 $ 1,706
(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.
(2) The standby letters of credit disclosed above represent
those disclosed in Note 7 of the Notes to
Consolidated Financial Statements.
(3) The majority of surety bonds do not have expiration or cancellation dates.
(4) These are off balance sheet obligations.
(5) As of December 31, 2009, $4 million of cash collateral is outstanding related to these bonds.
90
Contractual Obligations — Our contractual obligations related to continuing operations as of
December 31, 2009, are as follows (in millions):
2010
2011
2012
2013
2014
Thereafter
Total
Total operating lease obligations(1) . . . . . . .
$
58
Debt(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ 464
Interest payments on debt(3)
. . . . . . . . . . . .
$ 438
Interest rate swap agreement
payments(3)
. . . . . . . . . . . . . . . . . . . . . . . .
$ 202
Purchase obligations:
Turbine commitments . . . . . . . . . . . . . . . .
. . . . . .
Commodity purchase obligations(4)
Land leases . . . . . . . . . . . . . . . . . . . . . . . . .
LTSAs . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other purchase obligations . . . . . . . . . . . . . . .
23
502
7
13
56
Total purchase obligations(5) . . . . . . . . . . . .
$ 601
112
$
48
$
47
$
33
627
$ 259
$ 138
$4,448
436
$ 417
$ 448
$ 288
$
$
$
335
$
633
3,508
$ 9,444
779
$ 2,806
96
$
43
$
(3) $
(5) $
(14) $
319
46
428
7
9
81
571
15
418
7
10
90
16
361
6
4
50
16
271
6
6
50
—
2,722
346
42
1,005
116
4,702
379
84
1,332
$ 540
$ 437
$ 349
$
4,115
$ 6,613
Liability for uncertain tax positions . . . . . .
Other contractual obligations(6)
. . . . . . . . .
$
$
1
13
$
18
$ — $ — $
37
$ — $
5
$ — $ — $
25
8
$
$
57
50
$
$
$
$
$
$
(1)
Included in the total are future minimum payments for power plant operating leases and office and
equipment leases. See Note 17 of the Notes to Consolidated Financial Statements for more information.
(2) A note payable totaling $77 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.
(3) Amounts are projected based upon interest rates at December 31, 2009.
(4) The amounts presented here are primarily the notional volumes for indexed fuel purchase contracts for the
purchase, transportation, or storage of commodities accounted for as executory contracts or as a normal
purchase normal sale and, therefore, not recognized as liabilities on our Consolidated Balance Sheets. See
“— Risk Management and Commodity Accounting” for a discussion of our commodity derivative contracts
recorded at fair value on our Consolidated Balance Sheets.
(5) The amounts included above for purchase obligations include the minimum requirements under contract.
(6) Represents cash obligations included in other current liabilities and long-term liabilities on our Consolidated
Balance Sheet as of December 31, 2009.
Special Purpose Subsidiaries
Pursuant to applicable transaction agreements, we have established certain of our entities legally separate
from Calpine and our other subsidiaries. In accordance with GAAP, we consolidate these entities. As of the date
of filing this Report, these entities included: Rocky Mountain Energy Center, LLC, Riverside Energy Center,
LLC, Calpine Riverside Holdings, LLC, PCF, PCF III, 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.), CCFCP and Russell City Energy Company, LLC.
The following disclosures are required under certain applicable agreements and pertain to some of these entities.
The financial information provided below represents the assets, liabilities, and results of operations for each of
the special purpose subsidiaries as reflected on our Consolidated Financial Statements. These amounts may differ
91
materially from the assets, liabilities, and results of operations for these entities that present individual financial
statements on a stand-alone basis to their project lenders.
On June 13, 2003, PCF, our wholly owned stand-alone subsidiary, completed an offering of two tranches of
senior secured notes due 2006 and 2010 with original principal amounts totaling $802 million. PCF’s senior secured
notes due 2006 were paid in accordance with their terms upon maturity in 2006 and are no longer outstanding.
PCF’s 6.256% senior secured notes due 2010 were paid in accordance with their terms upon maturity in February
2010 and are no longer outstanding. Pursuant to the applicable agreements relating to the issuance of PCF’s senior
secured notes, we are required to report the following information in this Form 10-K (in millions):
Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
203
90
See Note 7 of the Notes to Consolidated Financial Statements for further information.
In accordance with the terms thereof, the PCF III notes were repaid in accordance with their terms upon
maturity in February 2010 and are no longer outstanding. Pursuant to the applicable agreements relating to the
issuance of the PCF III notes, we are required to report the following information in this Form 10-K (in millions):
2009
2009
Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
114
85
See Note 7 of the Notes to Consolidated Financial Statements for further information.
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 September 30, 2003, GEC completed an offering of
$302 million of 4% senior secured notes due 2011. In connection with the issuance of the secured notes, we
received funding on a third party preferred equity investment in GEC Holdings, LLC totaling $74 million. This
preferred interest meets the criteria of a mandatorily redeemable financial instrument and has been classified as
debt due to certain preferential distributions to the third party. The preferential distributions are due semi-
annually beginning in March 2004 through September 2011 and total approximately $113 million over the eight-
year period. As of December 31, 2009 and 2008, there was $25 million and $35 million, respectively,
outstanding under the preferred interest.
A long-term PPA between CES and CDWR was acquired by GEC by means of a series of capital
contributions by CES and certain of its affiliates and is an asset of GEC, and the secured notes and the preferred
interest are liabilities of GEC, separate from the assets and liabilities of us and other subsidiaries of ours. In
addition to the PPA and nine peaker power plants (including Creed and Goose Haven) owned directly or
indirectly by GEC, GEC’s assets include cash and a 100% equity interest in each of Creed and Goose Haven,
each of which is a wholly owned subsidiary of GEC and a guarantor of the 4% senior secured notes due 2011
issued by GEC. Each of GEC, Creed and Goose Haven has been established as an entity with its existence
separate from us and other subsidiaries of ours. Creed and Goose Haven each have assets consisting of a peaker
power plant and other assets. The following table sets forth selected financial information of GEC for the year
ended December 31, 2009 (in millions):
Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
505
89
On December 4, 2003, we announced that we had sold to a group of institutional investors our right to
receive payments from PG&E under an agreement between PG&E and Gilroy regarding the termination and
buy-out of a standard offer contract between PG&E and Gilroy for $133 million in cash. Since the transaction did
2009
92
not satisfy the criteria for sales treatment in accordance with GAAP, it was recorded on our Consolidated
Financial Statements as a secured financing, with a note payable of $133 million. The notes receivable balance
and note payable balance are both reduced as PG&E makes payments to the buyers of the notes receivable. The
$24 million difference between the $157 million net book value of the notes receivable at the transaction date and
the $133 million cash received is recognized as additional interest expense over the repayment term. We will
continue to record interest income over the repayment term, and interest expense will be accreted on the
amortizing note payable balance.
Pursuant to the applicable transaction agreements, each of Gilroy and Calpine Gilroy 1, Inc. (the general
partner of Gilroy), has been established as an entity with its existence separate from us and other subsidiaries of
ours. The following table sets forth the assets and liabilities of Gilroy and Calpine Gilroy I, Inc. as of
December 31, 2009 (in millions):
Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
394
78
2009
See Notes 5 and 7 of the Notes to Consolidated Financial Statements for further information.
On June 29, 2004, Rocky Mountain Energy Center, LLC and Riverside Energy Center, LLC, wholly
owned subsidiaries of our Calpine Riverside Holdings, LLC subsidiary, received funding in the aggregate
amount of $661 million comprising $633 million of first priority secured floating rate term loans due 2011 and a
$28 million letter of credit-linked deposit facility.
Pursuant
to the applicable transaction agreements, each of Rocky Mountain Energy Center, LLC,
Riverside Energy Center, LLC and Calpine Riverside Holdings, LLC has been established as an entity with its
existence separate from us. The following table sets forth the assets and liabilities of these entities as of
December 31, 2009 (in millions):
Rocky Mountain
Energy Center, LLC
2009
Riverside
Energy Center, LLC
2009
Calpine Riverside
Holdings, LLC 2009
Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
390
152
$
724
320
404
—
See Note 7 of the Notes to Consolidated Financial Statements for further information.
On October 14, 2005, our indirect subsidiary CCFCP issued $300 million of six-year redeemable
preferred shares. The CCFCP Preferred Shares were mandatorily redeemable on the maturity date of October 31,
2011; however, these preferred shares were redeemed on or before July 1, 2009, and are no longer outstanding.
Pursuant to the applicable agreements relating to the issuance of the CCFCP Preferred Shares, we are required to
report the following information in this Form 10-K (in millions):
Assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1,829
1,007
2009
93
RISK MANAGEMENT AND COMMODITY ACCOUNTING
We actively seek to manage the commodity risks of our portfolio, utilizing multiple strategies of buying
and selling power or natural gas to manage our spark spread, or selling Heat Rate transactions.
We use derivative instruments, 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) for the purchase and
sale of power, natural gas, and emission allowances to manage commodity price risk and to maximize the risk-
adjusted returns from our power and natural gas assets. We also use interest rate swaps to manage the interest
rate risk of our variable rate debt. We conduct these 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.
Along with our portfolio of hedging transactions, we enter into power and natural gas positions that often
act as hedges to our asset portfolio, but do not qualify as hedges under hedge accounting guidelines, such as
commodity options transactions and instruments that settle on power price to natural gas price relationships (Heat
Rate swaps and options). While our selling and purchasing of power and natural gas is mostly physical in nature,
we also engage in marketing, hedging and optimization activities, particularly in natural gas, that are financial in
nature. While we enter into these transactions primarily to provide us with improved price and price volatility
transparency, as well as greater market access, which benefits our hedging activities, 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 either hedge accounting or the normal
purchase normal sale exemption are recognized currently in earnings in mark-to-market activity within operating
revenues in the case of power transactions, and within fuel and purchased energy expense, in the case of natural
gas transactions. Our future hedged status, and marketing and optimization activities are subject to change as
determined by our commercial operations group, Chief Risk Officer, Risk Management Committee of senior
management and Board of Directors.
We have economically hedged a substantial portion of our generation and natural gas portfolio mostly
through power and natural gas forward physical and financial transactions for 2010. By entering into these
transactions, we are able to economically hedge a portion of our spark spread at pre-determined generation and
price levels. We use a combination of PPAs and other hedging instruments to manage our variability in future
cash flows. As of December 31, 2009, the maximum length of our PPAs extends 22 years into the future and the
maximum length of time over which we were hedging using commodity and interest rate derivative instruments
was 3 and 16 years, respectively. Assuming constant December 31, 2009, power and natural gas prices and
interest rates, we estimate that pre-tax net losses of $94 million 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 natural gas and power prices as well as 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.
We enter into a variety of derivative instruments, 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) for
the purchase and sale of power, natural gas, and emission allowances as well as interest rate swaps. Derivative
contracts are measured at their fair value and recorded as either assets or liabilities unless they qualify for, and
we elect, the normal purchase normal sale exemption. All changes in the fair value of contracts accounted for as
derivatives are recognized currently in earnings (as a component of our operating revenues, fuel and purchased
94
energy expense, or interest expense) unless specific hedge criteria are met. The hedge criteria require us to
formally document, designate and assess the effectiveness of transactions that receive hedge accounting. The
actual amounts that will ultimately be settled will likely vary based on changes in natural gas prices and power
prices as well as changes in interest rates. Such variances could be material.
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 and MWh), changing commodity market prices, principally for
power and natural gas, liquidity risk, counterparty and our credit risk and changes in interest rates. Since prices
for power and natural gas are among the most volatile of all commodity prices, 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 and liabilities have decreased to approximately $1.3 billion and
$(1.6) billion at December 31, 2009, compared to $4.1 billion and $(4.5) billion at December 31, 2008,
respectively. As of December 31, 2009, the fair value of our level 3 derivative assets and liabilities represent only
a small portion of our total assets and liabilities (less than 1%). See Note 8 of the Notes to Consolidated Financial
Statements for further information related to our level 3 derivative assets and liabilities. There is a substantial
amount of volatility inherent in accounting for the fair value of these derivatives, and our results during the years
ended December 31, 2009 and 2008 have reflected this as discussed below.
The change in fair value of our outstanding commodity and interest rate derivative instruments from
January 1, 2009, through December 31, 2009, is summarized in the table below (in millions):
Interest Rate
Swaps
Commodity
Instruments
Total
Fair value of contracts outstanding at January 1, 2009 . . . . . . . . . . . . .
Losses 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, 2009(3)
. . . . . . . .
$
(452) $
198
4
(15)
(54)
(319) $
$
12
5
2
(11)
—
8
$
(440)
203
6
(26)
(54)
(311)
(1)
Interest rate settlements consist of recognized losses from interest rate cash flow hedges of $184 million and
recognized losses from undesignated interest rate swaps of $14 million (represents a portion of interest
expense as reported on our Consolidated Statements of Operations).
(2) Settlement of commodity contracts not designated as hedging instruments of $(92) million (represents a
portion of operating revenues and fuel and purchased energy expense as reported on our Consolidated
Statements of Operations) and $87 million related to recognition of gains from cash flow hedges, previously
reflected in OCI, offset by other changes in derivative assets and liabilities not reflected in OCI or net
income.
(3) Net commodity and interest rate derivative assets and liabilities reported in Notes 8 and 9 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 current earnings.
95
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 not designated as
hedging instruments and where these components were recorded on our Consolidated Statements of Operations
for the years ended December 31, 2009, 2008 and 2007 (in millions):
Realized gain (loss)
Interest rate swaps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commodity derivative instruments(1)
. . . . . . . . . . . . . . . . . . . . . . . . . . .
Total realized gain (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrealized gain (loss)
Interest rate swaps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commodity derivative instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total unrealized gain (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total mark-to-market activity . . . . . . . . . . . . . . . . . . . . . . . . . . .
2009
2008
2007
$
$
$
$
$
(35) $
37
2
10
79
89
91
$
$
$
$
(11) $
(146)
(157) $
(11) $
35
24
$
(133) $
5
40
45
(17)
(35)
(52)
(7)
(1) Balance includes a non-cash gain from amortization of prepaid power sales agreements of approximately
nil, $40 million and $54 million for the years ended December 31, 2009, 2008 and 2007, respectively.
Power contracts included in operating revenues . . . . . . . . . . . . . . . . . . .
Natural gas contracts included in fuel and purchased energy
$
expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest rate swaps included in interest expense . . . . . . . . . . . . . . . . . . .
Total mark-to-market activity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
91
$
(133) $
2009
2008
2007
7
$
232
$
252
109
(25)
(343)
(22)
(247)
(12)
(7)
Our change in AOCI from an accumulated loss of $158 million at December 31, 2008, to an accumulated
loss of $266 million at December 31, 2009, was primarily driven by reclassification adjustments for cash flow
hedges realized in net income and a decrease in interest rates, which were partially offset by decreases in
commodity prices and the effect of income taxes, which includes a net $43 million tax expense reclassified from
OCI to continuing operations related to the intraperiod tax allocation provisions under GAAP.
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, 2009, based on price
source and the period during which the instruments will mature, are summarized in the table below (in millions):
Fair Value Source
2010
2011-2012
2013-2014 After 2014
Total
Prices actively quoted . . . . . . . . . . . . . . . . . . . . . . . . . .
Prices provided by other external sources . . . . . . . . . .
Prices based on models and other valuation
methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(165) $
115
9 $
20
— $
(1)
— $
—
(156)
134
Total fair value . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(40) $
48 $
(1) $
10
19
—
1
1
$
30
8
We measure the commodity price risks in our portfolio on a daily basis using a VAR model to estimate
the maximum 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 commodity derivatives, power plants, PPAs, and other physical and financial transactions. The
96
portfolio VAR calculation incorporates positions for the remaining portion of the current calendar year 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,
2009 and 2008 (in millions):
Year ended December 31:
2009
2008
High . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Low . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Average . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
As of December 31 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
59
28
47
51
$
$
$
$
70
29
49
45
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 10 of the Notes to
Consolidated Financial Statements.
Credit Risk — Credit risk relates to the risk of loss resulting from non-performance 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 believe that our credit policies adequately monitor and diversify our credit risk. We currently have no
individual significant concentrations of credit risk to a single counterparty; however a series of defaults or events
of nonperformance by several of our individual counterparties could impact our liquidity and future results of
operations. 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, 2009, 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, 2009)
2010
2011-2012
2013-2014 After 2014
Total
Investment grade . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-investment grade . . . . . . . . . . . . . . . . . . . . . . . . . . . .
No external ratings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total fair value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(39) $
—
(1)
(40) $
49 $
—
(1)
48 $
(1) $
—
—
(1) $
— $
—
1
1
$
9
—
(1)
8
97
The fair value of our interest rate swaps are validated based upon external quotes. See further discussion
of our interest rate swaps in the “— Interest Rate Risk” section below.
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.
Our fixed rate debt instruments do not expose us to the risk of loss in earnings due to changes in market
interest rates. In general, such a change in fair value would impact earnings and cash flows only if we were to
reacquire all or a portion of the fixed rate debt in the open market prior to their maturity.
The following table summarizes the contract terms as well as the fair values of our financial instruments
exposed to interest rate risk as of December 31, 2009. All outstanding balances and fair market values are shown
gross of applicable premium or discount, if any (in millions):
2010
2011
2012
2013
2014
Thereafter
Total
Fair Value
December 31,
2009
Debt by Maturity Date:
Fixed Rate . . . . . . . . . . . . . . $
Average Interest Rate . . . . .
218 $
6.5%
71 $
6.9%
21 $
9.6%
24 $
9.6%
21 $
9.4%
2,312 $
7.6%
Variable Rate . . . . . . . . . . . . $
Average Interest Rate(1) . . . .
223 $
3.1%
528 $
4.5%
210 $
3.9%
88 $ 4,410 $
4.2%
4.9%
688 $
6.8%
2,667
6,147
$
$
2,609
5,863
(1) Projection based upon anticipated LIBOR rates.
Currently, we use interest rate swaps to adjust the mix between fixed and floating rate debt as a hedge of
our interest rate risk. We do not use interest rate derivative instruments for trading purposes. The majority of our
interest rate swaps mature in years 2010 through 2012. 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.
Holding all other factors constant, we estimate that a 10% adverse change in interest rates would result in a
change in the fair value of our interest rate swaps of approximately $(37) million.
APPLICATION OF CRITICAL ACCOUNTING POLICIES
The preparation of financial statements in accordance with 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
98
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 derivative;
a contract that meets the definition of a derivative but is eligible for the normal purchase normal sale
exemption;
a contract that is a physical or executory contract; or
a contract that qualifies as a lease.
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 or traditional accrual
accounting to contracts that are exempt from derivative accounting or do not meet the definition of a derivative
instrument.
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 capacity payments, which are not related to generation;
other revenues such as RMR Contracts, resource adequacy and certain ancillary service revenues; and
other service revenues including revenue related to the sales of combustion turbine component parts
and services from PSM prior to its sale in March 2007.
RMR Contracts, resource adequacy and other ancillary revenues are recognized when contractually
earned and consist of revenues received from our customer either at the market price or a contract price.
Lease Accounting — 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.
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 basis. With respect to our physical executory contracts, where we do not take title of 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. Our physical commodity contracts are not entered into for the purpose of
settling on a net basis with another counterparty.
Accounting for Derivative Instruments
We enter into a variety of derivative 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) for the purchase and sale of power, natural gas, and emission allowances. We also
use interest rate swaps to manage the interest rate risk of our variable rate debt. The majority of this activity is
related to the fuel and power price risk associated with our generation assets and our contractual obligations. We
99
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 the normal purchase normal sale exemption.
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 our derivatives in the same category as the item being hedged
within operating activities 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.
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 included in unrealized
mark-to-market gains and losses and are recognized currently in earnings as a component of operating revenues
(for power contracts), fuel and purchased energy expense (for natural gas contracts) and interest expense (for
interest rate swaps). If it is determined that the forecasted transaction is no longer probable of occurring, then
hedge accounting will be discontinued prospectively. If the hedging instrument is terminated or de-designated
prior to the occurrence of the hedged forecasted transaction, the gain or loss associated with the hedge instrument
remains deferred in OCI until such time as the forecasted transaction impacts earnings, or until it is determined
that the forecasted transaction is probable of not occurring.
Fair Value Hedges — Changes in fair value of derivatives designated as fair value hedges and the
corresponding changes in the fair value of the hedged risk attributable to a recognized asset or liability, or
unrecognized firm commitment are recorded in earnings. If the fair value hedge is effective, the amounts
recorded will offset in earnings. If the underlying asset, liability or firm commitment being hedged is disposed of
or otherwise terminated, the gain or loss associated with the underlying hedged item is recognized currently in
earnings. If the hedging instrument is terminated or de-designated prior to the settlement of the hedged asset,
liability or firm commitment, the carrying amount of the hedged item is adjusted by any gain or loss from the
hedging instrument and remains until the hedged item is recognized in earnings. As of December 31, 2009, we
had no fair value hedges; however, we had one fair value hedge at December 31, 2008 related to PCF.
Derivatives Not Designated as Hedging Instruments — Along with our portfolio of hedging transactions,
we enter into power, natural gas and interest rate transactions that primarily act as economic hedges to our asset
portfolio, but either do not qualify as hedges under hedge accounting guidelines or qualify under the hedge
accounting guidelines and the hedge accounting designation has not been elected, such as commodity futures,
forwards, options, fixed for floating swaps and instruments that settle on power price to natural gas price
relationships (Heat Rate swaps and options). Changes in fair value of derivatives not designated as hedging
instruments are recognized currently in earnings as a component of operating revenues (for power contracts and
Heat Rate swaps and options), fuel and purchased energy expense (for natural gas contracts) and interest expense
(for interest rate swaps).
Mark-to-Market Activity — A component of operating revenues (for power contracts), fuel and purchased
energy expense (for natural gas contracts) and interest expense (for interest rate swaps), includes realized
settlements and unrealized mark-to-market gains and losses resulting from general market price movements on
power, natural gas and interest rate swap derivative instruments not designated or not qualifying as cash flow
hedges. Gains and losses due to ineffectiveness on commodity hedging instruments are also included in
unrealized mark-to-market gains and losses.
Significant judgment and estimates used in accounting for our derivative instruments include contract
interpretation, valuation techniques and assumptions, assumptions used in forecasting future generation and
market expectations. As defined by GAAP, fair value is the price that would be received to sell an asset or paid to
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transfer a liability in the principal or most advantageous market in an orderly transaction between market
participants at the measurement date (exit price). 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.
The following is a summary of the most significant estimates and assumptions associated with the
calculation of fair value of our commodity derivative instruments.
Pricing — 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 risks and the
to the inputs in the valuation technique. These inputs can be readily observable, market
risks inherent
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; however, other qualitative assessments are used 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.
Valuation Techniques — In certain instances, we utilize models to measure fair value. These models are
primarily industry-standard models,
incorporate various
assumptions, including quoted interest rates and time value, as well as other relevant economic measures. 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.
including the Black-Scholes pricing model,
that
Credit Reserves — We assess non-performance risk by adjusting the fair value of our derivatives based
on the credit standing of the 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.
See Notes 8 and 9 of the Notes to Consolidated Financial Statements for further discussion of our
derivative instruments.
Accounting for VIEs and Financial Statement Consolidation Criteria
We consolidate all VIEs where we have determined that we are the primary beneficiary. This
determination is made at the inception of our involvement with the VIE and, in accordance with GAAP, is
updated only in response to a reconsideration event. We consider both qualitative and quantitative factors to form
a conclusion as to whether we, or another interest holder, absorbs a majority of the entity’s risk of expected
losses, receives a majority of the entity’s potential for expected residual returns, or both.
Making these determinations can require the use of significant judgment, both on a qualitative and
quantitative basis, which include, but are not limited to:
•
•
consideration of the design of the VIE, its purpose and variability is designed to create and pass along
to its interest holders;
preparation of future expected financial results and future expected cash flows from the VIE;
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•
•
•
assigning probabilities to future events, markets and potential outcomes, such as the exercise of
purchase options;
estimates in future residual fair values of power plant assets years into the future; and
determinations of our counterparties’ reasons and intentions for entering into the VIE.
If we determine that we will absorb a majority of a VIE’s expected losses, receive a majority of the
entity’s potential for expected residual returns or both, we consolidate the VIE in accordance with GAAP into
our Consolidated Financial Statements. Beginning on January 1, 2010, new accounting standards will change the
approach for determination of the primary beneficiary and will require us to perform an ongoing reassessment of
whether we continue to be the primary beneficiary, which may result in future deconsolidation or consolidation
of our VIEs.
We do not consolidate VIE’s where we have determined, at the inception of our involvement with the
VIE, that we are not the primary beneficiary. These include OMEC, a VIE and 100% owned subsidiary due to
purchase option rights, a 50% joint venture interest in Greenfield LP and a 50% equity interest in Whitby where
we do not have control and therefore do not consolidate. We account for these entities under the equity method of
accounting and include our net equity interest in investments on our Consolidated Balance Sheets as we exercise
significant influence over their operating and financial policies. Our equity interest in the net (income) loss from
our unconsolidated VIE, joint venture and equity interest is recorded in (income) loss from unconsolidated
investments in power plants.
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
the timing and amount of deprecation expense affecting our results of
depreciation methods can impact
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 is 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 is 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 using an estimated salvage value which approximates 10% of the depreciable cost basis for our power
plant assets 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 our rotable spares equipment. We use
component depreciation method for our rotable parts and composite depreciation method for all the other power
plant asset groups and Geysers Assets. During 2009, we reviewed our accounting policies related to depreciation
including our estimates of useful lives and salvage values. We determined changing from composite depreciation
to component depreciation for our rotable natural gas-fired power plant assets, and changing our Geysers Assets
depreciation from the units of production method to the straight line method was preferable under GAAP. In
addition, we completed a depreciable life study of our natural gas-fired power plants and Geysers Assets, and
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determined that a change in the depreciable lives of our natural gas-fired power plants and Geysers Assets was
appropriate. See Note 3 of the Notes to Consolidated Financial Statements for further discussion regarding our
changes in depreciation and the effective date of our changes.
Impairment Evaluation of Long-Lived Assets
We evaluate our long-lived assets, such as property, plant and equipment, equity method investments,
turbine equipment, patents, and specifically identified intangibles, 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 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. 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.
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.
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 charge.
The following summarizes some of the most significant estimates and assumptions used in evaluating if
we have an impairment charge.
Undiscounted Expected Future Cash Flows — In order to estimate future cash flows, we consider
historical cash flows, existing and future contracts and PPA’s 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). Certain
of our operating power plants are located in regions with depressed demand and Commodity Margin. Our
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forecasts generally assume that Commodity Margin will increase in future years in these regions as the supply
and demand relationships improve. 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.
Fair Value — Generally, fair value is determined using valuation techniques such as the present value of
expected future cash flows. 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.
The evaluation and measurement of impairments for equity method investments involve the same
uncertainties as described for long-lived assets that we own directly. Similarly, our estimates that we make with
respect to our equity and cost-method investments are subjective, and the impact of variations in these estimates
could be material.
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.
Our federal income tax reporting group is comprised primarily of two groups, CCFC and its subsidiaries,
which we refer to as the CCFC group, and Calpine Corporation and its subsidiaries other than CCFC, which we
refer to as the Calpine group. In 2005, CCFCP issued the CCFCP Preferred Shares, which resulted in the
deconsolidation of the CCFC group for income tax purposes. On July 1, 2009, the CCFCP Preferred Shares were
redeemed; however, CCFCP continues to be a partnership and therefore,
the CCFC group remains
deconsolidated from Calpine Corporation for federal income tax reporting purposes.
As of December 31, 2009, our NOL and credit carryforwards consists of federal carryforwards of
approximately $7.5 billion which expire between 2021 and 2029. This includes an NOL carryforward of
approximately $513 million for the CCFC group. 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 benefit of the 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.
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
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greater than 50% likely of being realized upon ultimate settlement with a taxing authority. We derecognize
previously recognized tax positions 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, 2009, we have $98 million of unrecognized tax benefits from uncertain tax
positions.
See Note 11 of the Notes to Consolidated Financial Statements for further discussion of our accounting
for income taxes.
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 Balance Sheets,” “Consolidated Statements of Operations,” “Consolidated
Statements of Comprehensive Income (Loss) and Stockholders’ Equity (Deficit),” “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 relating to our Company, including our consolidated subsidiaries, 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
principal executive officer and principal financial and accounting 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. Our internal control over financial reporting is a process designed to provide reasonable assurance
105
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with 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 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, 2009. 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, we have concluded that our internal control over financial reporting
was effective as of December 31, 2009.
The effectiveness of our internal control over financial reporting as of December 31, 2009, 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 2009, there were no changes in our internal control over financial reporting
that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
None.
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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
Age
Principal Occupation
Jack A. Fusco . . . . . . . . . . . .
Zamir Rauf . . . . . . . . . . . . . .
W. Thaddeus Miller . . . . . . .
John B. Hill . . . . . . . . . . . . . .
Jim D. Deidiker . . . . . . . . . . .
Gary M. Germeroth . . . . . . . .
47 President and Chief Executive Officer
50 Executive Vice President and Chief Financial Officer
59 Executive Vice President, Chief Legal Officer and Secretary
42 Executive Vice President and Chief Commercial Officer
54 Senior Vice President and Chief Accounting Officer
51 Executive Vice President and Chief Risk Officer
Jack A. Fusco has served as our President and Chief Executive Officer and as a member of our Board of
Directors since August 10, 2008. 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, Mr. Fusco served as
President and Chief Executive Officer of Orion Power Holdings, Inc. Prior to joining 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 Power, Mr. Fusco was Executive Director of International Development and Operations
for Pacific Gas & Electric Company’s non-regulated subsidiary PG&E Enterprises, Inc. 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.
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 in
Business and Commerce and Masters in Business Administration — Finance 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 from St. John’s School of Law. In addition, Mr. Miller was an officer in the U.S. Coast Guard from
1973 through 1976.
John B. (Thad) Hill has served as our Executive Vice President and Chief Commercial Officer since
September 1, 2008. 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
107
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
Vice President and 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.
Jim D. Deidiker has served as our Senior Vice President and Chief Accounting Officer since January 6,
2009. 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 in Accounting from
Southwest Missouri State University and a Master in Business Administration from the University of Houston. In
addition, Mr. Deidiker is a Certified Public Accountant and Certified Management Accountant.
Gary M. Germeroth has served as our Executive Vice President and Chief Risk Officer since June 2007.
Mr. Germeroth’s responsibilities include maintaining oversight of our risk management framework and assuring
that our complex risks are communicated and understood throughout the organization. Prior to joining the
Company, Mr. Germeroth worked for PA Consulting Group, Inc. and its predecessor firm, Hagler Bailly Risk
Advisors, since 1999. Prior to joining PA Consulting, Mr. Germeroth held a variety of controllership, risk control
and treasury positions at various entities in his energy career. Mr. Germeroth has more than 29 years of
experience in energy strategy and risk management, having directed a variety of commercial strategy, enterprise
risk management and corporate restructuring projects for multiple companies. Mr. Germeroth has led efforts
related to corporate governance, portfolio risk evaluation, operational risk management, strategic options
analysis, management of portfolio capital requirements, organizational and business process design, transaction
settlement and financial accounting. Mr. Germeroth obtained a Bachelor of Science in Finance from the
University of Denver.
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 2010 annual meeting of stockholders to be held
on May 19, 2010.
Item 11. Executive Compensation
Information appearing under this Item is incorporated herein by reference to our proxy statement for the
2010 annual meeting of stockholders to be held May 19, 2010.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information appearing under this Item is incorporated herein by reference to our proxy statement for the
2010 annual meeting of stockholders to be held May 19, 2010.
Item 13. Certain Relationships and Related Transactions and Director Independence
Information appearing under this Item is incorporated herein by reference to our proxy statement for the
2010 annual meeting of stockholders to be held May 19, 2010.
Item 14. Principal Accounting Fees and Services
Information appearing under this Item is incorporated herein by reference to our proxy statement for the
2010 annual meeting of stockholders to be held May 19, 2010.
108
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, 2009, 2008 and 2007 . . . .
Consolidated Balance Sheets at December 31, 2009 and 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Comprehensive Income (Loss) and Stockholders’ Equity (Deficit) for the
Years Ended December 31, 2009, 2008 and 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007 . . . .
Notes to Consolidated Financial Statements for the Years Ended December 31, 2009, 2008 and
Page
117
118
119
120
121
2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
123
(a)-2. Financial Statement Schedule
Calpine Corporation and Subsidiaries
Schedule II — Valuation and Qualifying Accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(c)-1. Financial Statements and Other Information
Otay Mesa Energy Center, LLC
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance Sheets at December 31, 2009 and 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statements of Operations for the Years Ended December 31, 2009 and 2008, and the Period May 1,
188
190
191
2007 to December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
192
Statements of Comprehensive Income (Loss) and Member’s Interest for the Years Ended
December 31, 2009 and 2008, and the Period May 1, 2007 to December 31, 2007 . . . . . . . . . . . . . .
193
Statements of Cash Flows for the Years Ended December 31, 2009 and 2008, and the Period May 1,
2007 to December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
194
Notes to Financial Statements for the Years Ended December 31, 2009 and 2008, and the Period
May 1, 2007 to December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(b) Exhibits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
195
212
109
Exhibit
Number
2.1
2.2
3.1
3.2
4.1
4.2
4.3
4.4
4.5
4.6
4.7
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 the Company’s Current Report on
Form 8-K filed with the SEC on December 27, 2007).
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 the Company’s Current Report on Form 8-K filed with the SEC on December 27,
2007).
Amended and Restated Certificate of Incorporation of the Company, as amended (incorporated by
reference to Exhibit 3.1 to the Company’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 the Company’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 June 13, 2003, between Power Contract Financing, L.L.C. and Wilmington
Trust Company, as trustee, accounts agent, paying agent and registrar, including form of 6.256
senior secured notes due 2010 (incorporated by reference to Exhibit 4.4 to the Company’s
Quarterly Report on Form 10-Q for the quarter ended June 30, 2003, filed with the SEC on
August 14, 2003).
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 the Company’s Quarterly Report on Form 10-Q for the
quarter ended September 30, 2003, filed with the SEC on November 13, 2003).
Third Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC,
CalGen Finance Corp. and Manufacturers and Traders Trust Company (as successor trustee to
Wilmington Trust FSB), as trustee, including form of third priority secured floating rate notes due
2011 (incorporated by reference to Exhibit 4.21 to the Company’s Annual Report on Form 10-K
for the year ended December 31, 2003, filed with the SEC on March 25, 2004).
Indenture, dated as of June 2, 2004, between Power Contract Financing III, LLC and Wilmington
Trust Company, as trustee, accounts agent, paying agent and registrar, including form of senior
secured notes due 2010 (incorporated by reference to Exhibit 4.6 to the Company’s Quarterly
Report on Form 10-Q for the quarter ended June 30, 2004, filed with the SEC on August 9, 2004).
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 our 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 the Company’s Current Report on Form 8-K filed with the SEC on October 26,
2009).
Registration Rights Agreement, dated January 31, 2008, among the Company and each
Participating Shareholder named therein (incorporated by reference to Exhibit 10.1 to the
Company’s Current Report on Form 8K filed with the SEC on February 6, 2008).
10.1
Financing Agreements
110
Exhibit
Number
10.1.1.1
10.1.1.2
10.1.1.3
10.1.1.4
10.1.5
10.1.6
10.1.7
Description
Credit Agreement, dated as of January 31, 2008, among the Company, as borrower, Goldman
Sachs Credit Partners L.P., Credit Suisse, Deutsche Bank Securities Inc. and Morgan Stanley
Senior Funding, Inc., as co-documentation agents and as co-syndication agents, General Electric
Capital Corporation, as sub-agent for the revolving lenders, Goldman Sachs Credit Partners L.P.,
as administrative agent and as collateral agent and each of the financial institutions from time to
time party thereto (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on
Form 8-K filed with the SEC on February 1, 2008).
to Credit Agreement and Second Amendment
to Collateral Agency and
First Amendment
Intercreditor Agreement, dated as of August 20, 2009, among the Company, certain of the
Company’s subsidiaries as guarantors, the financial institutions party thereto as lenders and
Goldman Sachs Credit Partners L.P., as administrative agent and collateral agent (incorporated by
reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on
August 26, 2009).
Guaranty and Collateral Agreement, dated as of January 31, 2008, 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 10.1.3 to the Company’s Annual
Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on February 29,
2008).
Commodity Collateral Revolving Credit Agreement, dated as of July 8, 2008, among Calpine
Corporation as Borrower, Goldman Sachs Credit Partners L.P. as Payment Agent, sole Lead
Arranger and sole Bookrunner, and the Lenders from time to time party thereto (incorporated by
reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on
July 14, 2008).
Credit Agreement, dated as of June 24, 2004, among Riverside Energy Center, LLC, the Lenders
named therein, Union Bank of California, N.A., as the Issuing Bank, Credit Suisse First Boston,
acting through its Cayman Islands Branch, as Lead Arranger, Book Runner, Administrative Agent
and Collateral Agent, and CoBank, ACB, as Syndication Agent (incorporated by reference to
Exhibit 10.1.9 to the Company’s Annual Report on Form 10-K for the year ended December 31,
2004, filed with the SEC on March 31, 2005).
Credit Agreement, dated as of June 24, 2004, among Rocky Mountain Energy Center, LLC, the
Lenders named therein, Union Bank of California, N.A., as the Issuing Bank, Credit Suisse First
Boston, acting through its Cayman Islands Branch, as Lead Arranger, Book Runner,
Administrative Agent and Collateral Agent, and CoBank, ACB, as Syndication Agent
(incorporated by reference to Exhibit 10.1.10 to the Company’s Annual Report on Form 10-K for
the year ended December 31, 2004, filed with the SEC on March 31, 2005).
Amended and Restated Credit Agreement, dated as of November 24, 2009, among Calpine
Steamboat Holdings, LLC, Calyon New York Branch, as lead arranger, co-book runner,
administrative agent, collateral agent and Security Fund LC issuer, WestLB AG, New York
Branch, as lead arranger, co-book runner and syndication agent, CoBank ACB and The Bank of
Tokyo-Mitsubishi UFJ, LTD., New York Branch, as lead arrangers, co-book runners and
co-documentation agents, Landesbank Hessen-Thüringen, Natixis, New York Branch, The
Governor & Company of the Bank of Ireland and Bayerische Hypo-Und Vereinsbank AG, New
York Branch, as lead arrangers, and the lenders named therein (incorporated by reference to
Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on November 30,
2009).
10.2
Management Contracts or Compensatory Plans or Arrangements
10.2.1.1
Employment Agreement, dated August 10, 2008, between the Company and Jack A. Fusco
(incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed
with the SEC on August 12, 2008).†
111
Exhibit
Number
10.2.1.2
10.2.2
10.2.3.1
10.2.3.2
10.2.4.1
10.2.4.2
10.2.5
10.2.6
10.2.7
10.2.8.1
10.2.8.2
10.2.8.3
10.2.8.4
10.2.8.5
10.2.9.1
Description
Calpine Corporation Executive Sign On Non-Qualified Stock Option Agreement (Jack A. Fusco)
(incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed
with the SEC on August 12, 2008).†
Letter Agreement, dated December 17, 2008, between the Company and Zamir Rauf
(incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed
with the SEC on December 19, 2008).†
Letter Agreement, dated September 1, 2008, between the Company and John B. Hill
(incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed
with the SEC on September 4, 2008).†
Calpine Corporation Executive Sign On Non-Qualified Stock Option Agreement (John B. Hill)
(incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed
with the SEC on September 4, 2008).†
Employment Agreement, dated August 11, 2008, between the Company and W. Thaddeus Miller
(incorporated by reference to Exhibit 10.2.7 to the Company’s Quarterly Report on Form 10-Q
for the quarter ended September 30, 2008, filed with the SEC on November 7, 2008).†
Calpine Corporation Executive Sign On Non-Qualified Stock Option Agreement (Miller)
(incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement on Form S-8
(Registration No. 333-153860) filed with the SEC on October 6, 2008).†
Calpine Corporation U.S. Severance Program.*†
Calpine Corporation 2009 Calpine Incentive Plan (incorporated by reference to Exhibit 10.2 to
the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, filed with
the SEC on May 8, 2009).†
Calpine Corporation 2008 Calpine Incentive Plan (incorporated by reference to Exhibit 10.2.9 to
the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, filed
with the SEC on November 7, 2008).†
Calpine Corporation 2008 Equity Incentive Plan (incorporated by reference to Exhibit 4.5 to the
Company’s Registration Statement on Form S-8 (No. 333-149074) filed with the SEC on
February 6, 2008).†
Form of Non-Qualified Stock Option Agreement (Pursuant to the 2008 Equity Incentive Plan)
(incorporated by reference to Exhibit 10.4.3 to the Company’s Quarterly Report on Form 10-Q
for the quarter ended March 31, 2008, filed with the SEC on May 12, 2008).†
Form of Restricted Stock Agreement (Pursuant to the 2008 Equity Incentive Plan) (incorporated
by reference to Exhibit 10.4.4 to the Company’s Quarterly Report on Form 10-Q for the quarter
ended March 31, 2008, filed with the SEC on May 12, 2008).†
Director’s Restricted Stock Unit Agreement (Pursuant to the 2008 Equity Incentive Plan) between
the Company and Mr. William J. Patterson (incorporated by reference to Exhibit 10.4.6 to the
Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, filed with the
SEC on May 12, 2008).†
Restricted Stock Unit Election Form between the Company and William J. Patterson
(incorporated by reference to Exhibit 10.4.7 to the Company’s Quarterly Report on Form 10-Q
for the quarter ended March 31, 2008, filed with the SEC on May 12, 2008).†
Calpine Corporation 2008 Director Incentive Plan (incorporated by reference to Exhibit 4.4 to the
Company’s Registration Statement on Form S-8 (No. 333-149074) filed with the SEC on
February 6, 2008).†
112
Exhibit
Number
10.2.9.2
10.2.9.3
Description
Amendment No. 1 to the Calpine Corporation 2008 Director Incentive Plan (incorporated by
reference to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008,
filed with the SEC on February 27, 2009).†
Form of Restricted Stock Agreement (Pursuant to the 2008 Director Incentive Plan) (incorporated
by reference to Exhibit 10.4.5 to the Company’s Quarterly Report on Form 10-Q for the quarter
ended March 31, 2008, filed with the SEC on May 12, 2008).†
10.2.10
Calpine Corporation Change in Control and Severance Benefits Plan.*†
10.2.11
10.2.12
Letter Agreement, dated December 30, 2008, between the Company and Jim D. Deidiker
(incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed
with the SEC on January 8, 2009).†
Letter re Employment Offer, dated February 6, 2009, between the Company and Michael D.
Rogers (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on
Form 10-Q for the quarter ended March 31, 2009, filed with the SEC on May 7, 2009).†
18.1
21.1
23.1
23.2
24.1
31.1
31.2
32.1
Letter of preferability regarding change in accounting principle from PricewaterhouseCoopers
LLP, Independent Registered Public Accounting Firm.*
Subsidiaries of the Company.*
Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.*
Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.*
Power of Attorney of Officers and Directors of Calpine Corporation (set forth on the signature
pages of this report).*
Certification of the Chief Executive Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under
the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.*
Certification of the Senior Vice President and Chief Financial Officer Pursuant to Rule 13a-14(a)
or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant
to
Section 302 of the Sarbanes-Oxley Act of 2002.*
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.*
*
Filed herewith.
† Management contract or compensatory plan or arrangement.
113
Pursuant to the requirements of Section 13 or 15(d) 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 (principal financial officer)
Date: February 24, 2010
114
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
President, Chief Executive Officer
and Director (principal executive
officer)
Executive Vice President and Chief
Financial Officer (principal
financial officer)
February 24, 2010
February 24, 2010
Chief Accounting Officer
(principal accounting officer)
February 24, 2010
Director
February 24, 2010
Director
February 24, 2010
Director
February 24, 2010
/s/ W. BENJAMIN MORELAND
Director
February 24, 2010
W. Benjamin Moreland
/s/ ROBERT MOSBACHER, JR.
Director
February 24, 2010
Robert Mosbacher, Jr.
/s/ DENISE M. O’LEARY
Denise M. O’Leary
Director
February 24, 2010
/s/ WILLIAM J. PATTERSON
Director
February 24, 2010
William J. Patterson
/s/ J. STUART RYAN
J. Stuart Ryan
115
Director
February 24, 2010
CALPINE CORPORATION AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2009
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Operations for the Years Ended December 31, 2009, 2008 and 2007 . . . . . . . .
Consolidated Balance Sheets at December 31, 2009 and 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Comprehensive Income (Loss) and Stockholders’ Equity (Deficit) for the
Years Ended December 31, 2009, 2008 and 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007 . . . . . . . .
Notes to Consolidated Financial Statements for the Years Ended December 31, 2009, 2008 and 2007 . . . . .
Page
117
118
119
120
121
123
116
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,
2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period
ended December 31, 2009 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, 2009, 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, 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.
As discussed in Note 3 to the consolidated financial statements, the Company changed its method of depreciation
for certain of its property, plant and equipment assets in 2009.
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
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.
limitations,
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 24, 2010
117
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Years Ended December 31, 2009, 2008 and 2007
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost of revenue:
Fuel and purchased energy expense . . . . . . . . . . . . . . . . . . . . . . . . . . .
Plant operating expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization expense . . . . . . . . . . . . . . . . . . . . . . . .
Operating asset impairments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other cost of revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total cost of revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross profit
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales, general and other administrative expense . . . . . . . . . . . . . . . . . . .
(Income) loss from unconsolidated investments in power plants . . . . . .
Other operating expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest (income) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Debt extinguishment costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other (income) expense, net
Income (loss) before reorganization items, income taxes and
discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reorganization items . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) before income taxes and discontinued operations . . . .
Income tax expense (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) before discontinued operations . . . . . . . . . . . . . . . . . . .
Discontinued operations, net of tax expense of $14 in 2008 . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . .
Net loss attributable to the noncontrolling interest
2009
2008
2007
(in millions, except share and per share amounts)
$
6,564
$
9,937
$
7,970
3,897
897
467
4
84
5,349
1,215
183
(50)
18
1,064
829
(16)
76
16
159
(1)
160
15
145
—
145
4
149
7,281
918
433
33
114
8,779
1,158
215
229
26
688
1,071
(47)
13
14
(363)
(302)
(61)
(47)
(14)
23
9
1
10
$
5,683
749
463
44
136
7,075
895
146
21
23
705
2,019
(64)
(1)
(138)
(1,111)
(3,258)
2,147
(546)
2,693
—
2,693
—
$
2,693
Net income attributable to Calpine . . . . . . . . . . . . . . . . . . . . .
$
Basic earnings (loss) per common share:
Weighted average shares of common stock outstanding (in
thousands)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
485,659
485,054
479,235
Income (loss) before discontinued operations attributable to
Calpine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Discontinued operations, net of tax, attributable to Calpine . . . . . . . .
Net income per common share attributable to Calpine —
basic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
0.31
—
0.31
$
$
(0.03)
0.05
0.02
$
$
5.62
—
5.62
Diluted earnings (loss) per common share:
Weighted average shares of common stock outstanding (in
thousands)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
486,319
485,546
479,478
Income (loss) before discontinued operations attributable to
Calpine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Discontinued operations, net of tax, attributable to Calpine . . . . . . . .
Net income per common share attributable to Calpine —
diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
0.31
—
0.31
$
$
(0.03)
0.05
0.02
$
$
5.62
—
5.62
The accompanying notes are an integral part of these Consolidated Financial Statements.
118
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, 2009 and 2008
2009
2008
(in millions, except
share and per share amounts)
Current assets:
ASSETS
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts receivable, net of allowance of $14 and $42 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts receivable, related party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Inventory . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Margin deposits and other prepaid expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restricted cash, current
Derivative assets, current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property, plant and equipment, net
Restricted cash, net of current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term derivative assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
989
747
3
209
490
508
1,119
34
4,099
11,583
54
214
127
573
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
16,650
$
Current liabilities:
LIABILITIES & STOCKHOLDERS’ EQUITY
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued interest payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Debt, current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative liabilities, current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Debt, net of current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred income taxes, net of current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term derivative liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
578
54
463
1,360
7
287
2,749
8,996
54
197
208
1,657
846
4
163
776
337
3,653
64
7,500
11,908
166
144
404
616
20,738
574
85
716
3,799
5
437
5,616
9,756
93
698
203
Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12,204
16,366
Commitments and contingencies (see Note 17)
Stockholders’ equity:
Preferred stock, $.001 par value per share; authorized 100,000,000 shares, none issued and
outstanding at December 31, 2009 and 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Common stock, $.001 par value per share; authorized 1,400,000,000 shares, 443,325,827
shares issued and 442,998,255 shares outstanding at December 31, 2009 and
429,025,057 shares issued and 428,960,025 shares outstanding at December 31, 2008 . . .
Treasury stock, at cost, 327,572 shares and 65,032 shares at December 31, 2009 and
December 31, 2008, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated deficit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated other comprehensive loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Calpine stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Noncontrolling interest
Total stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
1
(3)
12,256
(7,540)
(266)
4,448
(2)
4,446
—
1
(1)
12,217
(7,689)
(158)
4,370
2
4,372
Total liabilities and stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
16,650
$
20,738
The accompanying notes are an integral part of these Consolidated Financial Statements.
119
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) AND
STOCKHOLDERS’ EQUITY (DEFICIT)
For the Years Ended December 31, 2009, 2008 and 2007
Common
Stock
Treasury
Stock
Additional
Paid-In
Capital
Retained
Earnings
(Accumulated
Deficit)
Accumulated
Other
Comprehensive
Income (Loss)
Noncontrolling
Interest
Total
Stockholders’
Equity
(Deficit)
(in millions except share amounts)
Balance, December 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1 $
— $
3,270
$
(10,378) $
(46) $
3 $
(7,150)
Return of 50,000,000 shares of loaned common stock . . . .
Returnable shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Stock-based compensation (income) . . . . . . . . . . . . . . . . . .
Total stockholders’ deficit before comprehensive
income (loss) items . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on cash flow hedges before reclassification
adjustment for cash flow hedges realized in net
income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reclassification adjustment for cash flow hedges realized
in net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign currency translation gain . . . . . . . . . . . . . . . . . . . .
Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total comprehensive income . . . . . . . . . . . . . . . . . . . . . .
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(145)
145
(7)
—
—
—
—
—
—
—
—
2,693
—
—
—
—
—
—
—
—
(196)
13
12
(14)
—
—
—
—
—
—
—
—
Balance, December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1 $
— $
3,263
$
(7,685) $
(231) $
3 $
Cancellation of Calpine Corporation common stock . . . . .
Issuance of reorganized Calpine Corporation common
stock in accordance with our Plan of Reorganization . . .
Treasury stock transactions . . . . . . . . . . . . . . . . . . . . . . . . .
Stock-based compensation expense . . . . . . . . . . . . . . . . . . .
Proceeds received from the exercise of warrants . . . . . . . .
Cumulative effect of adjustment from adoption of fair
value measurement standards, net of tax of $8
million . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total stockholders’ equity before comprehensive
income (loss) items . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain on cash flow hedges before reclassification
adjustment for cash flow hedges realized in net
income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reclassification adjustment for cash flow hedges realized
in net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign currency translation loss . . . . . . . . . . . . . . . . . . . . .
Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total comprehensive income . . . . . . . . . . . . . . . . . . . . . .
(1)
1
—
—
—
—
—
—
—
—
—
—
—
(1)
—
—
—
—
—
—
—
—
(3,263)
12,166
—
50
1
—
—
—
—
—
—
—
—
—
—
—
(14)
10
—
—
—
—
—
—
—
—
—
—
—
141
27
(19)
(76)
—
—
—
—
—
—
(1)
—
—
—
—
(145)
145
(7)
(7,157)
2,693
(196)
13
12
(14)
2,508
(4,649)
(3,264)
12,167
(1)
50
1
(14)
4,290
9
141
27
(19)
(76)
82
Balance, December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1 $
(1) $
12,217
$
(7,689) $
(158) $
2 $
4,372
Treasury stock transactions . . . . . . . . . . . . . . . . . . . . . . . . .
Stock-based compensation expense . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other
Total stockholders’ equity before comprehensive
income (loss) items . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain on cash flow hedges before reclassification
adjustment for cash flow hedges realized in net
income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reclassification adjustment for cash flow hedges realized
in net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign currency translation gain . . . . . . . . . . . . . . . . . . . .
Income tax benefit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total comprehensive income . . . . . . . . . . . . . . . . . . . . . .
—
—
—
—
—
—
—
—
(2)
—
—
—
—
—
—
—
—
38
1
—
—
—
—
—
—
—
—
149
—
—
—
—
—
—
—
—
180
(335)
4
43
—
—
—
(4)
—
—
—
—
(2)
38
1
4,409
145
180
(335)
4
43
37
Balance, December 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1 $
(3) $
12,256
$
(7,540) $
(266) $
(2) $
4.446
The accompanying notes are an integral part of these Consolidated Financial Statements.
120
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2009, 2008 and 2007
Cash flows from operating activities:
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjustments to reconcile net income to net cash provided by operating activities:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization expense(1)
(Income) loss from unconsolidated investments in power plants . . . . . . . . . . . . . . . . . . . . . . . . .
Debt extinguishment costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment loss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain on sale of discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on disposal of assets, excluding reorganization items . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrealized mark-to-market activity, net
Return on investment in unconsolidated subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Stock-based compensation expense (income) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reorganization items . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in operating assets and liabilities, net of effects of acquisitions:
Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts payable, LSTC and accrued expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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, turbines and investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from sale of discontinued operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash acquired due to reconsolidation of Canadian Debtors and other deconsolidated foreign
entities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Contributions to unconsolidated investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Return of investment from unconsolidated investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(Increase) decrease in restricted cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash effect of deconsolidation of VIEs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net cash provided by (used in) investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash flows from financing activities:
Repayments of notes payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Borrowings from CCFC New Notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Repayments of CCFC Old Notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Borrowings from project financing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Repayments of project financing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Repayments of CalGen Secured Debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Borrowings under DIP Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Repayments of DIP Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Borrowings under First Lien Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Repayments of First Lien Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Borrowings under Commodity Collateral Revolver . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Repayments of Second Priority Debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from sale of ULC I notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Repayments on capital leases . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Redemptions of preferred interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative contracts classified as financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net cash provided by (used in) financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net (decrease) increase in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2009
2008
2007
(in millions)
$
145
$
9
$ 2,693
556
(50)
37
16
4
—
37
(89)
11
38
(6)
6
108
(118)
235
(19)
(150)
761
(179)
—
—
—
(19)
9
(59)
—
(2)
(250)
544
229
7
27
46
(37)
36
(24)
—
50
(359)
16
375
234
(101)
(215)
(343)
494
(143)
413
79
64
(17)
27
78
(2)
17
516
554
21
—
(517)
46
—
31
52
—
(1)
(3,342)
(2)
(194)
(34)
(102)
931
51
187
(196)
541
—
—
(68)
179
37
(29)
9
473
(106)
(99)
955
—
(781)
(4)
79
357
(121)
(275)
—
—
—
—
(98)
—
— 4,248
(1,475)
(785)
—
100
— (3,672)
—
—
(42)
(43)
(166)
(310)
(207)
(65)
64
—
1
(2)
(1,268)
(1,179)
(258)
(668)
1,915
1,657
$ 1,657
989
$
(135)
—
(4)
21
(88)
(224)
614
(38)
—
—
—
—
151
(35)
(9)
(81)
—
6
178
838
1,077
$ 1,915
The accompanying notes are an integral part of these Consolidated Financial Statements.
121
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS — (Continued)
Cash paid (received) during the period for:
Interest, net of amounts capitalized . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . .
Reorganization items included in operating activities, net
Reorganization items included in investing activities, net . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . .
Reorganization items included in financing activities, net
$ 761
$1,060
$1,143
7
$
$
74
$
1
$ 126
$ 120
5
$
$ — $ (418) $ (582)
74
$ — $ — $
2009
2008
2007
(in millions)
Supplemental disclosure of non-cash investing and financing activities:
Settlement of commodity contract with project financing . . . . . . . . . . . . . . . . . . . . .
Change in capital expenditures included in accounts payable . . . . . . . . . . . . . . . . . .
Issuance of First Lien Notes in exchange for First Lien Credit Facility term
loans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amended Steamboat project debt
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Settlement of LSTC through issuance of reorganized Calpine Corporation common
stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
DIP Facility borrowings converted into exit financing under our First Lien
$
$
79
6
$ — $ —
1
$
13
$
$1,200
$ 448
$ — $ —
$ — $ —
$ — $5,200
$ —
Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ — $3,872
$ —
Settlement of Convertible Senior Notes and Unsecured Senior Notes with
reorganized Calpine Corporation common stock . . . . . . . . . . . . . . . . . . . . . . . . . .
$ — $3,703
$ —
DIP Facility borrowings used to extinguish the Original DIP Facility principal
$(989), CalGen Secured Debt principal $(2,309) and operating liabilities
$(88) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Project financing $(159) and operating liabilities $(33) extinguished with sale of
Aries Power Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Return of loaned common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Letter of credit draws under the CalGen Secured Debt used for operating activities
Fair value of Metcalf cooperation agreement, with offsets to notes payable $(6)
$ — $ — $3,386
$ — $ — $ 192
$ — $ — $ 145
16
$ — $ — $
and operating liabilities $(6)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$ — $ — $
12
(1)
Includes depreciation and amortization that is recorded in sales, general and other administrative expense
and interest expense on our Consolidated Statements of Operations.
The accompanying notes are an integral part of these Consolidated Financial Statements.
122
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the Years Ended December 31, 2009, 2008 and 2007
1. Organization and Operations
We are an independent wholesale power generation company engaged in the ownership and operation of
natural gas-fired and geothermal power plants in North America. We have a significant presence in the major
competitive power markets in the U.S., including California and Texas. We sell wholesale power, steam,
capacity, renewable energy credits and ancillary services to our customers, including industrial companies, retail
power providers, utilities, municipalities, independent electric system operators, marketers and others. We
engage in the purchase of natural gas 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, commodity and financial derivative transactions 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 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 interest in
OMEC, a VIE where we have determined that we are not the primary beneficiary, Greenfield LP, a joint venture
interest, and Whitby, a less-than-majority equity interest
in which we exercise significant influence over
operating and financial policies. Our share of net income (loss) is calculated according to our equity ownership or
according to the terms of the applicable partnership agreement. See Note 4 for further discussion of our VIEs and
unconsolidated investments.
Deconsolidations / Consolidations — As a result of filings by the Canadian Debtors under the CCAA in
the Canadian Court, we deconsolidated the Canadian Debtors and their direct and indirect subsidiaries,
constituting most of our foreign entities as of December 20, 2005, the Petition Date, as we determined that the
administration of the CCAA proceedings in a jurisdiction other than that of the U.S. Debtors’ Chapter 11 cases
resulted in a loss of the elements of control necessary for consolidation and we fully impaired our investment in
the Canadian Debtors and other deconsolidated foreign entities. On February 8, 2008, the Canadian Effective
Date, the Canadian Court ordered and declared that the CCAA proceedings were terminated. The termination of
the CCAA proceedings and our emergence from Chapter 11 proceedings in the U.S. allowed us to maintain our
equity interest in the Canadian Debtors and other deconsolidated foreign entities, whose principal assets included
various working capital items and a 50% ownership interest in Whitby, an equity method investment. As a result,
we regained control over the Canadian Debtors and other deconsolidated foreign entities, which were
reconsolidated into our Consolidated Financial Statements as of the Canadian Effective Date. See Note 16 for a
further discussion on our emergence from Chapter 11.
We accounted for the reconsolidation under the purchase method in a manner similar to a step
acquisition. The excess of the fair market value of the reconsolidated net assets over the carrying value of our
investment balance of $0 amounted to approximately $133 million. We recorded the Canadian assets acquired
and the liabilities assumed based on their estimated fair value, with the exception of Whitby. We reduced the fair
value of our Whitby equity investment (approximately $62 million) to $0 on the Canadian Effective Date and
recorded the $71 million balance of the excess as a gain in reorganization items on our 2008 Consolidated
Statement of Operations.
123
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
During the second quarter of 2007, we deconsolidated OMEC. We deconsolidated RockGen in
January 2008 and Auburndale in August 2008, and subsequently reconsolidated RockGen in December 2008. See
Note 4 for further discussion of our VIEs.
Reclassifications
Certain reclassifications have been made to our December 31, 2008 Consolidated Balance Sheet, and our
Consolidated Statements of Operations and Consolidated Statements of Cash Flows for the years ended
December 31, 2008 and 2007 to conform to the current year presentation. Our reclassifications are summarized
as follows:
• We adopted the new accounting standards under GAAP for noncontrolling interests in consolidated
financial statements effective January 1, 2009, and accordingly have reclassified minority interest as
“noncontrolling interest,” a component of stockholders’ equity, on our Consolidated Balance Sheets
and included “net loss attributable to the noncontrolling interest” as a separate line item on our
Consolidated Statements of Operations. See “New Accounting Standards and Disclosure
Requirements” for a further discussion regarding this requirement.
• We have reclassified certain amounts on our Consolidated Statements of Cash Flows for years ended
December 31, 2008 and 2007, to separately report non-cash debt extinguishment costs of $7 million
for the year ended December 31, 2008, previously reflected in depreciation and amortization expense
and unrealized mark-to-market activity of $(24) million and $52 million previously reflected in our
changes in derivative instruments included within our cash flows provided by operating activities.
Use of Estimates in Preparation of Financial Statements
The preparation of financial statements in conformity with 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.
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 7 for disclosures regarding
the fair value of our debt instruments and Notes 8 and 9 for disclosures regarding the fair values of our derivative
instruments.
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, exceed FDIC insured limits or 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 credit-worthy 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
receivable and derivative
instrumentalities. Additionally, we actively monitor
counterparties. Our accounts and notes receivable are concentrated within entities engaged in the energy industry,
risk of our
the credit
124
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
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
financial and commodity
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.
in the future. For
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, 2009 and 2008, we had cash and cash
equivalents of $264 million and $296 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 are 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.
The table below represents the components of our restricted cash as of December 31, 2009 and 2008 (in
millions):
2009
2008
Current
Non-Current
Total
Current
Non-Current
Total
$
Debt service . . . . . . . . . . . . . . . . . .
Rent reserve . . . . . . . . . . . . . . . . . .
Construction/major
maintenance . . . . . . . . . . . . . . . .
Security/project/insurance . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . .
Total
. . . . . . . . . . . . . . . . . . . . .
$
193
34
87
146
48
508
$
$
25
—
22
—
7
54
$
$
218
34
109
146
55
562
$
$
102
34
$
121
—
72
96
33
18
1
26
223
34
90
97
59
$
337
$
166
$
503
125
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
Of our restricted cash at December 31, 2009 and 2008, $292 million and $265 million, respectively, relate
to the assets of the following entities, each of which is an entity with its legal existence separate from us and our
other subsidiaries (in millions):
PCF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gilroy Energy Center, LLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Rocky Mountain Energy Center, LLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Riverside Energy Center, LLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Calpine King City Cogen, LLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PCF III . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
2009
2008
159
34
48
42
8
1
292
$
$
159
35
29
33
8
1
265
Accounts Receivable and Payable
Accounts receivable and payable represent amounts due from customers and owed to vendors. 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
marketing, hedging and optimization activities of CES. Some of these receivables and payables with individual
counterparties are subject to master netting arrangements whereby we legally have a right of offset and we 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.
Counterparty Credit Risk
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 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
marketing counterparties. Currently, certain of our marketing counterparties within the energy industry have
126
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
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 do
not currently have any significant exposure to counterparties that are not paying on a current basis.
Inventory
Inventory primarily consists of spare parts, stored natural gas, 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 the costs
are expensed to plant operating costs 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 currently subject to first priority liens under our First Lien Credit
Facility as collateral under certain of our power and natural gas agreements that qualify as “eligible commodity
hedge agreements” under our First Lien Credit Facility 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 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 Credit Facility. See Note
10 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 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
127
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
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, have been capitalized since our purchase date. Exploration activities are
extremely limited and are not material to our overall capital expenditures or our fixed assets. We drilled one deep
test well in the Glass Mountain area in northern California in 2001, which produced economically viable quantities
of steam. Immaterial holding costs at Glass Mountain are expensed.
We depreciate our assets under the straight line method over the shorter of their estimated useful life or
lease term using an estimated salvage value which approximates 10% of the depreciable cost basis for our power
plant assets 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 our rotable spares equipment. During 2009, we
reviewed our accounting policies related to depreciation including our estimates of useful lives. We determined
changing from composite depreciation to component depreciation for our rotable natural gas-fired power plant
assets, and changing our Geysers Assets depreciation from the units of production method to the straight line
method was preferable under GAAP. We also revised our estimates of useful lives. See Note 3 for further
discussion regarding our changes in depreciation and the effective date of our changes.
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.
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 patents and specifically identifiable intangibles for impairment, 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 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. 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.
128
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
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 will be recovered through future operations, the carrying values of the
projects would be written down to their 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 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.
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.
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 charge.
Generally, fair value will be determined using valuation techniques such as the present value of expected
future cash flows. We will also discount the estimated future cash flows associated with the asset using a single
interest rate representative of the risk involved with such an investment including contract terms, tenor and credit risk
of 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 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 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. The evaluation and
measurement of impairments for equity method investments involve the same uncertainties as described for long-
lived assets that we own directly. Similarly, our estimates that we make with respect to our equity method
investments are subjective, and the impact of variations in these estimates could be material.
During 2009, we reviewed our power plants and determined that no events or changes in circumstances
indicated that impairment conditions had occurred. However, based upon a sales agreement with a third party we
wrote-down our natural gas reserves by approximately $4 million. The following table details impairment
charges recorded during the years ended December 31, 2009, 2008 and 2007 (in millions):
Operating asset impairments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment of equity method investment(1)
. . . . . . . . . . . . . . . . . . . . . . . .
Equipment, development project and other impairment charges(2) . . . . . . .
Impairments included in reorganization items . . . . . . . . . . . . . . . . . . . . . .
$
$
4
—
—
—
Total impairment charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
4
$
33
180
13
—
226
$
$
44
—
2
120
166
2009
2008
2007
(1) Amounts are included in (income) loss from unconsolidated investments in power plants on our
Consolidated Statements of Operations.
129
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
(2) Amounts are included in other operating expense on our Consolidated Statements of Operations.
During the year ended December 31, 2008, we recorded an impairment loss of $180 million as a result of
the anticipated sale of our investment in Auburndale as further described in Note 4. An additional impairment
charge of $33 million was recorded at December 31, 2008, for our Auburndale Peaking Energy Center (a
separate power plant from Auburndale) which did not receive an expected contract renewal resulting in reduced
future expected cash flows. Additionally, we recorded impairments related to certain development projects that
we determined were not probable of completion as of December 31, 2008. For the year ended December 31,
2007, we recorded operating asset impairment charges primarily related to the Bethpage Power Plant as
additional competition from new transmission lines reduced future expected cash flows and we recorded $120
million in reorganization items primarily related to the sale of our interest in Acadia PP.
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, 2009 and 2008, our asset retirement
obligation liabilities were $48 million and $47 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 composed of the following:
•
•
•
power and steam revenue consisting of fixed capacity payments, which are not related to generation,
variable payments, which are related to generation, host steam and RECs from our Geysers Assets,
and other revenues such as RMR Contracts, resource adequacy and certain ancillary service revenues;
revenues from derivative instruments as a result of our marketing, hedging and optimization
activities; and
other service revenues including revenue related to the sales of combustion turbine component parts
and services from PSM prior to its sale in March 2007.
Power and Steam
Physical Commodity Contracts — We recognize revenue primarily 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.
We also 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 the normal purchase normal sale exemption. Certain other contracts do not meet the
definition of a derivative and may be considered physical executory contracts or leases. We apply lease or
traditional accrual accounting to these contracts that are 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.
130
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
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. Our physical commodity contracts
are not entered into for the purpose of settling on a net basis with another counterparty.
RMR Contracts, 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.
Leases — 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.
The total contractual future minimum lease receipts for these contracts are as follows (in millions):
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter
$
186
190
181
146
103
807
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1,613
Accounting for Derivative Instruments
We enter into a variety of derivative instruments to include 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. The majority of this activity is related to the
fuel and power price risk associated with our generation assets and our contractual obligations. 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 the normal purchase normal sale exemption.
Operating revenues, fuel and purchased energy expense and gains and losses on interest rate swaps
derived from marketing, hedging and optimization activities that qualify for hedge accounting are recorded in the
period and same financial statement line item as the hedged item. We present the cash flows from our derivatives
in the same category as the item being hedged within operating activities 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 requires us to formally document, designate and assess
the effectiveness of transactions that receive hedge accounting. For operating revenues, fuel and purchased
energy expense and gains and losses on interest rate swaps derived from marketing, hedging and optimization
activities that do not qualify for hedge accounting treatment and for certain forward physical PPAs that do not
qualify for the normal purchase normal sale exemption under derivative accounting, changes in fair value are
recognized currently into earnings as mark-to-market activity.
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
131
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
developed price estimates. During periods where external price quotes are not available, we derive such future
price estimates based on an extrapolation of prices from periods where external price quotes are available. We
perform this extrapolation using liquid and observable market prices and extending those prices to an internally
generated long-term price forecast based on a generalized equilibrium model.
We adopted the new accounting requirements related to disclosures about derivative instruments and
hedging activities as of January 1, 2009, which required enhanced disclosures about an entity’s derivative and
hedging activities to enable investors to better understand their effects on the entity’s financial position, financial
performance and cash flows as well as qualitative disclosures about our fair value amounts of gains and losses
associated with derivative instruments and disclosures about credit-risk-related contingent features in derivative
contracts. See Note 9 for further information regarding our accounting for derivative instruments.
Fuel and Purchased Energy Expense
Fuel and purchased energy expense is composed of the cost of natural gas purchased from third parties for
the purposes of consumption in our power plants as fuel expense, and the cost of power and natural gas
purchased from third parties for marketing, hedging and optimization activities as well as unrealized
mark-to-market gains and losses resulting from general market price movements against certain derivative
natural gas contracts that do not qualify for hedge accounting treatment.
Plant Operating Expense
Plant operating expense primarily includes employee expenses, repairs and maintenance, insurance and
property taxes. We recognize expense when the service is performed.
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.
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 11 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.
132
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
In accordance with GAAP, entities that have entered into a forward contract that requires physical
settlement by repurchase of a fixed number of the issuer’s equity shares of common stock in exchange for cash
shall exclude the common shares to be redeemed or repurchased when calculating basic and diluted earnings
(loss) per share. Our share lending agreement, which terminated in 2007 upon the return to us of all the loaned
shares, did not provide for cash settlement, but rather physical settlement was required (i.e., the shares had to be
and were returned by the end of the arrangement). Consequently, the loaned shares of common stock subject to
the share lending agreement were excluded from our earnings (loss) per share calculation for the year ended
December 31, 2007. See Note 12 for a further discussion of our earnings (loss) per share.
Stock-Based Compensation
We have selected the Black-Scholes option-pricing model to estimate the fair value of our employee
stock options on the grant date. The Black-Scholes option-pricing model takes into account certain variables,
which are further explained in Note 13.
Accounting for Reorganization
During the period December 20, 2005, through January 31, 2008, we conducted our business in the
ordinary course as debtors-in-possession under the protection of the Bankruptcy Courts. We emerged from
Chapter 11 on January 31, 2008. In accordance with financial reporting by entities in reorganization under the
Bankruptcy Code prescribed by GAAP, certain income, expenses, realized gains and losses and provisions for
losses that were realized or incurred in our Chapter 11 cases are recorded in reorganization items on our
Consolidated Statements of Operations. In connection with our emergence from Chapter 11, we recorded certain
“plan effect” adjustments to our Consolidated Balance Sheet as of the Effective Date in order to reflect certain
provisions of our Plan of Reorganization. See Note 16 for a further discussion on our emergence from
Chapter 11.
New Accounting Standards and Disclosure Requirements
Accounting Standards Codification and GAAP Hierarchy — Effective for interim and annual periods
ending after September 15, 2009, the Accounting Standards Codification, or ASC, and related disclosure
requirements issued by the Financial Accounting Standards Board, FASB, became the single official source of
authoritative, nongovernmental GAAP. The ASC simplifies GAAP, without change, by consolidating the
numerous predecessor accounting standards and requirements into logically organized topics. All other literature
not included in the ASC is non-authoritative. We adopted the ASC during 2009, which did not have any impact
on our results of operations, financial condition or cash flows as it does not represent new accounting literature or
requirements; however, it did change our references to authoritative sources of GAAP to the new ASC
nomenclature.
Fair Value Measurements of Non-Financial Assets and Non-Financial Liabilities — Effective for interim
and annual periods beginning after November 15, 2008, GAAP includes new standards related to fair value
measurements for non-financial assets and liabilities. These new standards do not apply to assets and liabilities
that were not previously required to be recorded at fair value, but do apply when other accounting standards
require fair value measurements. The new standards also define fair value, establish a framework for measuring
fair value under GAAP and enhance disclosures about fair value measurements. We adopted the new standards
with respect to non-financial assets and non-financial liabilities as of January 1, 2009, which did not have a
material effect on our results of operations, financial position or cash flows; however, adoption may impact
measurements of asset impairments and asset retirement obligations if they occur in the future.
133
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
Determining Fair Value in Inactive Markets — Effective for interim and annual periods beginning after
June 15, 2009, GAAP includes new accounting standards for determining fair value when the volume and level
of activity for the asset or liability have significantly decreased and the identifying transactions are not orderly.
The new standards apply to all fair value measurements when appropriate. Among other things, the new
standards:
•
•
•
•
affirm that the objective of fair value, when the market for an asset is not active, is the price that
would be received in a sale of the asset in an orderly transaction;
clarify certain factors and provide additional factors for determining whether there has been a
significant decrease in market activity for an asset when the market for that asset is not active;
provide that a transaction for an asset or liability may not be presumed to be distressed (not orderly)
simply because there has been a significant decrease in the volume and level of activity for the asset
or liability, rather, a company must determine whether a transaction is not orderly based on the
weight of the evidence, and provide a non-exclusive list of the evidence that may indicate that a
transaction is not orderly; and
require disclosure in interim and annual periods of the inputs and valuation techniques used to
measure fair value and any change in valuation technique (and the related inputs) resulting from the
application of the standard, including quantification of its effects, if practicable.
These new accounting standards must be applied prospectively and retrospective application is not
permitted. We adopted these new standards during 2009, which resulted in a clarification of existing accounting
guidance with no change to our accounting policies and had no effect on our results of operations, cash flows or
financial position. See Note 8 for disclosure of our fair value measurements.
Noncontrolling Interests in Consolidated Financial Statements — Effective for interim and annual
periods beginning after December 15, 2008, GAAP includes new accounting standards and disclosure
requirements for noncontrolling ownership interests in subsidiaries held by parties other than the parent, the
amount of consolidated net income attributable to the parent and to the noncontrolling interest, and changes in a
parent’s ownership interest while the parent retains a controlling financial interest in its subsidiary. In addition,
the new standards established principles for valuation of retained noncontrolling equity investments and
measurement of gain or loss when a subsidiary is deconsolidated as well as disclosure requirements to clearly
identify and distinguish between interests of the parent and the interests of the noncontrolling owners. We
adopted these new standards as of January 1, 2009, which did not have a material impact on our results of
operations, financial position or cash flows; however, adoption did result in the reclassification of minority
interest to noncontrolling interest on our Consolidated Balance Sheets and Statements of Operations.
Disclosures About Derivative Instruments and Hedging Activities — Effective for interim and annual
periods beginning after November 15, 2008, GAAP includes enhanced disclosure requirements relating to an
entity’s derivative and hedging activities to enable investors to better understand their effects on the entity’s
financial position, financial performance, and cash flows. We adopted the new disclosure requirements as of
January 1, 2009. Adoption resulted in additional disclosures related to our derivatives and hedging activities
including additional disclosures regarding our objectives for entering into derivative transactions, increased
balance sheet and financial performance disclosures, volume information and credit enhancement disclosures.
See Note 9 for our derivative disclosures.
134
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
Subsequent Events — Effective for interim and annual periods ending after June 15, 2009, GAAP
includes general standards of accounting for and disclosure of events that occur after the balance sheet date but
before financial statements are issued or are available to be issued. The new standards do not change the
accounting for subsequent events; however, they do require disclosure, on a prospective basis, of the date through
which an entity has evaluated subsequent events. We adopted these new standards during 2009, which had no
impact on our results of operations, financial condition or cash flows. We have evaluated subsequent events up to
the time of issuance of this Report to the SEC on February 24, 2010.
Consolidation of Variable Interest Entities — Effective for interim and annual periods beginning after
November 15, 2009, with earlier application prohibited, GAAP includes new standards for determining which
enterprise has a controlling financial interest in a VIE and amends guidance for determining whether an entity is
a VIE. The new standards will also add reconsideration events for determining whether an entity is a VIE and
will require ongoing reassessment of which entity is determined to be the VIE’s primary beneficiary as well as
enhanced disclosures about the enterprise’s involvement with a VIE. We are currently assessing the future impact
these new standards will have on our results of operations, financial position or cash flows; however, it is
possible this new standard could result in the future deconsolidation or consolidation of our VIEs. See Note 4 for
a discussion of our VIEs.
Fair Value Measurements and Disclosures — In January 2010, FASB issued Accounting Standards
Update 2010-06, “Fair Value Measurements and Disclosures” to enhance disclosure requirements relating to
different levels of assets and liabilities measured at fair value and to clarify certain existing disclosures. The
update requires disclosure of transfers in and out of levels 1 and 2 and gross presentation of purchases, sales,
issuances and settlements in the level 3 reconciliation of beginning and ending balances. The new disclosure
requirements relating to level 3 activity are effective for
interim and annual periods beginning after
December 15, 2010 and all the other requirements are effective for interim and annual periods beginning after
December 15, 2009. Since this update only requires additional disclosures, we do not expect this standard to have
a material impact on our results of operations, cash flows or financial position.
3. Property, Plant and Equipment, Net
As of December 31, 2009 and 2008, the components of property, plant and equipment, are stated at cost
less accumulated depreciation as follows (in millions):
2009
2008
Buildings, machinery and equipment
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Geothermal properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Less: Accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Land . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Construction in progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
13,373
1,050
232
14,655
(3,322)
11,333
74
176
Property, plant and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
11,583
$
13,360
979
258
14,597
(2,932)
11,665
76
167
11,908
Total depreciation expense, including amortization of leased assets, for the years ended December 31,
2009, 2008 and 2007, was $469 million, $437 million and $472 million, respectively.
135
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
We have various debt instruments that are collateralized by certain of our property, plant and equipment.
See Note 7 for a detailed discussion of such instruments.
Change in Depreciation Methods, Useful Lives and Salvage Values
During 2009, we reviewed our accounting policies related to depreciation including our estimates of
useful lives and salvage values. As further described below, effective October 1, 2009, we made two changes to
our methods of depreciation including (i) changing from composite depreciation to component depreciation for
our rotable parts utilized in our natural gas-fired power plants and (ii) changing from the units of production
method to the straight line method for our Geysers Assets. In addition, we completed a life study for each of our
natural gas-fired power plants and our Geysers Assets, and changed our estimate of their remaining useful lives
and the salvage values of our rotable parts utilized in our natural gas-fired power plants.
Component Depreciation for Rotable Parts at our Natural Gas-Fired Power Plants — Historically, we
have used the composite depreciation method for all of our natural gas-fired power plant assets. Under this
method, all assets comprising each power plant were combined into one group and depreciated under a composite
depreciation rate. Our power plants undergo scheduled and unscheduled outages to replace and repair rotable
parts over the course of their useful lives. Our rotable parts generally have shorter useful lives than the remainder
of our power plant assets. In conjunction with our recent plant maintenance activities and concurrently with our
useful life study, we have created records in sufficient detail to support componentizing our rotable parts for our
natural gas-fired power plant assets for purposes of calculating depreciation. We believe that component
depreciation method is preferable, since depreciating the individual rotable parts over their individual useful lives
would be a more precise method of depreciation compared to historical composite depreciation method.
As a result, the useful lives of our rotable parts are now generally estimated to range from 3 to 18 years.
Furthermore, we have reduced our estimate of salvage value for our rotable parts to 0.15% from 10% of original
cost to reflect our expectation with these separable parts. Our change in the method of depreciation for rotable
parts is considered a change in accounting estimate inseparable from a change in accounting principle, and will
result in changes to our depreciation expense prospectively.
Prior to October 2009, our composite useful lives for our natural gas-fired power plant assets, including
our rotable parts, were 35 years and 40 years for our combined-cycle and our simple-cycle power plant assets,
respectively. Based in part on the effect to our composite pools resulting from the componentization of our
rotable parts, and the results of our useful life study, we have revised the estimated useful lives of our composite
pools to 37 years and 47 years for our combined-cycle and simple-cycle power plant assets, respectively. Our
change in useful lives is considered a change in accounting estimate and will result in changes to our depreciation
expense prospectively.
Straight Line Method for our Geysers Assets — Historically, our Geysers Assets have used units of
production depreciation. Our units of production depreciation rate was calculated using a depreciable base of the
net book value of the Geysers Assets plus the expected future capital expenditures over the economic life of the
geothermal reserves. The rate of depreciation per MWh was determined by dividing the depreciable base by total
expected future generation. We historically viewed the geothermal steam being produced at our Geysers Assets
to be a depleting asset. Accordingly, the total expected future generation used to develop our depreciation rate
per MWh was limited by our estimate of the geothermal steam produced at our Geysers Assets. Over the past ten
years, we have signed long-term contracts with municipalities in proximity to our Geysers Assets which allows
us to receive, on average, 15 million gallons of reclaimed wastewater a day which is injected into the reservoir to
replenish natural steam withdrawn for the production of power. As a result, steam flow decline rates have
become very small. The expectation, as a result of the water injection program, is that the steam reservoir at
136
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
our Geysers Assets will be able to supply economic quantities of steam for the foreseeable future. Therefore, the
total expected future generation used to develop our depreciation rate per MWh is no longer limited by the
existence of geothermal steam, but instead is limited by the physical useful
life of the Geysers Assets.
Accordingly, we have changed our depreciation method from the units of production method to the straight line
method of depreciation for our Geysers Assets because we believe the straight line method is preferable since it
is more systematic and rational under our circumstances. As a result of this change, and based in part on the
results of our separate useful life study, we are now using estimates of the remaining composite useful lives of
our Geysers Assets which are 59 years and 13 years for our Geysers steam extraction and gathering assets and
our Geysers power plant assets, respectively. Our change in the method of depreciation for our Geysers Assets is
considered a change in accounting estimate inseparable from a change in accounting principle, and will result in
changes to depreciation expense prospectively.
The changes described above resulted in an increase in our historical depreciation expense of
approximately $28 million related to our natural gas-fired power plants and a decrease in historical depreciation
expense of approximately $3 million for our Geysers Assets for a net decrease to our income from operations and
our net income attributable to Calpine of approximately $25 million or approximately $(0.05) to our basic and
diluted earnings per share for the year ended December 31, 2009.
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 7 for further information regarding these assets under
capital leases.
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 $8 million, $20 million and $26 million for the years ended
December 31, 2009, 2008 and 2007, respectively.
4. Variable Interest Entities and Unconsolidated Investments
We consolidate all VIEs where we have determined that we are the primary beneficiary. This
determination is made at the inception of our involvement with the VIE and, in accordance with GAAP, is
updated only in response to a reconsideration event. Beginning on January 1, 2010, new accounting standards
will change the approach for the determination of the primary beneficiary and will require us to perform an
ongoing reassessment of our VIEs to determine the primary beneficiary, which may result
in future
deconsolidation or consolidation of our VIEs. We consider both qualitative and quantitative factors to form a
conclusion as to whether we, or another interest holder, absorbs a majority of the entity’s risk of expected losses,
receives a majority of the entity’s potential for expected residual returns, or both. Our consolidated VIEs are
aggregated into the following classifications in order of priority:
• Consolidated VIEs with Purchase Options — Certain of our subsidiaries have PPAs or other
agreements that provide third parties the option to purchase power plant assets, an equity interest, or a
portion of the future cash flows generated from an asset. For these VIEs, we determined at the time
137
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
we entered into the contractual arrangement that consolidation was appropriate as exercise of the
option was considered unlikely or would not provide the majority of the risk or reward from the
project.
• Consolidated Subsidiaries with Project Debt — Certain of our subsidiaries have project debt that
contains provisions which we have determined create variability. 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. Accordingly, we are the primary
beneficiary of these VIEs. See Note 7 for further information regarding our project debt and Note 2
for information regarding our restricted cash balances.
• Consolidated Subsidiaries with PPAs — Certain of our 100% owned subsidiaries have PPAs that are
deemed to be a form of subordinated financial support and thus constitute a VIE. For all such VIEs,
we have determined that we are the primary beneficiary as we retain the primary risk of loss over the
life of the project.
• Other Consolidated VIEs — Our other consolidated VIEs primarily consist of monetized assets
secured by financing. For each of these arrangements we are the primary beneficiary as we retain both
the primary risk of loss and potential for reward associated with the assets of the subsidiary.
The tables below detail the assets and liabilities (excluding intercompany balances which are eliminated
in consolidation) for our VIEs, combined by VIE classification, that were included in our Consolidated Balance
Sheets as of December 31, 2009 and 2008 (in millions):
Condensed Combined VIE Assets and Liabilities
2009
Purchase
Options
Project Debt
PPAs
Other
Assets:
Current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restricted cash, net of current portion . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . .
Property, plant and equipment, net
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
288
16
2,560
101
Total assets(1)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
2,965
Liabilities:
Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term derivative liabilities . . . . . . . . . . . . . . . . . . . . . . . .
Other liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
143
1,091
—
9
$
$
$
$
396
12
3,038
57
$
78
17
1,349
38
3,503
$ 1,482
$
$
97
1,940
6
11
34
11
—
8
53
$
$
204
—
—
—
204
175
—
—
—
175
Total liabilities(1)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1,243
$
2,054
$
138
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
2008
Purchase
Options
Project Debt
PPAs
Other
Assets:
Current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restricted cash, net of current portion . . . . . . . . . . . . . . . . . .
Property, plant and equipment, net
. . . . . . . . . . . . . . . . . . . .
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total assets(1)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities:
Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term derivative liabilities . . . . . . . . . . . . . . . . . . . . . . .
Other liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
224
3
2,863
94
3,184
204
1,413
11
10
$
$
$
$
$
369
16
2,438
32
152
27
1,413
7
2,855
$
1,599
$
$
412
1,313
14
5
$
33
58
—
9
Total liabilities(1)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1,638
$
1,744
$
100
$
103
111
—
4
218
142
131
—
—
273
(1) The assets and liabilities listed above for our VIEs with purchase options may not be indicative of our risk
of loss. Some of the above VIEs include sale options that are held by us or purchase options held by others,
some are for only a minority interest, some are only for a portion of a VIE’s total assets and liabilities and
some are only effective upon the occurrence of an event of default.
Unconsolidated VIEs and Investments
We do not consolidate OMEC, a VIE where we have determined that we are not the primary beneficiary.
We also have a joint venture interest in Greenfield LP and a less-than-majority equity interest in Whitby where
we do not have control and therefore do not consolidate. We account for these entities under the equity method of
accounting and include our net equity interest in investments on our Consolidated Balance Sheets as we exercise
significant influence over their operating and financial policies. Our equity interest in the net (income) loss from
our unconsolidated VIE, joint venture and equity interest is recorded in (income) loss from unconsolidated
investments in power plants on our Consolidated Statements of Operations.
At December 31, 2009 and 2008, our equity method investments included on our Consolidated Balance
Sheets were comprised of the following (in millions):
OMEC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Greenfield LP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Whitby . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
100%
50%
50%
Total investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ownership
Interest as of
December 31,
2009
2009
2008
$
$
144
70
—
214
$
$
98
46
—
144
139
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
The following details our (income) loss and distributions from unconsolidated investments in power
plants for the years ended December 31, 2009, 2008 and 2007 (in millions):
(Income) Loss from Unconsolidated
Investments in Power Plants
Distributions
2009
2008
2007
2009
2008
2007
OMEC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Greenfield LP . . . . . . . . . . . . . . . . . . . . . . . . . . .
RockGen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Whitby . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Auburndale . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(32) $
(16)
—
(2)
—
$
55
5
(9)
(2)
180
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(50) $
229
$
9
12
—
—
—
21
$
$
9
9
—
2
—
20
$
$
— $
24
—
3
—
27
$
—
104
—
—
—
104
Our risk of loss related to our unconsolidated VIE, OMEC, is limited to our investment balance and our
operational risks during the period we operate OMEC. The debt on the books of our unconsolidated investments
is not reflected on our Consolidated Balance Sheets. As of December 31, 2009 and 2008, equity method investee
debt was approximately $873 million and $697 million, respectively. Based on our pro rata share of each of the
investments, our share of such debt would be approximately $624 million and $477 million as of December 31,
2009 and 2008, respectively.
OMEC — OMEC, an indirect wholly owned subsidiary, is the owner of the Otay Mesa Energy Center, a
608 MW natural gas-fired power plant in southern San Diego County, California. OMEC began commercial
operations on October 3, 2009. OMEC has a ten-year tolling agreement with SDG&E. We do not consolidate
OMEC as a result of a put option held by OMEC to sell the Otay Mesa Energy Center for $280 million to
SDG&E, and a call option held by SDG&E to purchase the Otay Mesa Energy Center for $377 million at the end
of the tolling agreement. We determined SDG&E has a greater variability of risk compared to us and we are not
the primary beneficiary.
OMEC has a $377 million non-recourse project finance facility construction loan, which converted to a
term loan on November 13, 2009 and matures in April 2019. Borrowings under the project finance facility are
initially priced at LIBOR plus 1.5%. The term loan bears interest at LIBOR plus 1.25%. We contributed $19
million and $9 million for the years ended December 31, 2009 and 2008, respectively, as an additional
investment in OMEC.
Greenfield LP — Greenfield LP is a limited partnership between certain subsidiaries of ours and a third
party which operates the Greenfield Energy Centre, a 1,005 MW natural gas-fired power plant in Ontario,
Canada. We and a third party each hold a 50% joint venture interest in Greenfield LP. Greenfield LP holds an
18-year term loan in the 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%. We contributed nil and $8 million for the
years ended December 31, 2009 and 2008, respectively, as an additional investment in Greenfield LP.
Whitby — Represents our 50% investment in Whitby held by our Canadian subsidiaries, which were
reconsolidated on the Canadian Effective Date.
RockGen — On December 6, 2007, our subsidiary RockGen, which had leased the RockGen Energy
Center from the RockGen Owner Lessors pursuant to a sale and leaseback arrangement, entered into a settlement
agreement and a purchase and sale agreement with the RockGen Owner Lessors to purchase the RockGen Energy
140
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
Center for an allowed general unsecured claim of approximately $145 million. While the allowed claim was
approved by the U.S. Bankruptcy Court in December 2007, the purchase agreement was conditional upon certain
events before title could transfer to us. All of the conditions were satisfied in January 2008 and the acquisition of
RockGen Energy Center assets closed on January 15, 2008.
On January 15, 2008, we closed on our purchase of the RockGen Energy Center assets which terminated
the prior sale-leaseback agreement and also required us to reconsider if we were RockGen’s primary beneficiary.
RockGen’s PPA with WP&L contained a call option which allowed WP&L and related parties to purchase the
RockGen Energy Center assets at a fixed price on May 31, 2009, provided they gave us 180-days prior written
notice. The call option effectively created a ceiling value for us and absorbed the majority of the expected change
in fair value of the RockGen Energy Center assets and transferred it to WP&L. As a result, we determined that
we were not RockGen’s primary beneficiary. Accordingly, we deconsolidated RockGen during the first quarter
of 2008, and accounted for our investment in RockGen under the equity method through December 2, 2008.
On December 2, 2008, (180 days prior to May 31, 2009) WP&L’s period to exercise the purchase option
expired without providing written notification. This resulted in a reconsideration event and we determined that
expiration of the option eliminated the transfer of the risk of loss and potential for future reward to us and that we
are RockGen’s primary beneficiary. We reconsolidated RockGen as of December 2, 2008. The expiration of the
purchase option also terminated WP&L’s variable interest and RockGen is no longer a VIE. The reconsolidation
resulted in the addition to our Consolidated Balance Sheet of $141 million in property, plant and equipment, $11
million in other assets and $2 million in liabilities and removal of $150 million representing our investment
balance in RockGen.
Auburndale — Auburndale was an unconsolidated subsidiary accounted for under the equity method of
accounting for the period from August 21, 2008 through the date of its sale on November 21, 2008. Prior to
August 21, 2008, we consolidated Auburndale as we determined that we were Auburndale’s primary beneficiary.
Pomifer, an unrelated party, held a preferred interest which entitled it to approximately 70% of Auburndale’s
cash distributions through 2013. Pomifer also held an option which, upon exercise, entitled Pomifer to an
additional 20% of Auburndale’s cash distributions through 2013, as well as certain drag-along rights that would
require us to sell our remaining interest in Auburndale should Pomifer sell its interest in Auburndale. On
August 21, 2008, Pomifer exercised its option to the additional 20% of cash distributions, which required us,
under GAAP, to reconsider whether we remained Auburndale’s primary beneficiary. We determined that we
were no longer Auburndale’s primary beneficiary and we deconsolidated Auburndale during the third quarter of
2008. On September 30, 2008, Pomifer notified us of their intent to exercise their drag-along rights. Accordingly,
we determined that a sale of our remaining interest was probable. We compared our expected proceeds from such
sale to the net book value of our interest in Auburndale at September 30, 2008, to determine if an impairment
existed and, as a result, recorded an impairment loss of approximately $180 million, which is included in our
(income) loss from unconsolidated investments in power plants on our Consolidated Statement of Operations
during the year ended December 31, 2008. We sold our remaining interest in Auburndale on November 21, 2008.
Inland Empire Energy Center Put and Call Options — We hold a call option to purchase the Inland
Empire Energy Center development project (a 775 MW natural gas-fired power plant located in California) from
GE that may be exercised between years 7 and 14 of the life of the power plant. GE holds a put option whereby
they can require us to purchase the power plant, if certain plant performance criteria are met during year 15 of the
life of the power plant. We determined that we were not the primary beneficiary of the Inland Empire power
plant as we do not absorb the majority of the risk of loss associated with the project due to, but not limited to, the
fact that GE will continue to manage and fully fund the operation of the power plant. Additionally, if we
141
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
purchase the power plant under the call or put options, GE will continue to provide critical power plant
maintenance services throughout the remaining estimated useful life of the power plant.
Significant Subsidiary — OMEC meets the criteria of a significant subsidiary as defined under SEC
guidelines based upon the relationship of our equity income from our investment in this subsidiary to our
consolidated net income before income taxes. Condensed combined financial statements for our unconsolidated
subsidiaries are set forth below (in millions):
Condensed Combined Balance Sheets
of Our Unconsolidated Subsidiaries
December 31, 2009 and 2008
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Member’s interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
2009
2008
$
$
$
33
133
1,220
54
1,440
37
117
836
95
47
1,132
308
39
91
1,006
95
1,231
24
97
673
154
48
996
235
Total liabilities and member’s interest
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1,440
$
1,231
Condensed Combined Statements of Operations
of Our Unconsolidated Subsidiaries
For the Years Ended December 31, 2009, 2008 and 2007
2009
2008(1)
2007(1)
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Impairment of equity method investment . . . . . . . . . . . . . . . . . . . . . . .
$
Income (loss) from operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest (income) expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other (income) expense, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
256
195
—
61
2
5
54
$
$
121
106
180
(165)
12
58
$
(235) $
42
35
—
7
(1)
17
(9)
(1) Amounts include results from Auburndale and RockGen during the periods they were deconsolidated in
2008. Amounts prior to OMEC’s deconsolidation in the second quarter of 2007 are included in our
Consolidated Statements of Operations.
142
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
5. Other Assets
As of December 31, 2009 and 2008, the components of other assets were as follows (in millions):
Prepaid lease, net of current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Notes receivable, net of current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred financing costs, net of current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intangible assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
2009
2008
127
68
176
38
74
90
573
$
$
115
83
211
26
77
104
616
Prepaid Lease, Net of Current Portion — Included in prepaid lease, net of current portion, are operating
leases for South Point Energy Center, Gilroy Energy Center and Kennedy International Airport Power Plant at
December 31, 2009. At December 31, 2008, operating leases for South Point Energy Center and Gilroy Energy
Center were included in prepaid lease, net of current portion.
Notes Receivable, Net of Current Portion — Notes receivable, net of current portion, primarily consists of
a secured financing for the sale of a note receivable from PG&E with an original net book value of $157 million
in December 2003 for $133 million in cash. We recorded the transaction as a secured financing, with an
offsetting note payable of $133 million. The notes receivable balance and note payable balance are both reduced
as PG&E makes payments to the buyers of the notes receivable. The $24 million difference between the original
$157 million net book value of the notes receivable at the transaction date and the $133 million cash received is
recognized as additional interest expense over the repayment term. The fair value of the note receivable as of
December 31, 2009 and 2008, was $83 million and $96 million, respectively.
Deferred Financing Costs, Net of Current Portion — Deferred financing costs related to the issuance of
our debt. See Note 7 for further discussion of our debt.
Deposits — Deposits include margin deposits as well as other deposits.
Intangible Assets, Net — Intangible assets, net,
include lease levelization costs and power sales
agreement amounts.
Other — Other consists of our long-term deferred tax asset, project development costs and deferred
transmission credits.
6. Asset Sales and Purchase
2008
On January 15, 2008, we purchased the RockGen Energy Center from the RockGen Owner Lessors.
RockGen previously leased the RockGen Energy Center from the RockGen Owner Lessors, which are not
affiliates of ours, pursuant to a leveraged operating lease. We purchased the RockGen Energy Center for an
allowed general unsecured claim of approximately $145 million, plus interest. As a result of the lease termination
and related acquisition, we recorded $102 million in reorganization items on our 2007 Consolidated Statement of
Operations to expense prepaid lease assets related to the RockGen Energy Center.
143
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
On February 14, 2008, we completed the sale of substantially all of the assets comprising the Hillabee
development project, a partially completed 774 MW combined-cycle power plant located in Alexander City,
Alabama, to CER Generation, LLC for approximately $156 million, plus the assumption of certain liabilities. We
recorded a pre-tax gain of approximately $63 million in the first quarter of 2008, which is included in
reorganization items on our 2008 Consolidated Statement of Operations.
On March 5, 2008, we completed the sale of substantially all of the assets comprising the Fremont
development project, a partially completed 550 MW natural gas-fired power plant located in Fremont, Ohio, to
First Energy Generation Corp. for approximately $254 million, plus the assumption of certain liabilities. We
recorded a pre-tax gain of approximately $136 million in the first quarter of 2008, which is included in
reorganization items on our 2008 Consolidated Statement of Operations.
On August 21, 2008, Pomifer exercised its purchase option to purchase additional cash distributions of
20% through 2013 from Auburndale as further described in Note 4. On September 30, 2008, we received notice
that Pomifer had entered into an asset purchase agreement with a third party and that Pomifer intended to
exercise its drag-along rights to sell 100% of Auburndale. We recorded an impairment loss of approximately
$180 million based upon the anticipated sales proceeds. We sold our remaining interest in Auburndale on
November 21, 2008.
The sales of the Hillabee and Fremont development projects and the sale of Auburndale did not meet the
criteria for discontinued operations due to our continuing activity in the markets in which these power plants
were located; therefore, the results of operations for all periods prior to sale are included in our continuing
operations.
2007
On January 16, 2007, we completed the sale of the Aries Power Plant, a 590 MW natural gas-fired power
plant in Pleasant Hill, Missouri, to Dogwood Energy LLC, an affiliate of Kelson Holdings, LLC, for $234
million plus certain per diem expenses incurred by us for running the power plant after December 21, 2006,
through the closing of the sale. We recorded a pre-tax gain of approximately $78 million included in
reorganization items on our Consolidated Statements of Operations. As part of the sale we were also required to
use a portion of the proceeds received to repay approximately $159 million principal amount of financing
obligations, $8 million in accrued interest, $11 million in accrued swap liabilities and $14 million in debt
pre-payment, and make whole premium fees to our project lenders.
On February 21, 2007, we completed the sale of substantially all of the assets of the Goldendale Energy
Center, a 247 MW natural gas-fired power plant located in Goldendale, Washington, to Puget Sound Energy LLC
for approximately $120 million, plus the assumption by Puget Sound Energy LLC of certain liabilities. We
recorded a pre-tax gain of approximately $31 million included in reorganization items on our 2007 Consolidated
Statements of Operations.
On March 22, 2007, we completed the sale of substantially all of the assets of PSM, a designer,
manufacturer and marketer of turbine and combustion components, to Alstom Power Inc. for approximately $242
million, plus the assumption by Alstom Power Inc. of certain liabilities. In connection with the sale, we entered
into a parts supply and development agreement with PSM whereby we committed to purchase turbine parts and
other services totaling approximately $200 million over a five-year period. We recorded a pre-tax gain of $135
million included in reorganization items on our 2007 Consolidated Statements of Operations.
144
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
On July 6, 2007, we completed the sale of the Parlin Power Plant, a 118 MW natural gas-fired power
plant in Parlin, New Jersey, to EFS Parlin Holdings, LLC, an affiliate of General Electric Capital Corporation,
for approximately $3 million in cash, plus the assumption by EFS Parlin Holdings, LLC of certain liabilities and
the agreement to waive certain asserted claims against the Parlin Power Plant. We recorded a pre-tax gain of
approximately $40 million included in reorganization items on our 2007 Consolidated Statements of Operations.
On September 13, 2007, we completed the sale of our 50% interest in Acadia PP, the owner of the Acadia
Energy Center, a 1,212 MW natural gas-fired power plant located near Eunice, Louisiana, to Cajun Gas Energy,
L.L.C. for consideration totaling approximately $189 million consisting of $104 million in cash and the payment
of $85 million in priority distributions due to Cleco Corp. (the indirect owner, through its wholly owned
subsidiary, Acadia Power Holdings, LLC, of the remaining 50% ownership interest in Acadia PP) in accordance
with the limited liability company agreement, plus the assumption by Cajun Gas Energy, L.L.C. of certain
liabilities. We recorded a pre-tax loss of $6 million, after recording a pre-tax, predominately non-cash
impairment charge of approximately $89 million, to record our interest in Acadia PP at fair value less the cost to
sell, both charges are included in reorganization items on our Consolidated Statements of Operations.
Additionally, in connection with the sale, we entered into a settlement agreement with Cleco Corp., which was
approved by the U.S. Bankruptcy Court on May 9, 2007, under which Cleco Corp. received an allowed
unsecured claim against us in the amount of $85 million as a result of the rejection by CES of two long-term
PPAs for the output of the Acadia Energy Center and our guarantee of those agreements. We recorded expense of
$85 million for this allowed claim during the second quarter of 2007, which is included in reorganization items
on our 2007 Consolidated Statements of Operations.
The sales of the Aries Power Plant, the Goldendale Energy Center, the Parlin Power Plant and our interest
in Acadia PP did not meet the criteria for discontinued operations due to our continuing activity in the markets in
which these power plants operate or were located; therefore, the results of operations for all periods prior to sale
are included in our continuing operations. Similarly, we have determined that the sale of PSM did not meet the
criteria for discontinued operations due to our continuing involvement through the parts supply and development
agreement; therefore, the results of operations for all periods prior to sale are included in our continuing
operations.
Discontinued Operations
On December 1, 2008, the U.S. Bankruptcy Court finalized the settlement with Rosetta for all of our
outstanding claims related to our domestic oil and gas assets we sold to Rosetta for $1.1 billion in 2005. Under
the settlement, Rosetta paid us $97 million; we completed the transfer of certain other assets; we and Rosetta
extended an existing natural gas purchase agreement for an additional ten years; and we and Rosetta executed
mutual releases.
The original sale of our domestic oil and gas assets was recorded as discontinued operations on our 2005
Consolidated Statement of Operations. Of the $97 million settlement proceeds received, $79 million was
associated with the certain other assets with a remaining net book value of approximately $42 million related to
our domestic oil and gas assets we sold to Rosetta in 2005. The resulting $37 million gain is reflected as
discontinued operations on our 2008 Consolidated Statement of Operations. The remaining $18 million
settlement proceeds received was associated with the agreed upon fraudulent conveyance of $12 million, which
is included in reorganization items on our 2008 Consolidated Statement of Operations, and approximately $6
million in revenues collected by Rosetta during the litigation period on assets retained by us.
145
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
The table below presents the components of our discontinued operations for the year ended December 31,
2008 (in millions):
Income from discontinued operations before taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Discontinued operations, net of tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2008
37
14
23
$
$
7. Debt
Our debt at December 31, 2009 and 2008, was as follows (in millions):
2009
2008
First Lien Credit Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
First Lien Notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commodity Collateral Revolver . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Project financing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CCFC New Notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CCFC Old Notes and CCFC Term Loans . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Preferred interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Notes payable and other borrowings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital lease obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Current maturities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
4,661
1,200
100
1,562
959
—
25
253
699
9,459
463
Debt, net of current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
8,996
$
6,645
—
100
1,525
—
778
335
356
733
10,472
716
9,756
Annual Debt Maturities
Contractual annual principal repayments or maturities of debt instruments as of December 31, 2009, are
as follows (in millions):
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter
$
Total debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
477
642
275
156
4,463
3,508
9,521
62
9,459
146
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
First Lien Facilities
Upon our emergence from Chapter 11, we converted the approximately $4.9 billion of loans and
commitments outstanding under our DIP Facility (including the $1.0 billion revolver)
into loans and
commitments under our approximately $7.3 billion of First Lien Facilities. Our First Lien Facilities provided for
approximately $2.1 billion in senior secured term loans and $300 million in senior secured bridge loans in
addition to the loans and commitments that had been available under the DIP Facility. Our First Lien Facilities
include:
• Our First Lien Credit Facility, comprised of:
i. approximately $6.0 billion of senior secured term loans;
ii. a $1.0 billion senior secured revolving facility; and
iii. the ability to raise up to $2.0 billion of incremental term loans available on a senior secured basis
in order to refinance secured debt of subsidiaries under an “accordion” provision; and
•
a bridge facility, which, prior to its repayment as described below, provided for a $300 million senior
secured bridge term loan.
On the Effective Date, we fully drew on our approximately $6.0 billion of senior secured term loans and
$300 million bridge facility and we drew approximately $150 million under the $1.0 billion senior secured
revolving facility. The proceeds of the drawdowns, above the amounts that had been applied under the DIP
Facility, were used to repay a portion of the Second Priority Debt, fund distributions under our Plan of
Reorganization to holders of other secured claims and to pay fees, costs, commissions and expenses in
connection with our First Lien Facilities and the implementation of our Plan of Reorganization.
The bridge facility was repaid in full on March 6, 2008, in accordance with its terms with proceeds from
the sales of the Hillabee and Fremont development project assets. Prior to repayment, borrowings under the
bridge facility bore interest at LIBOR plus 2.875% per annum.
On October 2, 2008, we borrowed $725 million under our First Lien Credit Facility revolving facility.
The borrowing was made as a base rate loan which initially bore interest at the base rate (5% on date of
borrowing) plus 1.875% per annum. Proceeds from the borrowing were invested in money market funds, which
are mainly invested in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. government,
its agencies or instrumentalities. On September 28, 2009, we repaid $725 million previously drawn under our
First Lien Credit Facility revolver from cash on hand.
As of December 31, 2009, under our First Lien Credit Facility, we had approximately $4.7 billion
outstanding under the term loan facilities and $206 million of letters of credit issued against the revolver.
Borrowings of term loans under our First Lien Credit Facility bear interest at a floating rate, at our option, of
LIBOR plus 2.875% per annum or base rate plus 1.875% per annum. First Lien Credit Facility term loans require
quarterly payments of principal equal to 0.25% of the original principal amount of First Lien Credit Facility term
loans. Our First Lien Credit Facility matures on March 29, 2014.
The obligations under our First Lien Credit Facility are unconditionally guaranteed by certain of our
direct and indirect domestic subsidiaries and are secured by a security interest in substantially all of the tangible
and intangible assets of Calpine Corporation and certain of the guarantors. The obligations under our First Lien
147
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
Credit Facility are also secured by a pledge of the equity interests of the direct subsidiaries of certain of the
guarantors, subject to certain exceptions, including exceptions for equity interests in foreign subsidiaries, existing
contractual prohibitions and prohibitions under other legal requirements. Our First Lien Credit Facility contains
restrictions, including limiting our ability to, among other things:
•
incur additional indebtedness and issue certain stock;
• make prepayments on or purchase certain indebtedness in whole or in part;
•
•
pay dividends and other distributions with respect to our stock or repurchase our stock or make other
restricted payments;
use money borrowed under our First Lien Credit Facility for non-guarantors (including foreign
subsidiaries);
• make certain investments;
•
•
•
•
create or incur liens;
consolidate or merge with another entity, or allow one of our subsidiaries to do so;
lease, transfer or sell assets and use proceeds of permitted asset leases, transfers or sales;
pay dividends or make other distributions from certain of our subsidiaries up to Calpine Corporation;
• make capital expenditures beyond specified limits;
•
•
•
engage in certain business activities;
enter into certain transactions with our affiliates; and
acquire power plants or other businesses.
Our First Lien Credit Facility also requires compliance with financial covenants that include a maximum
ratio of total net debt to Consolidated EBITDA (as defined in the First Lien Credit Facility), a minimum ratio of
Consolidated EBITDA to cash interest expense, and a maximum ratio of total senior net debt to Consolidated
EBITDA.
Amendment of First Lien Credit Facility and Issuance of First Lien Notes due 2017
We executed the First Amendment to Credit Agreement and Second Amendment to Collateral Agency
and Intercreditor Agreement dated as of August 20, 2009, which amended both the First Lien Credit Facility
Credit Agreement and the First Lien Credit Facility Collateral Agency and Intercreditor Agreement. The
amendment provides additional flexibility with our capital structure and First Lien Credit Facility by granting us
the option, subject to certain conditions, to buy back debt at a discount using cash on hand via an auction process;
to offer first lien bonds in exchange for or to retire First Lien Credit Facility term loans; to issue up to $2.0
billion of first lien bonds in lieu of issuing first lien term loans under the accordion provision of our First Lien
148
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
Credit Facility; and to extend all or a portion of the revolver and term loan maturities, on revised terms, subject to
acceptance by applicable lenders. In addition, the amendment provides for the aggregation of various investment
and capital expenditure baskets for covenant purposes.
We subsequently issued approximately $1.2 billion aggregate principal amount of First Lien Notes in a
private placement on October 21, 2009. We received no net cash proceeds from the transaction. The offer and
sale of our First Lien Notes was consummated as a permitted debt exchange pursuant to our First Lien Credit
Facility in exchange for a like principal amount of First Lien Credit Facility term loans. Upon their exchange for
First Lien Notes, such term loans were canceled and may not be redrawn. Our First Lien Notes bear interest at
7.25% per annum payable on April 15 and October 15 of each year, beginning on April 15, 2010. Our First Lien
Notes will mature on October 15, 2017; however, among other things, prior to October 15, 2012, we may redeem
up to 35% of the aggregate principal amount of our First Lien Notes with the net cash proceeds of certain equity
offerings, at a price equal to 107.25% of the aggregate principal amount thereof, plus accrued and unpaid
interest. Beginning on October 15, 2013, we may redeem all or a portion of our First Lien Notes at a premium as
defined in the indenture governing our First Lien Notes, plus accrued and unpaid interest. Our First Lien Notes
are guaranteed by each of our current and future domestic subsidiaries that is a borrower or guarantor under our
First Lien Credit Facility and our First Lien Notes rank 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 our First Lien Notes. Our
First Lien Notes are secured equally and ratably with indebtedness under our First Lien Credit Facility by a first-
priority lien, subject to certain exceptions and permitted liens, on substantially all of our and certain of the
guarantors’ existing and future assets.
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 prohibited commodity hedge agreements;
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.
In connection with the amendment of our First Lien Credit Facility and issuance of our First Lien Notes,
we recorded approximately $25 million in debt extinguishment costs related to the retirement of the term loans
under our First Lien Credit Facility and approximately $25 million in new deferred financing costs on our
Consolidated Balance Sheet during 2009.
149
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
Project Financing
The components of our project financing are (in millions, except for interest rates):
Outstanding at December 31,
Weighted Average
Effective Interest Rates(2)
2009
2008
2009
2008
$
Bethpage Energy Center 3, LLC due 2020-2025(1) . . . . . . . . .
Gilroy Energy Center, LLC due 2011 . . . . . . . . . . . . . . . . . . .
Blue Spruce due 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Riverside Energy Center, LLC due 2011 . . . . . . . . . . . . . . . .
Rocky Mountain Energy Center, LLC due 2011 . . . . . . . . . .
Metcalf due 2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Steamboat due 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deer Park due 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
107
76
76
311
140
261
452
128
11
112
113
83
328
164
264
453
—
8
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1,562
$
1,525
7.0%
7.3
4.9
7.6
7.7
7.0
6.9
7.5
—
6.9%
7.3
5.8
9.3
9.9
7.9
6.5
—
—
(1) Represents a weighted average of first and second lien loans.
(2) Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt
discount.
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.
On November 24, 2009, Steamboat amended and extended the terms of its credit agreement. The
Steamboat Amended Credit Facility increases the amount of term loans outstanding by $17 million from $448
million to $465 million. The increase in the borrowing was used to pay accrued and unpaid interest, breakage
costs and other fees in connection with closing the Steamboat Amended Credit Facility. The Steamboat Amended
Credit Facility also provides for a “security fund” letter of credit facility of up to $11 million and a “DSR” letter
of credit facility of up to approximately $23 million. The maturity date of the term loans facilities has been
extended from December 2011 to November 24, 2017. The security fund letter of credit facility, matures on
November 24, 2017 with the term loans and the DSR letter of credit facility matures on September 29, 2017. We
recorded approximately $7 million in new deferred financing costs on our Consolidated Balance Sheet as of
December 31, 2009, and approximately $2 million in debt extinguishment costs related to the write-off of the old
deferred financing costs on our Consolidated Statement of Operations for the year ended December 31, 2009.
Interest on the term loans is at a base rate or LIBOR (as defined in the Steamboat Amended Credit Facility)
as elected by Steamboat plus a rate margin which escalates from 2.875% to 3.375% (less 1% for a base rate loan)
during the term of the Steamboat Amended Credit Facility. Principal and interest are due and payable on the last
banking day of each calendar quarter. Steamboat may, at its option convert the interest rate on all or a portion of the
amounts outstanding under the term loans to the one month, three month or six month LIBOR rate plus the rate
margin and may convert any LIBOR rate loan back to a base rate loan. Both the security fund and “DSR” letter of
credit facilities incur a commitment fee equal to 1.0% for the average unutilized letters of credit and a letter of credit
participation fee equal to the rate margin for the stated amount of the issued letters of credit. Under the Steamboat
Amended Credit Facility we are required to hedge a minimum of 75% of our interest rate exposure, and as of
150
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
December 31, 2009, we have hedged approximately 95% of this interest rate exposure with interest rate swaps. See
Note 9 for further discussion regarding our interest rate swaps.
Subject to certain limitations and minimum amounts, Steamboat may elect to permanently reduce the
commitment amounts under both the security fund and DSR letter of credit facilities and prepay, without penalty,
in whole or in part, the amounts outstanding under the term loans. The Steamboat Amended Credit Facility
contains certain restrictive covenants and allows for acceleration of the debt in the event of certain defaults and is
secured, subject to certain exceptions and permitted liens, by all real and personal property of Steamboat and its
wholly owned subsidiaries, Freeport Energy Center and Mankato Power Plant.
On January 21, 2009, Deer Park, our indirect wholly owned subsidiary, closed on $156 million of senior
secured credit facilities, which include a $150 million term facility and a $6 million letter of credit facility.
Proceeds received were used to settle an existing commodity contract of approximately $79 million, pay
financing and legal fees of approximately $8 million and fund approximately $22 million in restricted cash. The
remainder was distributed to Calpine Corporation for general corporate purposes. The senior term loan facility
matures on January 21, 2012, and bears interest of LIBOR plus 3.5% or base rate plus 2.5% at Deer Park’s option.
On June 10, 2008, Metcalf, an indirect wholly owned subsidiary, closed on a $265 million new term loan
facility. The proceeds were used to repay Metcalf’s existing $100 million term loan facility and $155 million
preferred interests. The new term loan facility, which matures on June 10, 2015, bears interest at Metcalf’s option at
LIBOR plus 3.25% or base rate plus 2.25% and is secured by the assets of Metcalf and the sole member interest held
by Metcalf’s parent, Metcalf Holdings, LLC. In connection with this refinancing, we recorded $6 million in loss on
debt extinguishment, related to the write-off of deferred financing costs of $3 million and prepayment penalties of
$3 million, which are recorded in debt extinguishment costs on our 2008 Consolidated Statement of Operations.
On February 1, 2008, Blue Spruce, an indirect wholly owned subsidiary, entered into a $90 million senior
term loan. Net proceeds from the senior term loan were used to refinance all outstanding indebtedness under the
existing Blue Spruce term loan facility, to pay fees and expenses related to the transaction and for general corporate
purposes. The senior term loan carries interest at a base rate plus 0.63% which escalates to 1.50% or LIBOR plus
1.63%, which escalates to 2.50% over the life of the senior term loan and matures December 31, 2017. The senior
term loan is secured by the assets of Blue Spruce. In connection with this refinancing, we recorded $7 million in loss
on debt extinguishment, related to the write-off of deferred financing costs of $4 million and prepayment penalties
of $3 million, which are recorded in debt extinguishment costs on our 2008 Consolidated Statement of Operations.
CCFC New Notes, CCFC Old Notes and CCFC Term Loans
On May 19, 2009, our wholly owned subsidiaries, CCFC and CCFC Finance, issued approximately
$1.0 billion aggregate principal amount of CCFC New Notes in a private placement. Interest on the CCFC New
Notes accrues at the rate of 8.0% per annum and is payable semi-annually in arrears on each June 1 and
December 1, commencing on December 1, 2009. The CCFC New Notes, which mature on June 1, 2016, are
guaranteed by two of CCFC’s subsidiaries. The CCFC New 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 New 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. The
net proceeds received of $939 million, together with CCFC cash on hand of $271 million, were used to:
•
repay the $364 million outstanding under the CCFC Term Loans on May 19, 2009;
151
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
•
•
•
redeem the $415 million outstanding principal amount of CCFC Old Notes on June 18, 2009;
distribute $327 million to CCFC’s indirect parent, CCFCP, which was used by CCFCP to redeem its
$300 million CCFCP Preferred Shares discussed below on or before July 1, 2009; and
in each case, pay any interest, prepayment penalties and other amounts due through the date of such
repayment or redemption.
In connection with the CCFC Refinancing, we recorded $49 million in debt extinguishment costs for the year
ended December 31, 2009. Debt extinguishment costs are comprised of $7 million from the write-off of unamortized
deferred financing costs and unamortized debt discount, $24 million of prepayment penalties related to redemption
of the CCFC Old Notes, $2 million from the write-off of unamortized deferred financing costs and unamortized debt
discount and $16 million related to prepayment penalties related to the redemption of the CCFCP Preferred Shares.
We also recorded approximately $21 million in new deferred financing costs on our Consolidated
Balance Sheet upon closing the CCFC Refinancing.
The components of the CCFC financing are (in millions, except for interest rates):
Outstanding at December 31,
Weighted Average
Effective Interest Rates(2)
2009
2008
2009
2008
CCFC Old Notes(1)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CCFC Term Loans(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CCFC New Notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total CCFC financing . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
— $
—
959
959
$
412
366
—
778
—%
—
8.9
12.6%
10.3
—
(1) The CCFC Old Notes and CCFC Term Loans were repaid with the proceeds from the CCFC New Notes
during 2009.
(2) Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt
discount.
Preferred Interests
Our preferred interests meet the criteria of mandatorily redeemable financial instruments and are therefore
classified as debt. The components of preferred interests are as follows (in millions, except for interest rates):
Outstanding at December 31,
Weighted Average
Effective Interest Rates(2)
2009
2008
2009
2008
Preferred interest in GEC Holdings, LLC due 2011 . . .
. . . . . . . . . . . .
Preferred interest in CCFCP due 2011(1)
Total preferred interests . . . . . . . . . . . . . . . . . . . . . . .
$
$
25
—
25
$
$
35
300
335
13.9%
—
14.8%
13.5
(1) Amounts were repaid with the proceeds from the CCFC New Notes during 2009.
(2) Our weighted average interest rate calculation includes the amortization of deferred financing costs.
152
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
Notes Payable and Other Borrowings
The components of notes payable and other borrowings are (in millions, except for interest rates):
Outstanding at December 31,
Weighted Average
Effective Interest Rates(2)
2009
2008
2009
2008
PCF III due 2010(1)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PCF due 2010(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gilroy note payable due 2014 . . . . . . . . . . . . . . . . . . . . .
Whitby Holdings due 2017 . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
84
55
77
31
6
Total notes payable and other borrowings . . . . . . . . .
$
253
$
76
159
89
26
6
356
11.3%
9.6
10.6
8.9
4.8
10.2%
9.6
10.7
9.5
6.0
(1) Amounts were repaid from cash on hand on February 1, 2010 and February 5, 2010, for PCF and PCF III,
respectively.
(2) Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt
discount.
Capital Lease Obligations
The following is a schedule by year of future minimum lease payments under capital leases together with
the present value of the net minimum lease payments as of December 31, 2009 (in millions):
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter
$
Total minimum lease payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Amount representing interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Present value of net minimum lease payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
98
99
96
92
79
802
1,266
567
699
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 39 years (including lease renewal options). Some of the lease
agreements contain customary restrictions on dividends, additional debt and further encumbrances similar to
those typically found in project financing agreements. As of both December 31, 2009 and 2008, the asset
balances for the leased assets totaled approximately $1.3 billion with accumulated amortization of $349 million
and $279 million, respectively. See Note 17 for a discussion of capital leases guaranteed by Calpine Corporation.
Other Financing Agreements
During the first quarter of 2008, we entered into a letter of credit facility related to our subsidiary Calpine
Development Holdings, Inc. under which up to $150 million is available for letters of credit. On December 11,
2009, we amended the letter of credit facility to extend the maturity from January 31, 2010 to December 11,
153
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
2012, with an option to increase the letters of credit available from $150 million to $200 million by satisfying
certain conditions. As of December 31, 2009 and 2008, $116 million and $148 million in letters of credit,
respectively, had been issued under this facility.
On July 8, 2008, we entered into the Commodity Collateral Revolver, a two-year, $300 million secured
revolving credit facility, which shares the benefits of the collateral subject to the liens under our First Lien Credit
Facility ratably with the lenders under our First Lien Credit Facility. At closing, we borrowed an initial advance
of $100 million. Amounts borrowed under the Commodity Collateral Revolver were used to collateralize
obligations to counterparties under eligible commodity hedge agreements. On August 13, 2009, we terminated
$200 million of the remaining availability under the Commodity Collateral Revolver in accordance with its terms
as energy commodity prices were not expected to exceed stated thresholds in the near future and it was
considered unlikely that any of the $200 million remaining availability would be available to us. The $100
million currently outstanding under the Commodity Collateral Revolver will mature on July 8, 2010, and bears
interest at LIBOR plus 2.875% per annum.
On June 25, 2008, we entered into the Knock-in Facility, a 12-month, $200 million unsecured letter of
credit facility. Availability of letters of credit for issuance under the Knock-in Facility were up to a total
maximum availability of $200 million contingent on natural gas futures contract prices exceeding certain
thresholds, with initial availability for up to $50 million. The Knock-in Facility matured on June 30, 2009, and is
no longer available.
Letters of Credit Facilities
The table below represents amounts issued under our letter of credit facilities as of December 31, 2009
and 2008 (in millions):
First Lien Credit Facility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Calpine Development Holdings, Inc.
Knock-in Facility(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Various project financing facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(1) The Knock-in Facility matured on June 30, 2009, and is no longer available.
2009
2008
206
116
—
90
412
$
$
259
148
50
99
556
154
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
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 GAAP provisions of the fair value option for recording financial assets
and financial liabilities at fair value on our Consolidated Financial Statements. We measured the fair value of our
debt instruments as of December 31, 2009, using market information including credit default swap rates and
historical default information, quoted market prices or dealer quotes for the identical liability when traded as an
asset and discounted cash flow analyses based on our current borrowing rates for similar types of borrowing
arrangements. The following table details the fair values and carrying values of our debt instruments as of
December 31, 2009 and 2008 (in millions):
2009
2008
Fair Value
Carrying
Value
Fair Value
Carrying
Value
$
First Lien Credit Facility . . . . . . . . . . . . . . . . . . . . . . . . .
First Lien Notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commodity Collateral Revolver . . . . . . . . . . . . . . . . . . .
Project financing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CCFC New Notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
CCFC Old Notes and CCFC Term Loans . . . . . . . . . . . .
Preferred interests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Notes payable and other borrowings . . . . . . . . . . . . . . . .
$
4,402
1,138
94
1,542
1,030
—
25
241
$
4,661
1,200
100
1,562
959
—
25
253
$
4,812
—
85
1,420
—
727
305
330
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
8,472
$
8,760
$
7,679
$
6,645
—
100
1,525
—
778
335
356
9,739
8. Fair Value Measurements
Derivatives — We enter into a variety of derivative instruments, 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) for the purchase and sale of power, natural gas, and emission allowances as well as interest
rate swaps.
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 markets such as the Intercontinental Exchange. 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 primarily consist of our 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
155
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
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 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.
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 risks and 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; however, other qualitative assessments are used 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 primary factors affecting the fair value of our commodity derivative instruments at any point in time
are the volume of open derivative positions (MMBtu and MWh); market price levels, primarily for power and
natural gas; our credit standing and that of our counterparties; and prevailing interest rates. Prices for power and
natural gas are volatile, which can result in material changes in the fair value measurements reported in our
financial statements in the future.
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.
Margin Deposits — Our margin deposits are cash and cash equivalents and are generally classified within
level 1 of the fair value hierarchy as the amounts approximate fair value.
156
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
The following tables present our financial assets and liabilities that were accounted for at fair value on a
recurring basis as of December 31, 2009 and 2008, by level within the fair value hierarchy. 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 the valuation of fair value assets and liabilities and their placement within the fair
value hierarchy levels.
Assets and Liabilities with Recurring Fair Value Measures
as of December 31, 2009
Level 1
Level 2
Level 3
Total
Assets:
Cash equivalents(1) . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . .
Margin deposits(2)
Commodity derivative instruments . . . . . . . . . . . . . .
Interest rate swaps . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
1,306
413
953
—
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
2,672
$
Liabilities:
Margin deposits held by us posted by our
counterparties(2) . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commodity derivative instruments . . . . . . . . . . . . . .
Interest rate swaps . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
9
1,096
—
Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1,105
$
(in millions)
— $
—
204
18
222
$
— $
91
337
428
$
— $
—
71
—
71
$
— $
33
—
33
$
1,306
413
1,228
18
2,965
9
1,220
337
1,566
Assets and Liabilities with Recurring Fair Value Measures
as of December 31, 2008
Level 1
Level 2
Level 3
Total
Assets:
Cash equivalents(1) . . . . . . . . . . . . . . . . . . . . . . . . . . .
Margin deposits(2)
. . . . . . . . . . . . . . . . . . . . . . . . . . .
Commodity derivative instruments . . . . . . . . . . . . . .
$
$
2,092
653
3,263
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
6,008
$
Liabilities:
Margin deposits held by us posted by our
counterparties(2) . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commodity derivative instruments . . . . . . . . . . . . . .
Interest rate swaps . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
169
3,515
—
Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
3,684
$
(in millions)
— $
—
634
634
$
— $
475
452
927
$
— $
—
160
160
$
— $
55
—
55
$
2,092
653
4,057
6,802
169
4,045
452
4,666
(1) Amounts represent cash equivalents invested in money market accounts and are included in cash and cash
equivalents and restricted cash on our Consolidated Balance Sheets. As of December 31, 2009 and 2008, we
had cash equivalents of $770 million and $1,597 million included in cash and cash equivalents and $536
million and $495 million included in restricted cash, respectively.
(2) 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 contracts.
157
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
Gains or losses associated with level 3 balances may not necessarily reflect trends occurring in the
underlying business. Further, unrealized gains and losses for the period from level 3 items are often offset by
unrealized gains and losses on positions classified in levels 1 or 2, as well as positions that have been realized
during the period. Certain of our level 3 balances qualify for cash flow hedge accounting for which any
unrealized gains and losses are recorded in OCI. Gains and losses for level 3 balances that do not qualify for
hedge accounting are recorded in earnings.
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, 2009 and 2008 (in
millions):
2009
2008
Balance, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
105
$
(23)(1)
Realized and unrealized gains (losses):
Included in net income(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Included in OCI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Purchases, issuances and settlements, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transfers in and/or out of level 3(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in unrealized gains relating to instruments still held at end of period(2)
. . . . .
$
$
19
(4)
(48)
(34)
38
19
$
$
57
229
(97)
(61)
105
57
(1) Our portfolio of derivative assets and liabilities is adjusted for the day one loss of $(22) million, excluding
the tax benefit of $8 million, recognized upon adoption of the new fair value measurement standards on
January 1, 2008.
(2)
Includes $5 million and $78 million recorded in operating revenues (for power contracts and Heat Rate
swaps and options) and $14 million and $(21) million recorded in fuel and purchased energy expense (for
natural gas contracts) for the years ended December 31, 2009 and 2008, respectively as shown on our
Consolidated Statements of Operations.
(3) We transfer amounts among levels of the fair value hierarchy as of the end of each period.
158
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
9. Derivative Instruments
The following tables reflect the amounts that were recorded as derivative assets and liabilities on our
Consolidated Balance Sheets at December 31, 2009 and 2008, for our derivative instruments (in millions):
2009
Interest Rate
Swaps
Commodity
Instruments
Total
Derivative
Instruments
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative assets, current
Long-term derivative assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total derivative assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative liabilities, current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term derivative liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total derivative liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net derivative assets (liabilities) . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
$
— $
18
18
202
135
337
$
$
$
(319) $
1,119
109
1,228
1,158
62
1,220
8
$
$
$
$
$
2008
1,119
127
1,246
1,360
197
1,557
(311)
Derivative assets, current
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term derivative assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total derivative assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative liabilities, current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term derivative liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total derivative liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net derivative assets (liabilities) . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest Rate
Swaps
Commodity
Instruments
Total
Derivative
Instruments
$
$
$
$
$
— $
—
— $
179
273
452
$
$
(452) $
3,653
404
4,057
3,620
425
4,045
12
$
$
$
$
$
3,653
404
4,057
3,799
698
4,497
(440)
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) for
the purchase and sale of power, natural gas, and emission allowances to attempt to maximize the risk-adjusted
returns by economically hedging a portion of the commodity price risk associated with our assets. These
transactions primarily act as fair value and cash flow hedges. 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 significant portion of our debt is indexed to base rates, primarily LIBOR. We
use 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. These transactions primarily act as cash flow hedges for our variable
rate debt.
As of December 31, 2009, the maximum length of our PPAs extend approximately 22 years into the
future and the maximum length of time over which we were hedging using commodity and interest rate
derivative instruments was 3 and 16 years, respectively.
159
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
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. Unless these instruments settle by means of the physical delivery of a commodity,
revenues and expenses derived from these 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 our derivatives in the same category as the item being hedged within operating activities 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.
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 included in unrealized
mark-to-market gains and losses and are recognized currently in earnings as a component of operating revenues
(for power contracts), fuel and purchased energy expense (for natural gas contracts) and interest expense (for
interest rate swaps). If it is determined that the forecasted transaction is no longer probable of occurring, then
hedge accounting will be discontinued prospectively. If the hedging instrument is terminated or de-designated
prior to the occurrence of the hedged forecasted transaction, the gain or loss associated with the hedge instrument
remains deferred in OCI until such time as the forecasted transaction impacts earnings, or until it is determined
that the forecasted transaction is probable of not occurring.
Fair Value Hedges — Changes in fair value of derivatives designated as fair value hedges and the
corresponding changes in the fair value of the hedged risk attributable to a recognized asset or liability, or
unrecognized firm commitment are recorded in earnings. If the fair value hedge is effective, the amounts
recorded will offset in earnings. If the underlying asset, liability or firm commitment being hedged is disposed of
or otherwise terminated, the gain or loss associated with the underlying hedged item is recognized currently in
earnings. If the hedging instrument is terminated or de-designated prior to the settlement of the hedged asset,
liability or firm commitment, the carrying amount of the hedged item is adjusted by any gain or loss from the
hedging instrument and remains until the hedged item is recognized in earnings. We had no fair value hedges at
December 31, 2009; however, we had one fair value hedge at December 31, 2008 related to PCF.
Derivatives Not Designated as Hedging Instruments — Along with our portfolio of hedging instruments,
we enter into power, natural gas and interest rate transactions that primarily act as economic hedges to our asset
portfolio, but either do not qualify as hedges under hedge accounting guidelines or qualify under the hedge
accounting guidelines and the hedge accounting designation has not been elected, such as commodity futures,
forwards, options, fixed for floating swaps and instruments that settle on power price to natural gas price
relationships (Heat Rate swaps and options). Changes in fair value of derivatives not designated as hedging
instruments are recognized currently in earnings as a component of operating revenues (for power contracts and
Heat Rate swaps and options), fuel and purchased energy expense (for natural gas contracts) and interest expense
(for interest rate swaps).
160
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
Derivatives Included on Our Consolidated Balance Sheet
The following table presents the fair values of our net derivative instruments recorded on our
Consolidated Balance Sheet by hedge type and location at December 31, 2009 (in millions):
Derivatives designated as cash flow hedging instruments:
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fair Value
of Derivative
Assets(1)
Fair Value
of Derivative
Liabilities(2)
$
$
$
$
$
18
213
231
$
$
— $
1,015
1,015
1,246
$
$
324
80
404
13
1,140
1,153
1,557
(1)
Included in derivative assets on our Consolidated Balance Sheet as of December 31, 2009.
(2)
Included in derivative liabilities on our Consolidated Balance Sheet as of December 31, 2009.
We execute forward physical and financial commodity purchase and sales agreements to hedge our
exposure to underlying commodity risk. Through hedging and optimization activities it is not uncommon for us
to purchase and sell forward natural gas and power in both the physical and financial markets. As of
December 31, 2009, 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
Notional
Volumes
Power (MWh) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas (MMBtu) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest rate swaps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(52)
78
7,324
Certain of our derivative instruments contain credit-contingent provisions that require us to maintain our
current credit rating or higher from each of the major credit rating agencies. If our credit rating were to be
downgraded, it could require us to post additional collateral or could potentially allow our counterparty to request
immediate, full settlement on certain derivative instruments in liability positions. The aggregate fair value of our
derivative liabilities with credit-contingent provisions as of December 31, 2009, was $156 million for which we
have posted collateral of $5 million by posting margin deposits or granted additional first priority liens on the
assets currently subject to first priority liens under our First Lien Credit Facility. However, if our credit rating
were downgraded, we estimate that any additional collateral would not be material and that no counterparty could
request immediate, full settlement.
161
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
Derivatives Included on Our Consolidated Statements of Operations, OCI and AOCI
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 cash flow hedge accounting treatment, or on our Consolidated Statements of Operations as a
component of mark-to-market activity within our net income.
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 not designated as
hedging instruments and where these components were recorded on our Consolidated Statements of Operations
for the years ended December 31, 2009, 2008 and 2007 (in millions):
Realized gain (loss)
Interest rate swaps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commodity derivative instruments(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total realized gain (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrealized gain (loss)(2)
Interest rate swaps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commodity derivative instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total unrealized gain (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total mark-to-market activity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2009
2008
2007
$
$
$
$
$
(35) $
37
2
$
10
79
89
91
$
$
$
(11) $
(146)
(157) $
(11) $
35
24
$
(133) $
5
40
45
(17)
(35)
(52)
(7)
(1) Balance includes a non-cash gain from amortization of prepaid power sales agreements of approximately
nil, $40 million and $54 million for the years ended December 31, 2009, 2008 and 2007, respectively.
(2) Changes in unrealized gains and losses include hedge ineffectiveness and adjustments to reflect changes in
credit default risk exposure.
Power contracts included in operating revenues . . . . . . . . . . . . . . . . . . .
Natural gas contracts included in fuel and purchased energy
expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest rate swaps included in interest expense . . . . . . . . . . . . . . . . . . .
Total mark-to-market activity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
2009
2008
2007
7
$
232
$
252
109
(25)
91
$
(343)
(22)
(133) $
(247)
(12)
(7)
The following table details the effect of our net derivative instruments that qualified for hedge accounting
treatment on our Consolidated Statements of Operations and OCI, and the ineffectiveness related to our hedging
instruments for the year ended December 31, 2009 (in millions):
Gain (Loss)
Recognized in
OCI (Effective
Portion)
Gain (Loss)
Reclassified from
OCI into Income
(Effective
Portion)(3)
Gain (Loss)
Reclassified from
OCI into Income
(Ineffective
Portion)
Commodity derivative instruments . . . . . . . . . . . . . . . . . . . . . . .
Interest rate swaps included in interest expense . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
(280) $
125
(155) $
549(1) $
(214)
335
$
—(2)
—
—
(1)
Included in operating revenues and fuel and purchased energy expense on our Consolidated Statement of
Operations.
162
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
(2) The ineffective portion of gains (losses) reclassified from AOCI into income on commodity hedging
instruments was $2 million and $(2) million for the years ended December 31, 2008 and 2007, respectively.
(3) Cumulative net cash flow hedge losses included in AOCI were $261 million and $149 million at
December 31, 2009 and 2008, respectively.
Assuming constant December 31, 2009 power and natural gas prices and interest rates, we estimate that
pre-tax net losses of $94 million 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 natural gas and power prices as well as 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.
10. 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 our First Lien Credit
Facility as collateral under certain of our power and natural gas agreements that qualify as “eligible commodity
hedge agreements” under our First Lien Credit Facility 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 would share the benefits of the
collateral subject to such first priority liens ratably with the lenders under our First Lien Credit Facility.
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, 2009 and 2008 (in millions):
2009
2008
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(3) . . . . . . . . . . . . . . . . . .
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)(4) . . . . . . . . . . . . . . . . . . .
Letters of credit posted with us by our counterparties . . . . . . . . . . . . . . . . . . . . . . . .
$
$
$
$
$
$
$
$
$
$
413
34
447
353
—
333
686
9
70
Total margin deposits and letters of credit posted with us by our
counterparties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
79
$
653
60
713
455
—
477
932
169
95
264
(1) Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated
Balance Sheets.
(2) $426 million and $693 million were included in margin deposits and other prepaid expense on our
Consolidated Balance Sheets at December 31, 2009 and 2008, respectively, and $21 million and $20 million
were included in other assets at December 31, 2009 and 2008, respectively.
163
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
(3) The fair value of our commodity derivative instruments collateralized by first priority liens included assets
of $123 million and $201 million at December 31, 2009 and 2008, respectively; therefore, there was no
collateral exposure at December 31, 2009 and 2008.
(4)
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.
11. Income Taxes
Income Tax Expense (Benefit)
The jurisdictional components of income (loss) from continuing operations before income tax expense
(benefit) and discontinued operations, attributable to Calpine, for the years ended December 31, 2009, 2008 and
2007, are as follows (in millions):
U.S. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
International
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2009
2008
2007
$
$
151
13
164
$
$
(30) $
(30)
(60) $
2,160
(13)
2,147
The components of income tax expense (benefit) from continuing operations for the years ended
December 31, 2009, 2008 and 2007, consisted of the following (in millions):
2009
2008
2007
Current:
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(2) $
(2)
3
(10) $
2
(66)
Total current
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(1)
(74)
Deferred:
Federal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total income tax expense (benefit) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
13
4
(1)
16
15
164
(25)
11
(15)
(29)
(449)
(68)
—
(517)
24
3
—
27
$
(47) $
(546)
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
For the years ended December 31, 2009, 2008 and 2007, 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, 2009, 2008 and 2007, is as
follows:
Federal statutory tax expense (benefit) rate . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . .
State tax expense (benefit), net of federal benefit
Depletion in excess of basis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Valuation allowances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Foreign taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-deductible reorganization items . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from cancellation of indebtedness . . . . . . . . . . . . . . . . . . . . . .
Intraperiod allocation pursuant to OCI
. . . . . . . . . . . . . . . . . . . . . . . .
Bankruptcy settlement
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in unrecognized tax benefits . . . . . . . . . . . . . . . . . . . . . . . . . .
Permanent differences and other items . . . . . . . . . . . . . . . . . . . . . . . .
2009
2008
2007
35.0%
0.8
—
(116.8)
(7.3)
1.1
54.1
35.6
—
1.1
5.5
(35.0)%
9.7
(12.1)
323.6
(78.7)
(118.3)
43.7
(124.2)
(92.5)
5.8
(0.3)
35.0%
(2.6)
—
5.7
1.6
(65.2)
—
—
—
(1.9)
2.0
Effective income tax expense (benefit) rate . . . . . . . . . . . . . . . . . . . . . . .
9.1%
(78.3)%
(25.4)%
Deferred Tax Assets and Liabilities
The components of the deferred income taxes, net of current portion as of December 31, 2009 and 2008,
are as follows (in millions):
Deferred tax assets:
2009
2008
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 liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Current portion deferred tax asset (liability) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Non-current deferred tax asset . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
3,209
81
571
68
10
3,939
(2,572)
1,367
(1,417)
(50)
(8)
12
Deferred income taxes, net of current portion . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(54) $
3,310
10
583
51
6
3,960
(2,685)
1,275
(1,352)
(77)
1
15
(93)
For federal income tax reporting purposes, our consolidated GAAP financial reporting group is comprised
primarily of two groups, CCFC and its subsidiaries, which we refer to as the CCFC group, and Calpine
Corporation and its subsidiaries other than CCFC, which we refer to as the Calpine group. In 2005, CCFCP
issued the CCFCP Preferred Shares, which resulted in the deconsolidation of the CCFC group for income tax
165
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
purposes. On July 1, 2009, the CCFCP Preferred Shares were redeemed; however, CCFCP continues to be a
partnership and therefore, the CCFC group remains deconsolidated from Calpine Corporation for federal income
tax reporting purposes. As of December 31, 2009, the CCFC group did not have a valuation allowance recorded
against its deferred tax assets due to management’s assessment that the CCFC group would more likely than not
utilize its NOLs prior to their expiration.
In accordance with GAAP, intraperiod tax allocation provisions require allocation of a tax benefit to
continuing operations due to current OCI gains. We have recorded a tax expense of $43 million included in our
income before discontinued operations on our 2009 Consolidated Statement of Operations, with an offsetting $43
tax benefit in OCI and $0 tax benefit in income from discontinued operations. We recorded a tax benefit of $90
million included in our loss before discontinued operations on our 2008 Consolidated Statement of Operations,
with an offsetting $76 million tax expense in OCI and a $14 million tax expense in income from discontinued
operations.
NOL Carryforwards — Our carryforwards consist primarily of
federal NOL carryforwards of
approximately $7.5 billion, which expire between 2021 and 2029, and state NOL carryforwards of approximately
$4.6 billion, which expire between 2010 and 2029. The NOL carryforwards available are subject to limitations on
their annual usage. This includes an NOL carryforward of approximately $513 million for the CCFC group.
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. In addition, we have approximately $1.1 billion in foreign NOLs, substantially all of which are
offset with a full valuation allowance.
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.
Additionally, as of December 31, 2009, approximately $2.0 billion of our $7.5 billion NOLs are not limited
under Section 382 of the IRC. When considering our annual Section 382 limitations in addition to our NOLs that
are not limited, our total unlimited NOLs available to offset future income are approximately $3.9 billion, as of
December 31, 2009. However, if a subsequent ownership change were to occur as a result of future transactions
in our 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, including the $2.0 billion of
NOLs that are not currently limited by Section 382 of the IRC.
To manage the risk of significant limitations on our ability to utilize our tax NOL carryforwards, our
amended and restated certificate of incorporation permits our Board of Directors to meet to determine whether to
impose certain transfer restrictions on our common stock in the following circumstances: if, prior to February 1,
2013, our Market Capitalization declines by at least 35% from our Emergence Date Market Capitalization of
approximately $8.6 billion (in each case, as defined in and calculated pursuant to our amended and restated
certificate of incorporation) and at least 25 percentage points of shift in ownership has occurred with respect to
our equity for purposes of Section 382 of the IRC. We believe, as of the filing of this Report, we have
experienced declines in our stock price of more than 35% from our Emergence Date Market Capitalization.
While we don’t believe an ownership change of 25 percentage points has occurred, the change in ownership is
only slightly less than 25%. Accordingly, the transfer restrictions have not been put in place by our Board of
166
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
to impose them,
Directors; however, if both of the foregoing events were to occur together and our Board of Directors were to
elect
the
circumstances will not be met in the future, or in the event that they are met, that our Board of Directors would
choose to impose these restrictions or that, if imposed, such restrictions would prevent an ownership change from
occurring.
they could become operative in the future. There can be no assurance that
Should our Board of Directors elect to impose these restrictions, they shall have the authority and
discretion to determine and establish the definitive terms of the transfer restrictions provided that they apply to
purchases by owners of 5% or more of our common stock including any owners who would become owners of
5% or more of our common stock via such purchase. The transfer restrictions will not apply to the disposition of
shares provided they are not purchased by a 5% or more owner.
Valuation Allowance — 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, at December 31, 2007, we were able to
consider available tax planning strategies due to our expected emergence from Chapter 11. Future income from
reversals of existing taxable temporary differences and tax planning strategies allowed a larger portion of the
deferred tax assets to be offset against deferred tax liabilities resulting in a significant release of previously
recorded valuation allowance.
As of December 31, 2009, we have provided a valuation allowance of approximately $2.6 billion on
certain federal, state and foreign tax jurisdiction deferred tax assets to reduce the gross amount of these assets to
the extent necessary to result in an amount that is more likely than not of being realized. The net change in our
valuation allowance was a decrease of $113 million for the year ended December 31, 2009, and an increase of
$284 million and $80 million for the years ended December 31, 2008 and 2007, respectively; all primarily related
to our estimates of our ability to utilize our NOL carryforwards.
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 ending 2005 – 2008. We have timely responded to their request for information and the CRA has not
provided us with a timetable for their completion of the audit. At this time, we are unable to determine the
likelihood that the outcome could have a material adverse impact to us.
Unrecognized Tax Benefits
As of December 31, 2009, we had unrecognized tax benefits of $98 million. If recognized, $41 million of
our unrecognized tax benefits could impact the annual effective tax rate and $57 million related to deferred tax
assets, of which, $48 million could be offset against the recorded valuation allowance and $9 million could
reduce our deferred tax assets resulting in no impact to our effective tax rate. We also had accrued interest and
penalties of $17 million for income tax matters as of December 31, 2009. The amount of unrecognized tax
benefits increased by $8 million for the year ended December 31, 2009, primarily as a result of an increase of
approximately $11 million for withholding taxes and foreign exchange losses and reductions of approximately $1
million due to cash settlements and $2 million in other non-cash settlements with various state taxing authorities.
167
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
A reconciliation of the beginning and ending amounts of our unrecognized tax benefits for the years
ended December 31, 2009 and 2008, is as follows (in millions):
Balance, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increases related to prior year tax positions . . . . . . . . . . . . . . . . . . . . . . . .
Decreases related to prior year tax positions . . . . . . . . . . . . . . . . . . . . . . . .
Increases related to current year tax positions . . . . . . . . . . . . . . . . . . . . . .
Settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Decrease related to lapse of statute of limitations . . . . . . . . . . . . . . . . . . . .
$
Balance, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(90) $
(11)
2
—
1
—
(98) $
(173) $
(2)
6
(7)
84
2
(90) $
(240)
(28)
8
—
87
—
(173)
2009
2008
2007
We believe it is reasonably possible that a decrease of up to $1 million in unrecognized tax benefits
related primarily to state tax exposures could be recorded within the next 12 months as a result of settlements
with the tax authorities. We remain subject to various audits and reviews by state 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 U.S. Internal Revenue Service examination regardless of when the NOLs
occurred. Due to our significant NOLs, any adjustment to our federal returns would likely result in a reduction of
deferred tax assets rather than a cash payment of income taxes.
12. 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, are unresolved. To the extent that any of the reserved shares
remain undistributed upon resolution of the disputed claims, such shares will not be returned to us but rather will
be distributed pro rata to claimants with allowed claims to increase their recovery. Therefore, pursuant to our
Plan of Reorganization, all 485 million shares ultimately will be distributed. Accordingly, although the reserved
shares are not yet issued and outstanding, 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.
Reconciliations of the amounts used in the basic and diluted earnings (loss) per common share
computations for the years ended December 31, 2009, 2008 and 2007, are as follows (shares in thousands):
Diluted weighted average shares calculation:
Weighted average shares outstanding (basic)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Share-based awards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
485,659
660
485,054
492
479,235
243
Weighted average shares outstanding (diluted) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
486,319
485,546
479,478
2009
2008
2007
168
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
We excluded the following items from diluted earnings (loss) per common share for the years ended
December 31, 2009, 2008 and 2007 (shares in thousands):
2009
2008
2007
Share-based awards(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Common stock warrants(1)(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Convertible Senior Notes(3)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deutsche Bank AG London loaned shares(4)
13,158
7,259
— 29,158
—
—
17,315
—
— 399,914
— 17,401
(1) Excluded from diluted weighted average shares outstanding as these share-based awards are anti-dilutive in
accordance with the calculation under the treasury stock method prescribed by GAAP or because our
closing stock price had not reached the price at which the shares vest.
(2) Pursuant to our Plan of Reorganization, holders of allowed interests (primarily holders of our old common
stock canceled on the Effective Date) received a pro rata share of warrants to purchase approximately
48.5 million shares of our new, reorganized Calpine Corporation common stock at $23.88 per share.
Warrants for 21,499 shares of common stock were exercised prior to expiration. The remaining warrants
expired unexercised on August 25, 2008.
(3) Excluded from diluted weighted average shares outstanding as the conversion rights were terminated upon
our Chapter 11 filings.
(4) Excluded from basic and diluted weighted average shares outstanding as the share lending agreement with
Deutsche Bank AG London required physical settlement of these common shares.
Although earnings (loss) per share information for the years ended December 31, 2007, is presented, it is
not comparable to the information presented for the years ended December 31, 2009 and 2008, due to the
changes in our capital structure on the Effective Date, which also included termination of all outstanding
convertible securities.
13. Stock-Based Compensation
Calpine Equity Incentive Plans
The Calpine Equity Incentive Plans were approved as part of our Plan of Reorganization. These plans are
administered by the Compensation Committee of our Board of Directors and provide for the issuance of equity
awards to all employees as well as the non-employee members of our Board of Directors. The equity awards may
include incentive or non-qualified stock options, restricted stock, restricted stock units, stock appreciation rights,
performance compensation awards, and other stock-based awards. Under the MEIP and DEIP there are
14,833,000 shares and 167,000 shares, respectively, of our common stock available for issuance to participants.
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 of seven and ten years
and are subject to forfeiture provisions under certain circumstances, including termination of employment prior
to vesting. In addition, employment inducement options to purchase a total of 4,636,734 shares were granted
outside of the Calpine Equity Incentive Plans in connection with our hiring of a new Chief Executive Officer and
a new Chief Legal Officer in August 2008, and a new Chief Commercial Officer in September 2008. No grants
of options or shares of restricted stock were made outside of the Calpine Equity Incentive Plans during the year
169
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
ended December 31, 2009. Each of the employment inducement options vests over a period of five years,
contains a contractual term of seven years and is subject to forfeiture under certain circumstances, including
termination of employment prior to vesting.
We use the Black-Scholes option-pricing model 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.
Stock options granted to our retirement eligible employees are fully vested on the date of retirement and
therefore, compensation cost for those options is recognized on the date of grant. Restricted stock granted to our
retirement eligible employees are cancelled on the date of retirement. 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 (income) recognized was $38 million, $50 million and $(1) million
for the years ended December 31, 2009, 2008 and 2007, respectively. We did not record any 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,
2009, 2008 and 2007. At December 31, 2009, there was unrecognized compensation cost of $29 million related
to options, $11 million related to restricted stock and nil related to restricted stock units, which is expected to be
recognized over a weighted average period of 1.9 years for options, 1.7 years for restricted stock and 0.4 years
for restricted stock units. We issue new shares from our reserves set aside for the Calpine Equity Incentive Plans
and employment inducement options when stock options are exercised and for other stock-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, 2009, is as follows:
Number of
Options
Weighted
Average
Exercise Price
Outstanding — December 31, 2008 . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Exercised . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
12,840,754
929,651
$
$
— $
$
$
259,775
278,111
Outstanding — December 31, 2009 . . . . . . . . . . . . . . . . . .
13,232,519
Exercisable — December 31, 2009 . . . . . . . . . . . . . . . . . .
4,115,177
Vested and expected to vest — December 31, 2009 . . .
13,082,032
$
$
$
170
19.72
9.46
—
17.70
17.29
19.09
18.71
19.14
Weighted
Average
Remaining
Term
(in years)
Aggregate
Intrinsic Value
(in millions)
7.5
$
—
6.6
7.0
6.6
$
$
$
2
—
2
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
The total intrinsic value of our employee stock options exercised was nil for which we received
approximately $1 million in cash proceeds during the year ended December 31, 2007, and there were no
employee stock options exercised during the years ended December 31, 2009 and 2008.
The fair value of options granted during the years ended December 31, 2009 and 2008, was determined
on the grant date using the Black-Scholes pricing model. Certain assumptions were used in order to estimate fair
value for options as noted in the following table. No options were granted during the year ended December 31,
2007.
Expected term (in years)(1)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Risk-free interest rate(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Expected volatility(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividend yield(4)
. . . . . . . . . . . . . . . . . . . . . . . . .
Weighted average grant-date fair value (per option)
6.0 – 6.5
2.3 – 2.9%
5.0 – 6.1
1.0 – 3.3%
52.1 – 73.0% 34.8 – 98.0%
—
5.67
$
—
6.48
$
2009
2008
(1) Expected term calculated using the simplified method prescribed by the SEC.
(2) Zero Coupon U.S. Treasury rate or equivalent based on expected term.
(3) For the year ended December 31, 2009, we calculated volatility using the implied volatility of our exchange
traded stock options. For the year ended December 31, 2008, we calculated volatility using the weighted
average implied volatility of our industry peers’ exchange traded stock options.
(4) We are currently prohibited under our First Lien Credit Facility and certain of our other debt agreements
from paying any cash dividends on our common stock.
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, 2009, is as follows:
Nonvested — December 31, 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Number of
Restricted
Stock Awards
1,742,242
1,470,358
260,092
905,909
Nonvested — December 31, 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,046,599
Weighted
Average
Grant-Date
Fair Value
$
$
$
$
$
16.69
9.49
13.57
16.60
11.95
The total fair value of our restricted stock that vested during the years ended December 31, 2009 and
2008, was $8 million and $3 million, respectively, and no restricted stock or restricted stock units vested during
the year ended December 31, 2007.
171
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
14. Defined Contribution 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 $9 million, $10 million and $9 million for the
years ending December 31, 2009, 2008 and 2007, respectively.
Beginning January 1, 2008, the employer profit sharing contribution of 3% was eliminated and the
employer matching contribution was increased to 100% of the first 5% of compensation a participant defers for
the non-union plan. Beginning January 1, 2007, the employee deferral limits were increased from 60% to 75% of
compensation under both plans.
15. 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 we authorized the issuance of 485 million new shares of reorganized Calpine
Corporation common stock. As of December 31, 2009, approximately 440 million shares have been distributed to
holders of allowed unsecured claims and approximately 45 million shares remain in reserve for distribution to
holders of disputed claims whose claims ultimately become allowed. See Note 16 for further discussion of the
shares of reorganized Calpine Corporation common stock.
Our authorized common stock consists of 1.4 billion shares of Calpine Corporation common stock.
Common stock issued as of December 31, 2009 and 2008, was 443,325,827 shares and 429,025,057 shares,
respectively, at a par value of $0.001 per share. Common stock outstanding as of December 31, 2009 and 2008,
was 442,998,255 and 428,960,025, respectively.
The table below summarizes our common stock activity since our emergence from Chapter 11 on the
Effective Date. All shares of our common stock outstanding prior to the Effective Date were canceled and
common stock activity prior to the Effective Date is not presented below as it is no longer meaningful.
Shares
Issued
Shares
Held in
Treasury
Shares
Held in
Reserve
Inter-
Creditor
Disputes
Total
Implementation of our Plan of
Reorganization . . . . . . . . . . . . . . . . . . . . .
Resolution of claims . . . . . . . . . . . . . . . . . . .
Exercise of warrants . . . . . . . . . . . . . . . . . . .
Restricted stock, net of forfeitures . . . . . . . .
Vested restricted stock . . . . . . . . . . . . . . . . .
410,992,508
16,093,028
21,499
1,739,522
178,500
— 64,255,231
— (16,093,028)
—
—
—
—
—
(65,032)
9,752,261
—
—
—
485,000,000
—
21,499
1,739,522
113,468
Balance at December 31, 2008 . . . . . . . . . . .
429,025,057
(65,032)
48,162,203
9,752,261
486,874,489
Resolution of claims/inter-creditor
disputes . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restricted stock, net of forfeitures . . . . . . . .
Vested restricted stock . . . . . . . . . . . . . . . . .
13,167,420
230,161
903,189
— (3,415,159)
—
—
—
(262,540)
(9,752,261)
—
—
—
230,161
640,649
Balance at December 31, 2009 . . . . . . . . .
443,325,827
(327,572)
44,747,044
— 487,745,299
172
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
Treasury Stock
As of December 31, 2009 and 2008, we had treasury stock of 327,572 shares and 65,032 shares,
respectively, with a cost of $3 million and $1 million, respectively, which consists of our common stock withheld
to satisfy federal, state and local income tax withholding requirements for employee restricted stock awards that
vested in 2009 and 2008.
16. Our Emergence from Chapter 11
Summary of Proceedings
Summary of Proceedings and General Bankruptcy Matters — From the Petition Date through the
Effective Date, we operated as a debtor-in-possession under the protection of the U.S. Bankruptcy Court
following filings by Calpine Corporation and 274 of its wholly owned U.S. subsidiaries of voluntary petitions for
relief under Chapter 11 of the Bankruptcy Code. In addition, during that period, 12 of our Canadian subsidiaries
that had filed for creditor protection under the CCAA also operated as debtors-in-possession under the
jurisdiction of the Canadian Court.
During the pendency of our Chapter 11 cases through the Effective Date, pursuant to automatic stay
provisions under the Bankruptcy Code and orders granted by the Canadian Court, all actions to enforce or
otherwise effect repayment of liabilities preceding the Petition Date as well as all pending litigation against the
Calpine Debtors generally were stayed. Following the Effective Date, actions to enforce or otherwise effect
repayment of liabilities preceding the Petition Date, as well as pending litigation against the Calpine Debtors
related to such liabilities generally have been permanently enjoined. Any unresolved claims will continue to be
subject to the claims reconciliation process under the supervision of the U.S. Bankruptcy Court. However, certain
pending litigation related to pre-petition liabilities may proceed in courts other than the U.S. Bankruptcy Court to
the extent the parties to such litigation have obtained relief from the permanent injunction.
Plan of Reorganization — On June 20, 2007,
the U.S. Debtors filed the Debtors’ Joint Plan of
Reorganization and related Disclosure Statement, which were subsequently amended on each of August 27,
September 18, September 24, September 27 and December 13, 2007. On December 19, 2007, we filed the Sixth
Amended Joint Plan of Reorganization. As a result of the modifications to our Plan of Reorganization as well as
settlements reached by stipulation with certain creditors, all classes of creditors entitled to vote ultimately voted
to approve our Plan of Reorganization. Our Plan of Reorganization, established the total enterprise value of the
reorganized U.S. Debtors for purposes of our Plan of Reorganization at $18.95 billion and provided for the
amendment and restatement of our certificate of incorporation and the adoption of the Calpine Equity Incentive
Plans. Our Plan of Reorganization also provided for the treatment of claims against and interests in the U.S.
Debtors. Allowed administrative, tax and secured claims generally have been or are being paid in cash and cash
equivalents or, with respect to certain secured claims, had the collateral securing such claims returned to the
secured creditor. Allowed unsecured claims generally have been or are being paid with a distribution of common
stock. Pursuant to our Plan of Reorganization, 485 million shares of common stock were authorized to be issued
to settle such claims.
Through the filing of this Report, approximately 440 million shares have been distributed to holders of
allowed unsecured claims and approximately 45 million shares remain in reserve for distribution to holders of
disputed claims whose claims ultimately become allowed. We estimate that the number of shares reserved is
sufficient to satisfy the U.S. Debtors’ obligations under our Plan of Reorganization even if all disputed unsecured
173
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
claims ultimately become allowed. As disputed claims are resolved, the claimants receive distributions of shares
from the reserve on the same basis as if such distributions had been made on or about the Effective Date. To the
extent that any of the reserved shares remain undistributed upon resolution of the remaining disputed claims,
such shares will not be returned to us but rather will be distributed pro rata to claimants with allowed claims to
increase their recovery. We are not required to issue additional shares above the 485 million shares authorized to
settle unsecured claims, even if the shares remaining for distribution are not sufficient to fully pay all allowed
unsecured claims. Accordingly, resolution of these claims could have a material effect on creditor recoveries
under our Plan of Reorganization as the total number of shares of common stock that remain available for
distribution upon resolution of disputed claims is limited pursuant to our Plan of Reorganization. However,
certain disputed claims, including prepayment premium and default interest claims asserted by the holders of
CalGen Third Lien Debt, may be required to be settled with available cash and cash equivalents to the extent
reorganized Calpine Corporation common stock held in reserve pursuant to our Plan of Reorganization for such
claims is insufficient in value to satisfy such claims in full. To the extent that holders of the CalGen Third Lien
Debt have claims that remain unsettled or outstanding, they assert that they continue to have preferential lien
rights to the assets of Calpine Generating Company, LLC (a wholly owned indirect subsidiary of ours consisting
of 13 natural gas-fired power plants) that have priority over our other debt securing these assets. No assurances
can be given that settlements may not be materially higher or lower than confirmed in our Plan of Reorganization
or than we originally estimated.
Pursuant to our Plan of Reorganization, we were also authorized to issue up to 15 million shares under the
Calpine Equity Incentive Plans, and as of December 31, 2009, approximately 11.7 million share-based awards,
net of forfeitures, had been issued under the Calpine Equity Incentive Plans. Holders of allowed interests in
Calpine Corporation (primarily holders of Calpine Corporation common stock existing as of the Petition Date)
received a pro rata share of warrants to purchase approximately 48.5 million shares of reorganized Calpine
Corporation common stock at $23.88 per share. Warrants for 21,499 shares of common stock were exercised
prior to expiration. The remaining unexercised warrants expired on August 25, 2008. Proceeds received of
approximately $1 million from the exercise of the warrants were recorded as additional paid-in capital.
Our common stock is listed on the NYSE. Our common stock began “when issued” trading on the NYSE
under the symbol “CPN-WI” on January 16, 2008, and began “regular way” trading on the NYSE under the
symbol “CPN” on February 7, 2008. Our authorized equity consists of 1.5 billion shares comprising 1.4 billion
shares of common stock, par value $.001 per share, and 100 million shares of preferred stock which preferred
stock may be issued in one or more series, with such voting rights and other terms as our Board of Directors
determines.
In connection with the consummation of our Plan of Reorganization, we closed on our approximately
$7.3 billion of First Lien Facilities, comprising the approximately $4.9 billion of outstanding loan amounts and
commitments under the DIP Facility (including the $1.0 billion revolver), which were converted into exit
financing under our First Lien Credit Facility, approximately $2.1 billion of additional term loan facilities under
our First Lien Credit Facility and $300 million of term loans under the bridge facility. Amounts drawn under our
First Lien Facilities at closing were used to fund cash payment obligations under our Plan of Reorganization
including the repayment of a portion of the Second Priority Debt and the payment of administrative claims and
other pre-petition claims, as well as to pay fees and expenses in connection with our First Lien Facilities and for
working capital and general corporate purposes. The bridge facility was repaid in full on March 6, 2008, in
accordance with its terms.
In connection with our emergence from Chapter 11, we recorded certain “plan effect” adjustments to our
Consolidated Balance Sheet as of the Effective Date in order to reflect certain provisions of our Plan of
174
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
Reorganization. These adjustments included the distribution of approximately $4.1 billion in cash and the
authorized issuance of 485 million shares of reorganized Calpine Corporation common stock primarily for the
discharge of LSTC, repayment of the Second Priority Debt and for various other administrative and other post-
petition claims. As a result, our equity increased by approximately $8.9 billion. We borrowed approximately $6.4
billion under our First Lien Facilities, which was used to repay the outstanding term loan balance of $3.9 billion
(excluding the unused portion under the $1.0 billion revolver) under our DIP Facility. The remaining net
proceeds of approximately $2.5 billion were used to fund cash payment obligations under our Plan of
Reorganization including the repayment of a portion of the Second Priority Debt and the payment of
administrative claims.
CCAA Proceedings — Upon the application of the Canadian Debtors and other deconsolidated foreign
entities, on February 8, 2008, the Canadian Court ordered and declared that the unsecured notes issued by ULC I
were canceled and discharged on February 4, 2008; the Canadian Debtors had completed all distributions
previously ordered in full satisfaction of the pre-filing claims against them; the Canadian Debtors had otherwise
fully complied with all orders of the Canadian Court; and the proceedings under the CCAA were terminated,
including the stay of proceedings.
Applicability of Fresh Start Accounting
At the Effective Date, we did not meet the requirements under GAAP to adopt fresh start accounting
because the reorganization value of our assets exceeded the total of post-petition liabilities and allowed claims.
U.S. Debtors Condensed Combined Financial Statements
Basis of Presentation — The U.S. Debtors’ Condensed Combined Financial Statements exclude the
financial statements of our consolidated subsidiaries and affiliates that were not U.S. Debtors. Transactions and
balances of receivables and payables between U.S. Debtors were eliminated in consolidation.
Condensed combined financial statements of the U.S. Debtors are set forth below (in millions):
Condensed Combined Statement of Operations
For the Year Ended December 31, 2007
Total revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total cost of revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating (income) expense(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Income from operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other (income) expense, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reorganization items, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income before income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax benefit
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
2007
7,440
7,174
(39)
305
1,606
(118)
(3,240)
2,057
(346)
2,403
(1)
Includes equity in income (loss) of affiliates.
175
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
Condensed Combined Statement of Cash Flows
For the Year Ended December 31, 2007
Net cash provided by (used in):
Operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net increase in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net cash paid for reorganization items included in operating activities . . . . . . . . . . . . . . . . . . . . .
Net cash received from reorganization items included in investing activities . . . . . . . . . . . . . . . .
Net cash paid for reorganization items included in financing activities . . . . . . . . . . . . . . . . . . . . .
2007
(93)
504
404
815
883
1,698
126
(576)
74
$
$
$
$
$
Interest Expense — We recorded $135 million in post-petition interest from January 1, 2008, through the
Effective Date. As our Plan of Reorganization was confirmed on December 19, 2007, we recorded interest
expense in December 2007 for allowed claims under our Plan of Reorganization of $347 million related to post-
petition interest on LSTC incurred from the Petition Date through December 31, 2007. This amount represents
non-cash value to be satisfied through distributions of shares of Calpine Corporation’s reorganized common
stock. Prior to recording the post-petition interest on LSTC in December 2007, interest expense related to
pre-petition LSTC was reported only to the extent that it was paid during the pendency of our Chapter 11 cases or
was permitted by the Cash Collateral Order or other orders of the U.S. Bankruptcy Court. Contractual interest (at
non-default rates) owed to unrelated parties on pre-petition LSTC not reflected on our Consolidated Financial
Statements was $157 million for the year ended December 31, 2007. Additionally, we made periodic cash
adequate protection payments to the holders of Second Priority Debt; originally payments were made only
through June 30, 2006, but, by order entered December 28, 2006, the U.S. Bankruptcy Court modified the Cash
Collateral Order to provide for periodic adequate protection payments on a quarterly basis to the holders of the
Second Priority Debt through December 31, 2007. Upon confirmation of our Plan of Reorganization, the
obligations to the holders of the Second Priority Debt were fully satisfied. Therefore, we have reported the full
amount of the adequate protection payments as interest expense on our Consolidated Statements of Operations
together with the remaining contractual interest through December 31, 2007, on the Second Priority Debt.
Reorganization Items
Reorganization items represent the direct and incremental costs related to our Chapter 11 cases. These
include professional and trustee fees, pre-petition liability claim adjustments and losses that are probable and can
be estimated, net of interest income earned on accumulated cash during the Chapter 11 process and net of gains
on the sale of assets or resulting from certain settlement agreements related to our restructuring activities. We
expect to continue to pay professional and trustee fees related to our Chapter 11 cases through 2010 and
thereafter until the claims resolution process is completed and our Chapter 11 case is formally dismissed by the
U.S. Bankruptcy Court; however, we do not expect such fees to be material in the future and do not anticipate
that we will separately report future fees as reorganization items on our Consolidated Statements of Operations
beginning in 2010.
176
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
The table below lists the significant components of
reorganization items for
the years ended
December 31, 2009, 2008 and 2007 (in millions):
Provision for expected allowed claims . . . . . . . . . . . . . . . . . . . . . . . . . . .
Professional and trustee fees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gains on asset sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset impairments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain on reconsolidation of Canadian Debtors and other deconsolidated
foreign entities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
DIP Facility and First Lien Facilities financing and CalGen Secured
Debt repayment costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest (income) on accumulated cash . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2009
2008
2007
$
(2) $
1
—
—
(95) $
85
(206)
—
(3,687)
217
(285)
120
—
—
—
—
(71)
(4)
(7)
(4)
—
202
(59)
234
Total reorganization items . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(1) $
(302) $
(3,258)
Provision for Expected Allowed Claims — Represents the change in our estimate of the expected allowed
claims. During the year ended December 31, 2008, our provision for expected allowed claims consisted primarily
of a $62 million credit related to the settlement of claims with the Canadian Debtors and other deconsolidated
foreign entities, a $12 million credit related to our settlement with Rosetta and a $34 million credit for RockGen
from a prior period which we determined was not material to any period. During the year ended December 31,
2007, our provision for expected allowed claims consisted primarily of a credit of $4.1 billion resulting from the
Canadian Settlement Agreement.
Gains on Asset Sales — Represents gains on the sales of the Hillabee and Fremont development project
assets for the year ended December 31, 2008. See Note 6 for further discussion of our sales of Hillabee and
Fremont. The sales of these assets and utilization of the sales proceeds to repay our $300 million bridge facility
were part of our Plan of Reorganization and are included in reorganization items even though the sales closed
subsequent to the Effective Date. The amounts recorded for the year ended December 31, 2007, primarily
represent the gains recorded on the sales of the assets of Aries Power Plant, Goldendale Energy Center and PSM.
Asset Impairments — Impairment charges for the year ended December 31, 2007, primarily relate to
recording our interest in Acadia PP at fair value less costs to sell.
Other — Other reorganization items consist primarily of adjustments for foreign exchange rate changes
on LSTC denominated in a foreign currency and governed by foreign law, employee severance and emergence
incentive costs during the year ended December 31, 2007.
17. Commitments and Contingencies
Long-Term Service Agreements
As of December 31, 2009, the total estimated commitments for LTSAs associated with turbines installed
or in storage were approximately $84 million. These commitments are payable over the terms of the respective
agreements, which range from 1 to 7 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
177
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
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. We had no LTSA cancellation charges for the
years ended December 31, 2009, 2008 and 2007.
Power Plant Operating Leases
We have entered into certain long-term operating leases for power plants, extending through 2049,
including renewal options. Some of the lease agreements provide for renewal options at fair value, and some of
the agreements contain customary restrictions on dividends, 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. Future minimum lease payments
under these leases are as follows (in millions):
Initial
Year
2010
2011
2012
2013
2014
Thereafter
Total
Watsonville . . . . . . . . 1995 $
Greenleaf . . . . . . . . . . 1998
KIAC . . . . . . . . . . . . . 2000
. . . . . . . . 2001
South Point
Total
. . . . . . . . . . .
$
1 $
7
25
10
43 $
— $
7
25
67
99 $
— $
7
24
5
36 $
— $
7
24
5
36 $
— $
3
24
5
32 $
— $
—
119
216
335 $
1
31
241
308
581
During the years ended December 31, 2009, 2008 and 2007, rent expense for power plant operating leases
amounted to $47 million, $46 million and $54 million, respectively. As of December 31, 2009, we guarantee
$308 million of the total future minimum lease payments of our consolidated subsidiaries.
Production Royalties and Leases
We are committed 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 natural gas-fired and geothermal power plants for the years ended December 31,
2009, 2008 and 2007, were $22 million, $33 million and $27 million, respectively.
178
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
Office and Equipment Leases
We lease our corporate, regional and satellite offices, as well as some of our office equipment, under
noncancellable operating leases extending through 2014. Future minimum lease payments under these leases are
as follows (in millions):
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter
$
Total
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
15
13
12
11
1
—
52
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, 2009, 2008 and 2007, rent expense for
noncancellable operating leases was $12 million, $14 million and $10 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 cogeneration projects. The majority of our purchases are made in the spot market or under
index-priced contracts. At December 31, 2009, we had future commitments of approximately $4.7 billion of
notional volume for natural gas purchases under contracts with terms from 1 to 16 years, and one contract with a
term of 31 years.
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.
At December 31, 2009, 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
2010
2011
2012
2013
2014
Thereafter
Total
Guarantee of subsidiary debt(1) . . . . $
Standby letters of credit(2)(4)
Surety bonds(3)(4)(5)
Guarantee of subsidiary operating
. . . . . .
. . . . . . . . . . . . .
lease payments(4) . . . . . . . . . . . . .
Total
. . . . . . . . . . . . . . . . . . . . . . $
73 $
384
—
10
467 $
72 $
28
—
67
167 $
70 $
—
—
5
75 $
66 $
—
—
5
71 $
54 $
—
—
5
59 $
647 $
—
4
982
412
4
216
867 $
308
1,706
(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.
179
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
(2) The standby letters of credit disclosed above represent those disclosed in Note 7.
(3) The majority of surety bonds do not have expiration or cancellation dates.
(4) These are off balance sheet obligations.
(5) As of December 31, 2009, $4 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 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.
In connection with our purchase and sale agreements, we have frequently provided for indemnification by
each of the purchaser and the seller, and/or their respective parent, 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.
Additionally, we and our subsidiaries from time to time assume other indemnification obligations in
conjunction with transactions other than purchase or sale transactions. These indemnification obligations
generally have a discrete term and are intended to protect our counterparties against risks that are difficult to
predict or impossible to quantify at the time of the consummation of a particular transaction, such as the costs
associated with litigation that may result from the transaction.
Litigation
We are party to various litigation matters, including regulatory and administrative proceedings arising out
of the normal course of business, the more significant of which are summarized below. The ultimate outcome of
each of these matters cannot presently be determined, nor can the liability that could potentially result from a
negative outcome be reasonably estimated presently for every case. The liability we may ultimately incur with
respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently
accrued with respect to such matters and, as a result of these matters, may potentially be material to our financial
position or results of operations. We review our litigation activities and determine if an unfavorable outcome to
us is considered “remote,” “reasonably possible” or “probable” as defined by GAAP. Where we have determined
an unfavorable outcome is probable and is reasonably estimable, we have accrued for potential litigation losses.
During the pendency of our Chapter 11 cases through the Effective Date, pursuant to automatic stay provisions
under the Bankruptcy Code and orders granted by the Canadian Court, all actions to enforce or otherwise effect
repayment of liabilities preceding the Petition Date, as well as all pending litigation against the Calpine Debtors,
generally were stayed. Following the Effective Date, pending actions to enforce or otherwise effect repayment of
180
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
liabilities preceding the Petition Date, as well as pending litigation against the U.S. Debtors related to such
liabilities, generally have been permanently enjoined. Any unresolved claims will continue to be subject to the
claims reconciliation process under the supervision of the U.S. Bankruptcy Court. However, certain pending
litigation related to pre-petition liabilities may proceed in courts other than the U.S. Bankruptcy Court to the
extent the parties to such litigation have obtained relief from the permanent injunction. In particular, certain
pending actions against us are anticipated to proceed as described below. See Note 16 for information regarding
our emergence from our Chapter 11 and our CCAA proceedings. In addition to the Chapter 11 cases and CCAA
proceedings (in connection with which certain of the matters described below arose), and the other matters
described below, we are involved in various other claims and legal actions,
including regulatory and
administrative proceedings arising out of the normal course of our business. We do not expect that the outcome
of such other claims and legal actions will have a material adverse effect on our financial position or results of
operations.
Hawaii Structural Ironworkers Pension Fund v. Calpine, et al. — This case was filed in San Diego
County Superior Court on March 11, 2003, and later transferred, on a defense motion, to Santa Clara County
Superior Court. Defendants in this case are Calpine Corporation, Peter Cartwright, Ann B. Curtis, John Wilson,
Kenneth Derr, George Stathakis, Credit Suisse First Boston LLC, Banc of America Securities LLC, Deutsche
Bank Securities, Inc. and Goldman Sachs & Co. The Hawaii Structural Ironworkers Pension Trust Fund alleges
that the prospectus and registration statement for an April 2002 offering of Calpine Corporation securities
contained false or misleading statements. The action was temporarily stayed during Calpine Corporation’s
Chapter 11 filings.
On December 19, 2007, Calpine Corporation entered into an agreement with the Hawaii Structural
Ironworkers Pension Trust Fund to allow the action to proceed to the extent there was insurance coverage
available to Calpine Corporation.
The parties attended mediation on June 1, 2009, and settlement discussions continued thereafter. On
October 12, 2009, the parties executed a Stipulation of Settlement, which settled the matter for $43 million
contingent upon court approval. Pursuant to the December 19, 2007 agreement, Calpine Corporation’s portion of
the settlement is to be satisfied solely from applicable insurance coverage and will not require cash payment from
Calpine. Preliminary approval of the class action settlement was granted by Santa Clara Superior Court on
October 26, 2009, and final approval was ordered by the Santa Clara Superior Court on February 3, 2010. We
now consider this matter closed.
Pit River Tribe, et al. v. Bureau of Land Management, et al. — On June 17, 2002, the Pit River Tribe filed
suit against the BLM and other federal agencies in the U.S. District Court for the Eastern District of California
seeking to enjoin further exploration, construction and development of the Calpine Fourmile Hill Project in the
Glass Mountain and Medicine Lake geothermal areas. The complaint challenged the validity of the decisions of
the BLM and the U.S. Forest Service to permit the development of the proposed project under two geothermal
mineral leases previously issued by the BLM. The lawsuit also sought to invalidate the leases. Only declaratory
and equitable relief was sought.
The case was temporarily stayed during our Chapter 11 case; however, we and the Pit River Tribe filed a
stipulation to lift the automatic stay. On November 5, 2006, the U.S. Court of Appeals for the Ninth Circuit issued a
decision granting the plaintiffs relief by holding that the BLM had not complied with the National Environmental
Policy Act, and other procedural requirements and, therefore, held that the lease extensions were invalid. The U.S.
Court of Appeals for the Ninth Circuit remanded the matter back to the U.S. District Court to implement its decision.
181
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
On December 22, 2008, the U.S. District Court ruled that the lease extension for the two Fourmile Hill leases and the
approval to construct a proposed 49.9 MW Fourmile Hill power plant should be remanded to the federal agencies for
curative action. The Pit River Tribe timely appealed the Court’s December 22, 2008 order. Briefing of the appeal is
complete and we were granted our motion for an expedited hearing. The U.S. Court of Appeals for the Ninth Circuit
hearing on the merits of the Pit River Tribe’s appeal is scheduled to be heard on March 10, 2010.
Appeal of Confirmation Order — Several parties filed appeals in the U.S. District Court for the Southern
District of New York seeking reconsideration of the Confirmation Order of the U.S. Bankruptcy Court, despite the
effectiveness of our Plan of Reorganization. On June 6, 2008, the U.S. District Court for the Southern District of
New York entered an order denying the appeals, finding that all of the appeals were equitably moot. One of the
shareholders (Mr. Felluss) filed a motion for reconsideration, which was denied on June 24, 2008. On July 3, 2008,
Mr. Felluss filed a notice of appeal with the Second Circuit. In addition, on August 8, 2008, Mr. Felluss filed a
motion with the Second Circuit seeking to stay the expiration of the warrants that had been issued pursuant to our
Plan of Reorganization and were scheduled to expire August 25, 2008; the Second Circuit denied that motion on
August 27, 2008. Mr. Felluss’ appeal was heard by the Second Circuit on November 10, 2009, and denied by
Summary Order on November 25, 2009. On December 25, 2009, Mr. Felluss filed a petition for rehearing with the
Second Circuit. On January 11, 2010, the Second Circuit denied the petition. Unless Mr. Felluss files a petition for
review with the U.S. Supreme Court in the next 90 days, we will consider this matter closed.
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 normal
operation of our power plants. We do not, however, 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. A summary of our larger environmental matters are as follows:
Texas City and Clear Lake Environmental Matters — As part of an internal review of our Texas City and
Clear Lake power plants, we determined that these power plants were in violation of the requirements of the Acid
Rain Program found in Title 40 of the U.S. Federal Code of Regulations, Parts 72-78. We self-reported the
excess emissions to the Texas Commission on Environmental Quality, or TCEQ, and the EPA, and paid the
appropriate fees. Compliance agreements between each power plant and the TCEQ were executed on
September 26, 2008, and limit enforcement by the TCEQ. The EPA does have authority and discretion to issue
substantial fines that could be material; however, based on the circumstances and on consideration of recent
cases addressed by the agencies involved, we do not believe that the maximum penalty will be assessed or that
penalties, if any, resulting from these matters will have a material adverse effect on our business, financial
condition or results of operations.
San Diego Air Pollution Control District — The San Diego Air Pollution Control District issued OMEC a
notice of violation on August 28, 2009, for failing to install an auxiliary boiler required by the permit issued by
the San Diego Air Pollution Control District. OMEC entered into a compliance agreement on September 18,
2009, under which it paid the San Diego Air Pollution Control District a civil penalty, made a contribution to the
San Diego Air Pollution Control District’s Air Quality Improvement Trust Fund, and agreed to install an
auxiliary boiler by November 30, 2009 and to install control system software to reduce emissions occurring
during gas turbine startup. As of December 31, 2009, we have satisfied all of the terms of the compliance
agreement and consider this matter closed.
182
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
Other Contingencies
Lyondell Bankruptcy — On January 6, 2009, Lyondell Chemical Co. and certain of its subsidiaries,
including Houston Refining LP, filed for protection under Chapter 11 in the U.S. Bankruptcy Court. Channel
Energy Center, a 608 MW natural gas-fired cogeneration power plant located in Houston, Texas, leases its
project site from Houston Refining LP and is granted certain easements in, over, under and on the site pursuant to
the lease. Channel Energy Center provides power and steam to Houston Refining LP pursuant to a power
services agreement and, pursuant to a power plant services agreement, provides clarified water and treated water
to Houston Refining LP. Channel Energy Center is provided with raw water, refinery gas and certain other power
plant services by Houston Refining LP.
The Lyondell debtors may exercise their right under the Bankruptcy Code to reject the lease, the power
services agreement and/or the power plant services agreement. The potential damages to us if any or all of these
agreements are rejected are uncertain and would represent an unsecured bankruptcy claim with Lyondell. To the
extent that any such damages would be recoverable under the laws of the State of Texas, the governing law under
the agreements, they would be treated as an unsecured claim against the Lyondell debtors in bankruptcy. The
percentage of recovery on unsecured claims in the Lyondell bankruptcy is unknown at this time, but is expected
to be low.
We continue to monitor this matter closely and will seek vigorously to protect our rights under our
various agreements with the Lyondell debtors.
18. Segment and Significant Customer Information
We are an independent wholesale power company. We own and operate natural gas-fired and geothermal
power plants in North America and have a significant presence in the major competitive power markets in the
U.S., including California and Texas. 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, Southeast and North (including Canada). We continue to evaluate the optimal manner in
which we assess our performance including our segments and future changes may result.
Commodity Margin includes our power and steam revenues, sales of purchased power and natural gas,
capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and expenses, fuel
and purchased energy expense, RGGI compliance costs, and cash settlements from our marketing, hedging and
optimization activities that are included in mark-to-market activity, but excludes the unrealized portion of our
mark-to-market activity and other revenue. Commodity Margin is a key operational measure reviewed by our
chief operating decision maker to assess the performance of our segments.
183
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
During the first quarter of 2009, we began assessing the performance of our regional segments to include
the allocation (based upon each regional segment’s MWh) of revenues and expenses from our fuel management,
Turbine Maintenance Group and certain non-region specific natural gas marketing and optimization and other
corporate activities, which had formerly been separately reported as our “Other” segment. Additionally, we have
modified our definition of Commodity Margin to include cash settlements from our marketing, hedging and
optimization activities that were previously included in mark-to-market activity. Our 2008 and 2007 segment
information has been reclassified to conform to the current year presentation. Financial data for our segments
were as follows (in millions):
Year Ended December 31, 2009
West
Texas
Southeast
North
Consolidation
and
Elimination
Total
Revenues from external
customers . . . . . . . . . . . . . . .
Intersegment revenues . . . . . . .
Total operating revenues . . .
Commodity Margin . . . . . . . . .
Add: Mark-to-market
commodity activity, net and
. . . . . . . . . .
other revenue(1)
Less:
Plant operating expense . . . . . .
Depreciation and amortization
expense . . . . . . . . . . . . . . . .
Other cost of revenue(2) . . . . . .
Gross profit . . . . . . . . . . . . .
Other operating expenses . . . .
Income from operations . . .
Interest expense, net of interest
income . . . . . . . . . . . . . . . . .
Debt extinguishment costs and
other (income) expense,
net
. . . . . . . . . . . . . . . . . . . .
Income before
reorganization items and
income taxes . . . . . . . . . .
Reorganization items . . . . . . . .
Income before income
taxes . . . . . . . . . . . . . . . . .
$
$
$
3,412
28
3,440
1,346
$
$
$
1,816
63
1,879
644
$
$
$
778
97
875
304
$
$
$
143
437
205
62
785
53
732
(40)
232
125
13
234
68
166
(5)
134
79
10
76
29
47
558
16
574
268
46
91
66
30
127
1
126
$
$
$
— $
(204)
(204) $
— $
(44)
3
(8)
(32)
(7)
—
(7)
6,564
—
6,564
2,562
100
897
467
83
1,215
151
1,064
813
92
159
(1)
$
160
184
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
Year Ended December 31, 2008
West
Texas
Southeast
North
Consolidation
and
Elimination
Total
Revenues from external
customers . . . . . . . . . . . . .
Intersegment revenues . . . . .
Total operating
revenues . . . . . . . . . . . .
Commodity Margin . . . . . . .
Add: Mark-to-market
commodity activity, net
and other revenue(1) . . . . .
Less:
Plant operating expense . . . .
Depreciation and
amortization expense . . . .
Other cost of revenue(2) . . . .
Gross profit . . . . . . . . . . .
Other operating expenses . .
Income (loss) from
operations . . . . . . . . . .
Interest expense, net of
interest income . . . . . . . .
Debt extinguishment costs
and other (income)
expense, net . . . . . . . . . . .
Loss before
reorganization items,
income taxes and
discontinued
operations . . . . . . . . . .
Reorganization items . . . . . .
Loss before income taxes
and discontinued
operations . . . . . . . . . .
$
$
$
4,243
49
4,292
1,255
$
$
$
3,806
252
4,058
726
$
$
$
1,245
229
1,474
264
$
$
$
643
25
668
279
$
$
$
— $
(555)
(555) $
— $
(31)
434
190
71
529
155
374
195
267
124
12
518
91
427
36
128
69
59
44
212
(168)
(40)
108
56
26
49
12
37
(28)
(19)
(6)
(21)
18
—
18
9,937
—
9,937
2,524
132
918
433
147
1,158
470
688
1,024
27
(363)
(302)
$
(61)
185
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
Revenues from external
customers . . . . . . . . . . . . .
Intersegment revenues . . . . .
Total operating
revenues . . . . . . . . . . . .
Commodity Margin . . . . . . .
Add: Mark-to-market
commodity activity, net
and other revenue(1)
. . . . .
Less:
Plant operating expense . . . .
Depreciation and
amortization expense . . . .
. . . .
Other cost of revenue(2)
Gross profit . . . . . . . . . . . .
Other operating expenses . . .
Income (loss) from
operations . . . . . . . . . . .
Interest expense, net of
interest income . . . . . . . . .
Debt extinguishment costs
and other (income)
expense, net
. . . . . . . . . . .
Loss before reorganization
items and income
taxes . . . . . . . . . . . . . . .
Reorganization items . . . . . .
Income before income
taxes . . . . . . . . . . . . . . .
Year Ended December 31, 2007
West
Texas
Southeast
North
Consolidation
and
Elimination
Total
$
$
$
3,649
50
3,699
1,172
$
$
$
2,665
15
2,680
505
$
$
$
1,036
144
1,180
256
$
$
$
620
12
632
278
$
$
$
— $
(221)
(221) $
— $
7,970
—
7,970
2,211
51
346
209
68
600
93
507
57
193
123
9
237
62
175
14
133
79
35
23
35
(12)
2
88
55
69
68
30
38
(48)
(11)
(3)
(1)
(33)
(30)
(3)
76
749
463
180
895
190
705
1,955
(139)
(1,111)
(3,258)
$
2,147
(1) Mark-to-market commodity activity represents the unrealized portion of our mark-to-market activity, net, as
well as a non-cash gain from amortization of prepaid power sales agreements included in operating revenues
and fuel and purchased energy expense on our Consolidated Statements of Operations.
(2) Excludes $5 million of RGGI compliance costs for the year ended December 31, 2009, and nil for the years
ended December 31, 2008 and 2007, respectively, which were included as a component of Commodity
Margin, and includes operating asset impairments of $4 million, $33 million and $44 million for the years
ended December 31, 2009, 2008 and 2007, respectively.
186
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009, 2008 and 2007
Significant Customer
We did not have a customer that accounted for more than 10% of our annual consolidated revenues for
the years ended December 31, 2009 and 2008. For the year ended December 31, 2007, we had one significant
customer that accounted for more than 10% of our annual consolidated revenues: CDWR. CDWR revenues were
$1.1 billion for the year ended December 31, 2007. Our receivables from CDWR were $95 million as of
December 31, 2007. CDWR revenues were attributable to our West segment.
19. 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, 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)
2009
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income from operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) attributable to Calpine . . . . . . . . . . . . . . . . . .
Basic earnings (loss) per common share:
Net income (loss) attributable to Calpine . . . . . . . . . . . . . . . .
Diluted earnings (loss) per common share:
Net income (loss) attributable to Calpine . . . . . . . . . . . . . . . .
2008
Operating revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross profit (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) from operations(1) . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) before discontinued operations attributable to
Calpine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Discontinued operations, net of tax . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) attributable to Calpine . . . . . . . . . . . . . . . . . .
Basic earnings (loss) per common share:
Income (loss) before discontinued operations . . . . . . . . . . . . .
Discontinued operations, net of tax, attributable to
Calpine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) attributable to Calpine . . . . . . . . . . . . . . . .
Diluted earnings (loss) per common share:
Income (loss) before discontinued operations attributable to
Calpine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Discontinued operations, net of tax, attributable to
Calpine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) attributable to Calpine . . . . . . . . . . . . . . . .
$
$
$
$
$
$
$
$
$
$
1,569
234
201
(43)
(0.09)
(0.09)
1,968
177
65
(132)
23
(109)
(0.27)
0.05
(0.22)
(0.27)
0.05
(0.22)
$
$
$
$
$
$
$
$
$
$
1,847
493
437
238
0.49
0.49
3,190
534
272
136
—
136
0.28
—
0.28
$
$
$
$
$
$
$
$
$
1,471
206
175
(78) $
(0.16) $
(0.16) $
2,828
476
433
197
—
197
0.41
—
0.41
$
$
$
$
1,677
282
251
32
0.07
0.07
1,951
(29)
(82)
(214)
—
(214)
(0.44)
—
(0.44)
0.28
$
0.41
$
(0.44)
—
0.28
$
—
0.41
$
—
(0.44)
(1) As a result of the anticipated sale of Auburndale during 2008, we recorded an impairment
loss of
approximately $180 million, which is included in income from operations on our 2008 Consolidated
Statements of Operations. See Notes 4 and 6 for more information.
187
CALPINE CORPORATION AND SUBSIDIARIES
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS
Description
Balance at
Beginning
of Year
Charged to
Expense
Charged to
AOCI
Reductions(1)
Other(2)
Balance at
End of Year
(in millions)
$
$
Year ended December 31, 2009
Allowance for doubtful accounts . . . .
Deferred tax asset valuation
allowance . . . . . . . . . . . . . . . . . . . .
Year ended December 31, 2008
Allowance for doubtful accounts . . . .
Allowance for doubtful accounts with
related party Canadian Debtors and
other deconsolidated foreign
entities . . . . . . . . . . . . . . . . . . . . . .
Reserve for notes receivable . . . . . . .
Reserve for interest and notes
receivable with related party
Canadian Debtors and other
deconsolidated foreign entities . . .
Deferred tax asset valuation
Allowance for doubtful accounts . . . .
Allowance for doubtful accounts with
related party Canadian Debtors and
other deconsolidated foreign
entities . . . . . . . . . . . . . . . . . . . . . .
Reserve for notes receivable . . . . . . .
Reserve for interest and notes
receivable with related party
Canadian Debtors and other
deconsolidated foreign entities . . .
Gross reserve for California refund
liability . . . . . . . . . . . . . . . . . . . . . .
Deferred tax asset valuation
42
$
2
$
— $
(30)
$
— $
14
2,685
(113)
—
—
—
2,572
54
$
15
$
— $
(27) $
— $
42
10
39
83
—
—
—
—
—
—
—
(10)
(39)
(83)
—
—
—
—
478
—
—
—
2,685
$
32
$
52
$
— $
(30) $
— $
54
71
36
227
13
3
3
—
—
—
—
—
—
—
(64)
—
(144)
(13)
(485)
—
—
—
—
—
10
39
83
—
2,401
allowance . . . . . . . . . . . . . . . . . . . .
2,401
(194)
Year ended December 31, 2007
allowance . . . . . . . . . . . . . . . . . . . .
2,321
565
(1) Represents write-offs of accounts considered to be uncollectible and recoveries of amounts previously
written off or reserved.
(2) The adjustment of $478 million represents the additions resulting from our reconsolidation of our Canadian
Debtors and other deconsolidated foreign entities and the difference in the amounts disclosed in our prior
10-K and the final amount as filed in our 2007 tax return. There was no impact to our Statement of
Operations for the year ended December 31, 2008.
188
OTAY MESA ENERGY CENTER, LLC
INDEX TO FINANCIAL STATEMENTS
December 31, 2009
Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Balance Sheets at December 31, 2009 and 2008 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Statements of Operations for the Years Ended December 31, 2009 and 2008, and the Period May 1, 2007
Page
190
191
to December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
192
Statements of Comprehensive Income (Loss) and Member’s Interest for the Years Ended December 31,
2009 and 2008, and the Period May 1, 2007 to December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
193
Statements of Cash Flows for the Years Ended December 31, 2009 and 2008, and the Period May 1, 2007
to December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
194
Notes to Financial Statements for the Years Ended December 31, 2009 and 2008, and the Period May 1,
2007 to December 31, 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
195
189
Report of Independent Registered Public Accounting Firm
To the Member of
Otay Mesa Energy Center, LLC
In our opinion, the accompanying balance sheets and the related statements of operations, comprehensive income
(loss) and member’s interest, and cash flows present fairly, in all material respects, the financial position of Otay
Mesa Energy Center, LLC at December 31, 2009 and 2008, and the results of its operations and its cash flows for
each of the two years in the period ended December 31, 2009 and for the period from May 1, 2007 (date of
inception) to December 31, 2007 in conformity with accounting principles generally accepted in the United
States of America. These financial statements are the responsibility of the Company’s management. Our
responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits
of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether
the financial statements are free of material misstatement. An audit includes 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. We
believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 24, 2010
190
OTAY MESA ENERGY CENTER, LLC
(Previously a Development Stage Company)
BALANCE SHEETS
December 31, 2009 and 2008
Current assets:
ASSETS
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Restricted cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts receivable, related party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred income taxes, current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Materials and supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid expenses and other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred transmission credits, related party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property, plant and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intangible assets, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred financing costs, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred lease levelization receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2009
2008
(in thousands)
$
7,509
7,672
10,578
387
1,410
235
—
27,791
542,002
43,430
7,047
2,047
11,486
70
—
513
—
433
22,661
35,163
462,713
46,119
7,776
—
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
622,317
$
551,771
Current liabilities:
LIABILITIES & MEMBER’S INTEREST
Accounts payable, trade . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts payable, related party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative liabilities, current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Project financing, current
Accrued interest payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax payable, related party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Project financing, net of current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Written call option . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term derivative liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred income taxes, net of current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Commitments and contingencies (see Note 11)
Member’s interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
1,975
4,479
16,744
9,949
4,314
82
28
37,571
364,564
46,119
25,893
387
786
998
476,318
28,716
4,733
12,322
2,487
951
1,759
28
50,996
253,870
46,119
72,251
513
612
627
424,988
145,999
126,783
Total liabilities and member’s interest
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
622,317
$
551,771
The accompanying notes are an integral part of these Financial Statements.
191
OTAY MESA ENERGY CENTER, LLC
(Previously a Development Stage Company)
STATEMENTS OF OPERATIONS
For the Years Ended December 31, 2009 and 2008,
and the Period May 1, 2007 to December 31, 2007
2009
2008
2007
$
20,398
(in thousands)
$
— $
Operating revenues, related party . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost of revenue:
Plant operating expense, related party . . . . . . . . . . . . . . . . . . . . .
Plant operating expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization expense . . . . . . . . . . . . . . . . . . . .
Project development expense . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sales, general and other administrative expense . . . . . . . . . . . . .
Asset impairment expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion of asset retirement obligations . . . . . . . . . . . . . . . . . . .
Total cost of revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) from operations . . . . . . . . . . . . . . . . . . . . . . .
Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest (income)
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liquidating damages . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) before income taxes . . . . . . . . . . . . . . . . . . . .
Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,454
387
5,097
2,949
3,674
1,647
72
16,280
4,118
(23,120)
(658)
6,050
195
21,651
—
—
—
—
507
436
—
53
996
(996)
52,934
(1,706)
—
—
(52,224)
28
—
—
—
—
—
99
—
5
104
(104)
8,562
(382)
—
—
(8,284)
—
(8,284)
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
21,651
$
(52,252) $
The accompanying notes are an integral part of these Financial Statements.
192
OTAY MESA ENERGY CENTER, LLC
(Previously a Development Stage Company)
STATEMENTS OF COMPREHENSIVE INCOME (LOSS) AND
MEMBER’S INTEREST
For the Years Ended December 31, 2009 and 2008,
and the Period May 1, 2007 to December 31, 2007
Contributions from member on
May 1, 2007 . . . . . . . . . . . . . . . $
Contributions from member . . .
Comprehensive loss from
interest rate swaps . . . . . . . .
Net loss . . . . . . . . . . . . . . . . . . .
Total comprehensive loss . . .
Balance, December 31, 2007 . . .
Contributions from member . . .
Comprehensive loss from
interest rate swaps . . . . . . . .
Net loss . . . . . . . . . . . . . . . . . . .
Total comprehensive loss . . .
Balance, December 31, 2008 . . .
Contributions from member . . .
Distributions to member . . . . . .
Comprehensive gain from
interest rate swaps . . . . . . . .
Reclassification adjustment for
losses included in net
income . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . .
Total comprehensive
income . . . . . . . . . . . . . . .
Member’s
Interest
Accumulated
Deficit
Accumulated
Other
Comprehensive
Income (Loss)
(in thousands)
Total Member’s
Interest
Comprehensive
Income
(Loss)
203,360 $
331
— $
—
— $
—
203,360
331
—
—
—
(8,284)
(9,696)
—
(9,696) $
(8,284)
(9,696)
(8,284)
203,691
10,336
—
—
214,027
4,250
(9,130)
—
—
—
(8,284)
—
—
(52,252)
(60,536)
—
—
(9,696)
—
(17,012)
—
(26,708)
—
—
$
(17,980)
185,711
10,336
(17,012) $
(52,252)
(17,012)
(52,252)
$
(69,264)
126,783
4,250
(9,130)
—
334
334 $
334
—
21,651
2,111
—
2,111
21,651
2,111
21,651
$
24,096
Balance, December 31, 2009 . . . $
209,147 $
(38,885) $
(24,263) $
145,999
The accompanying notes are an integral part of these Financial Statements.
193
OTAY MESA ENERGY CENTER, LLC
(Previously a Development Stage Company)
STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2009 and 2008,
and the Period May 1, 2007 to December 31, 2007
2009
2008
2007
(in thousands)
21,651 $
(52,252) $
(8,284)
Cash flows from operating activities:
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Net income (loss)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of intangible assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Asset impairment expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accretion of asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrealized mark-to-market activities, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Lease levelization expense (revenue), net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in deferred transmission expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in operating assets and liabilities:
Prepaid expense and other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts receivable, related party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred transmission credits, related party . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts payable, related party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Materials and supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued interest payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts payable, trade . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax payable, related party . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net cash used in operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4,055
1,042
1,647
226
72
(39,492)
(1,676)
—
(235)
(10,578)
3,795
3,572
(1,410)
3,439
(5)
884
—
(13,013)
Cash flows from investing activities:
Purchases of property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase in restricted cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transmission credit proceeds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Transmission credit expenditures, related party . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(115,127)
(7,602)
19,045
(226)
—
—
—
—
53
49,644
—
(1,630)
—
—
—
—
—
518
—
18
28
(3,621)
(179,594)
(70)
—
(9,313)
—
—
—
—
5
8,561
—
—
(1,390)
—
—
—
—
—
—
—
95
(1,013)
(97,296)
—
—
(3,091)
Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(103,910)
(188,977)
(100,387)
Cash flows from financing activities:
Borrowings under project financing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Repayment of project financing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distributions to member . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Contributions from member . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
120,643
(2,487)
(9,130)
4,250
(330)
193,157
—
—
10,336
(495)
63,200
—
—
46,980
(7,694)
Net cash provided by financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
112,946
202,998
102,486
Net (decrease) increase in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(3,977)
11,486
10,400
1,086
Cash and cash equivalents, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
7,509 $
11,486 $
1,086
—
1,086
Cash paid during the period for:
Interest, net of amounts capitalized . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
12,727 $
— $
2,771 $
— $
—
—
Supplemental disclosure of non-cash investing and financing activities:
Change in property, plant and equipment financed by accounts payable and other
liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (33,097) $
15,376 $
17,308
Amortization of deferred financing costs capitalized to property, plant and
equipment
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Additions to property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Contributions of assets and liabilities from member . . . . . . . . . . . . . . . . . . . . . . . . . $
524 $
790 $
— $
381 $
1,848 $
31
—
— $ 156,711
The accompanying notes are an integral part of these Financial Statements.
194
OTAY MESA ENERGY CENTER, LLC
(Previously a Development Stage Company)
NOTES TO FINANCIAL STATEMENTS
For the Years Ended December 31, 2009 and 2008,
and the Period May 1, 2007 to December 31, 2007
1. Organization and Operations
Otay Mesa Energy Center, LLC (previously a development stage company), a Delaware limited liability
company, is an indirect, wholly owned subsidiary of Calpine Corporation (“Calpine Corp.”). OMEC was formed for
the purpose of developing, constructing, financing, operating and maintaining Otay Mesa Energy Center, a 608 MW
peak capacity, natural gas-fired, combined-cycle power plant (the “Plant”) located in San Diego County, California.
The Plant commenced operations on October 3, 2009 (the “Commercial Operations Date”). The Plant sells capacity
under a long-term PPA with a related party, SDG&E. See Note 8 for additional discussion.
Management believes the Plant meets the current requirements for status as an EWG, as defined by PUHCA
2005. An EWG is defined as the owner or operator of an electric generation plant used exclusively for the wholesale
generation and sale of electric power.
Prior to 2007, all activities related to the development and construction of the Plant were conducted by
Calpine Corp. and certain of its affiliates. Effective May 1, 2007, OMEC entered into various agreements,
including the PPA Reinstatement Agreement, the Contribution and Transfer Agreement and the Ground Sublease
and Easement Agreement (collectively, the “Agreements”), by and among OMEC, Calpine Corp. and SDG&E.
In accordance with the Agreements, Calpine Corp. and certain of its affiliates contributed all cash, property and
equipment, and other assets and liabilities associated with the Plant to OMEC and assigned certain related
contracts to OMEC.
Calpine assigned its leasehold interest under the Ground Sublease and Easement Agreement (the
“Sublease Agreement”) to SDG&E. The Sublease Agreement includes a put option by OMEC to sell, and a call
option by SDG&E to buy, the Plant at the end of the term of the PPA. See Note 3 for additional discussion.
Management of Calpine Corp. determined that the PPA, along with the put and call options, absorb the majority
of the risk from OMEC such that OMEC is a VIE and Calpine Corp. is not the primary beneficiary during the
period May 1, 2007 to December 31, 2009. As there was a new primary beneficiary as of May 1, 2007, there was
a change in the basis of accounting. As a result, the assets and liabilities contributed by Calpine Corp. and certain
of its affiliates were measured at fair value as of May 1, 2007, (the “Contribution Date”). Prior to the
Commercial Operations Date, OMEC devoted substantially all its efforts to constructing the Plant.
2. Business Risks
Several current
financial
performance. Some of the business risks and uncertainties that could cause future results to differ from historical
results include, but are not limited to:
industry could have an effect on OMEC’s
in the power
issues
•
The uncertain length and severity of the current depressed general financial and economic conditions
and its impacts on OMEC’s business, including demand for power and the ability of OMEC’s
contractual counterparties to perform under their contracts with OMEC;
• OMEC’s ability to manage its customer and counterparty exposure and credit risk;
• Regulation in the markets in which OMEC participates and OMEC’s ability to effectively respond to
changes in federal, state and regional laws and regulations, including environmental regulations;
195
OTAY MESA ENERGY CENTER, LLC
(Previously a Development Stage Company)
NOTES TO FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009 and 2008,
and the Period May 1, 2007 to December 31, 2007
• Natural disasters such as hurricanes, earthquakes and floods, or acts of terrorism that may impact the
Plant or the market it serves;
•
Seasonal fluctuations of OMEC’s results and exposure to variations in weather patterns;
• Disruptions in or limitations on the transportation of natural gas and transmission of power;
•
Present and possible future claims, litigation and enforcement actions;
• Risks associated with the operation of a power plant including unscheduled outages; and
•
The expiration or termination of OMEC’s PPA with SDG&E and the related results on revenues.
3. Summary of Significant Accounting Policies
Basis of Presentation
The financial statements have been prepared in accordance with GAAP. The financial statements reflect
all costs of doing business, including those incurred by Calpine Corp. on OMEC’s behalf. Costs that are clearly
identifiable as being applicable to OMEC have been allocated to OMEC by Calpine Corp. Centralized
departments that serve all business units have allocated costs to OMEC using relevant allocation measures,
primarily budgeted productivity. The most significant costs in this category include salaries and benefits of
certain employees, legal and other professional fees, information technology costs and facilities costs, including
office rent. Calpine Corp. corporate costs that clearly relate to other business segments of Calpine Corp. have not
been allocated to OMEC.
Use of Estimates in Preparation of Financial Statements
The preparation of the financial statements in conformity with GAAP requires management to make
estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related
disclosure in these financial statements. Actual results could differ from those estimates.
Fair Value of Financial Instruments
The carrying value of cash and cash equivalents, restricted cash, accounts receivable, accounts payable
and other current liabilities approximate their respective fair values due to their short-term maturities. See Note 5
for disclosures regarding the fair value of OMEC’s project financing. See Note 6 for disclosures regarding the
fair value of OMEC’s derivative instruments.
Concentration of Credit Risk
Financial instruments that potentially subject OMEC to credit risk consist primarily of cash and cash
equivalents, restricted cash, accounts receivable and derivative instruments. Cash and cash equivalent balances,
as well as restricted cash balances, may exceed FDIC limits or are invested in money market accounts with
investment banks that are not FDIC insured. OMEC places cash and cash equivalents and restricted cash in what
196
OTAY MESA ENERGY CENTER, LLC
(Previously a Development Stage Company)
NOTES TO FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009 and 2008,
and the Period May 1, 2007 to December 31, 2007
it believes to be credit-worthy financial institutions, and certain money market accounts invest in U.S. Treasury
securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities.
The counterparty to the interest rate swaps is a major financial institution. Management does not believe there is
significant risk to OMEC relating to the financial institutions. OMEC sells power to a public utility under a long-
term agreement, and accounts receivable are concentrated with SDG&E. OMEC has exposure to trends within
the energy industry, including declines in the creditworthiness of SDG&E. OMEC generally has not collected
collateral or other security to support its power-related accounts receivable. OMEC does not believe there is
significant credit risk associated with SDG&E.
Cash and Cash Equivalents
OMEC considers all highly liquid investments with an original maturity of three months or less to be cash
equivalents.
Restricted Cash
OMEC is required to maintain cash balances that are restricted by the provisions of its financing
agreement, which restricts the use of certain cash inflows received during the construction phase and after
achieving commercial operations. These amounts are held by a depository bank in order to comply with the
contractual provisions regarding reserves for operating, maintenance, debt service, and restricted distributions to
OMEC’s parent. Funds that can be used to satisfy obligations due during the next 12 months are classified as
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 in the Balance
Sheets and Statements of Cash Flows.
Accounts Receivable and Payable
Accounts receivable and payable represent amounts due from customers, including related parties, and
owed to both related party and third-party vendors. 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.
Management uses their 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 significant one-time
events. Specific provisions are recorded for individual receivables when management becomes aware of a
customer’s inability to meet its financial obligations. Management reviews the adequacy of the reserves and
allowances quarterly. As of December 31, 2009 and 2008, OMEC determined that no allowance for doubtful
accounts was required.
Capitalized Interest
OMEC capitalized interest on capital invested in the Plant during the advanced stages of development and
the construction period. OMEC’s qualifying assets included all of its construction in progress. Interest capitalized
totaled $5.8 million and $9.2 million for the years ended December 31, 2009 and 2008, respectively, and
$1.4 million for the period May 1, 2007 to December 31, 2007. Upon commencement of commercial operations
197
OTAY MESA ENERGY CENTER, LLC
(Previously a Development Stage Company)
NOTES TO FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009 and 2008,
and the Period May 1, 2007 to December 31, 2007
of the Plant, capitalized interest, as a component of the total cost of the Plant, is amortized over the estimated
useful life of the Plant.
Derivative Instruments
OMEC entered into derivative instruments to manage its interest rate risk on its project financing. OMEC
recognizes all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities
and measures those instruments at fair value. OMEC presents cash flows from interest rate swaps within
operating activities on the Statements of Cash Flows.
Gains and losses on interest rate swaps that qualify for hedge accounting are recorded in the period and
same financial statement line item as the hedged item. Hedge accounting requires management to formally
document, designate and assess the effectiveness of transactions that receive hedge accounting. For gains and
losses on interest rate swaps that do not qualify for or have not been documented for hedge accounting treatment,
changes in fair value are recognized currently into earnings.
Accounting for derivatives at fair value requires management to make estimates about future prices during
periods for which price quotes are not available from external sources, in which case management relies on
internally developed price estimates. During periods where external price quotes are not available, management
derives such future price estimates based on an extrapolation of prices from periods where external price quotes are
available. Management performs this extrapolation using liquid and observable market prices and extending those
prices to an internally generated long-term price forecast based on a generalized equilibrium model.
Materials and Supplies
Materials and supplies consist of spare parts and are valued at weighted average cost. Costs are expensed to
plant operating expense or capitalized into property, plant and equipment as the parts are utilized and consumed.
Property, Plant and Equipment, Net
Property, plant, and equipment items are recorded at cost. OMEC capitalizes costs incurred in connection
with the construction of the Plant and the refurbishment of major turbine generator equipment. Annual planned
maintenance is expensed when the service is performed. The Plant’s assets, excluding rotable parts, are
depreciated on a composite basis over a useful life of 37 years, utilizing the straight-line method and an estimated
salvage value of 10% of the depreciable cost basis. Rotable parts are depreciated on a component basis, which
generally ranges from 3 to 18 years, utilizing the straight-line method, with an estimated salvage value of 0.15%
of the depreciable cost basis.
Impairment Evaluation of Long-Lived Assets
Management evaluates long-lived assets for impairment when such events or changes in circumstances
indicate that
the carrying value of such assets may not be recoverable. When management believes an
impairment condition may have occurred, they 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
198
OTAY MESA ENERGY CENTER, LLC
(Previously a Development Stage Company)
NOTES TO FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009 and 2008,
and the Period May 1, 2007 to December 31, 2007
expected to be held and used. Such cash flows do not include interest or tax expense cash outflows. In the event
such cash flows are not expected to be sufficient to recover the recorded value of the assets, the assets are written
down to their estimated fair values. Except as noted below at Intangible Assets, Net, no impairment charge was
recorded for the years ended December 31, 2009 and 2008, and for the period May 1, 2007 to December 31,
2007.
Intangible Assets, Net
Intangible assets consist of contractual rights and the put option included within the Agreements that were
recorded at fair value on the Contribution Date, when Calpine Corp. contributed assets and liabilities to OMEC.
Intangible assets with finite lives are amortized on a straight-line basis over their estimated useful lives and are
reviewed for impairment whenever changes in circumstances indicate that the carrying amount of the asset may
not be recoverable. Contractual rights under the Agreements totaled $42.6 million and began amortizing on the
Commercial Operations Date. The contractual rights are subject to amortization over the 10-year term of the PPA
on a straight-line basis. Amortization expense on the contractual rights totaled $1.0 million for the year ended
December 31, 2009 and is included in depreciation and amortization expense in the Statement of Operations. The
put option included within the Agreements is generally exercisable 180 days after the ninth anniversary of the
commercial operation date through the tenth anniversary and allows OMEC to put the Plant to SDG&E for
$280.0 million. The put had a value of $3.5 million at inception and is reviewed at least annually for impairment.
During 2009, management determined that the put option was impaired based on an evaluation of the likelihood
that the option will be exercised. As a result of this evaluation, management recorded asset impairment expense
of $1.6 million in the Statement of Operations for the year ended December 31, 2009. No impairment expense
was recorded for the years ended December 31, 2008, and for the period May 1, 2007 to December 31, 2007.
The Agreements also include a call option whereby SDG&E may purchase the Plant for $377.0 million.
The call option is valued at $46.1 million and is generally exercisable between the ninth and tenth anniversaries
of the Plant’s Commercial Operations Date. The carrying value of the call will be adjusted at the time the option
is exercised or expires.
Asset Retirement Obligations
OMEC records 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. OMEC’s asset retirement obligations primarily relate to
land leases upon which the Plant is built.
Deferred Financing Costs
Costs incurred related to the issuance of debt instruments are deferred and amortized over the term of the
related debt using the effective interest rate method. Prior to the Commercial Operations Date, amortization costs
of $0.5 million and $0.4 million for the years ended December 31, 2009 and 2008, respectively, and nil for the
period May 1, 2007 to December 31, 2007, were capitalized to construction in progress and are subject to
amortization over the estimated useful life of the Plant. Subsequent to the Commercial Operations Date,
amortization costs of $0.2 million were included in interest expense in the Statement of Operations for the year
ended December 31, 2009.
199
OTAY MESA ENERGY CENTER, LLC
(Previously a Development Stage Company)
NOTES TO FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009 and 2008,
and the Period May 1, 2007 to December 31, 2007
Revenue Recognition
Contracts accounted for as operating leases, such as certain tolling agreements, with minimum lease
rentals that vary over time must be levelized. The PPA with SDG&E is a tolling agreement that meets the criteria
of an operating lease. OMEC levelizes the minimum lease payments on a straight-line basis over the term of the
contract.
Project Development Expense
Project development expense represents costs incurred by OMEC prior to the Commercial Operations
Date related to anticipated post-operational needs of the Plant. Such costs included hiring and training of
operations personnel, which are not subject to capitalization under GAAP and were expensed as incurred.
Income Taxes
OMEC is a single member limited liability company whose tax results are included in the consolidated
U.S. federal and state income tax returns of Calpine Corp. and is treated as a taxable entity for financial reporting
purposes. For separate company financial reporting purposes, income taxes are calculated by OMEC on a
separate return basis.
Income taxes are accounted for under the asset and liability method. OMEC has reported its assets and
liabilities at fair value as of the Contribution Date; however, the deferred tax assets and liabilities are recorded
based on Calpine Corp.’s original basis as there was no change in the tax entity. 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 bases and net operating loss and tax
credit 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. OMEC recognizes interest and penalties incurred in income tax expense in the statements of
operations. For the years ended December 31, 2009 and 2008, OMEC did not incur any tax-related penalties or
interest.
OMEC recognizes 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. OMEC reverses 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 9 for further discussion on OMEC’s income taxes.
New Accounting Standards and Disclosure Requirements
Accounting Standards Codification and GAAP Hierarchy — Effective for interim and annual periods
ending after September 15, 2009, the Accounting Standards Codification, or ASC, and related disclosure
requirements issued by the Financial Accounting Standards Board became the single official source of
authoritative, nongovernmental GAAP. The ASC simplifies GAAP, without change, by consolidating the
200
OTAY MESA ENERGY CENTER, LLC
(Previously a Development Stage Company)
NOTES TO FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009 and 2008,
and the Period May 1, 2007 to December 31, 2007
numerous, predecessor accounting standards and requirements into logically organized topics. All other literature
not included in the ASC is non-authoritative. Management adopted the ASC as of September 30, 2009, which did
not have any impact on the results of operations, financial condition or cash flows as it does not represent new
accounting literature or requirements; however, it did change references within this report to authoritative
sources of GAAP to the new ASC nomenclature.
Fair Value Measurements of Non-Financial Assets and Non-Financial Liabilities — Effective for interim
and annual periods beginning after November 15, 2008, GAAP includes new standards related to fair value
measurements for non-financial assets and liabilities. These new standards do not apply to assets and liabilities
that were not previously required to be recorded at fair value, but do apply when other accounting standards
require fair value measurements. The new standards also define fair value, establish a framework for measuring
fair value under GAAP and enhance disclosures about fair value measurements. Management adopted the new
standards with respect to non-financial assets and non-financial liabilities as of January 1, 2009, which did not
have a material effect on the results of operations, financial position or cash flows; however, adoption may
impact measurements of asset impairments and asset retirement obligations if they occur in the future.
Disclosures About Derivative Instruments and Hedging Activities — Effective for interim and annual
periods beginning after November 15, 2008, GAAP includes enhanced disclosure requirements relating to an
entity’s derivative and hedging activities to enable investors to better understand their effects on the entity’s
financial position, financial performance, and cash flows. OMEC adopted the new disclosure requirements as of
January 1, 2009. Adoption resulted in additional disclosures related to OMEC’s derivatives and hedging
activities including additional disclosures regarding OMEC’s objectives for entering into derivative transactions,
increased balance sheet and financial performance disclosures, volume information and credit enhancement
disclosures. See Note 7 for OMEC’s derivative disclosures.
Fair Value Measurements and Disclosures — In January 2010, FASB issued Accounting Standards
Update 2010-06, “Fair Value Measurements and Disclosures” to enhance disclosure requirements relating to
different levels of assets and liabilities measured at fair value and to clarify certain existing disclosures. The
update requires disclosure of transfers in and out of levels 1 and 2 and gross presentation of purchases, sales,
issuances and settlements in the level 3 reconciliation of beginning and ending balances. The new disclosure
interim and annual periods beginning after
requirements relating to level 3 activity are effective for
December 15, 2010 and all the other requirements are effective for interim and annual periods beginning after
December 15, 2009. Since this update only requires additional disclosures, management does not expect this
standard to have a material impact on OMEC’s results of operations, cash flows or financial position.
Subsequent Events — Effective for interim and annual periods ending after June 15, 2009, GAAP
includes general standards of accounting for and disclosure of events that occur after the balance sheet date but
before financial statements are issued or are available to be issued. The new standards do not change the
accounting for subsequent events; however, they do require disclosure, on a prospective basis, of the date an
entity has evaluated subsequent events. Management adopted these new standards for the year ended
December 31, 2009, which had no impact on OMEC’s results of operations, financial condition or cash flows.
Management has evaluated subsequent events up to the time of issuance of this Report on February 24, 2010.
201
OTAY MESA ENERGY CENTER, LLC
(Previously a Development Stage Company)
NOTES TO FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009 and 2008,
and the Period May 1, 2007 to December 31, 2007
4. Property, Plant and Equipment, Net
As of December 31, 2009 and 2008, property, plant and equipment, are stated at cost less accumulated
depreciation as follows (in thousands):
Building, machinery and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Construction in progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Emission reduction credits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Less: Accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
529,364
—
16,693
546,057
(4,055)
Property, plant and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
542,002
$
—
446,020
16,693
462,713
—
462,713
2009
2008
5. Project Financing
On the Contribution Date, OMEC entered into a credit agreement with a group of lenders for $377.0
million (the “Credit Agreement”). The project financing is collateralized by OMEC’s assets and is non-recourse
to Calpine Corp. and its other affiliates. The project financing was used to fund the construction activities for the
Plant. The construction loan converted to a term loan on November 13, 2009, after the Plant satisfied conversion
requirements of the Credit Agreement. The term loan matures on April 30, 2019.
Borrowings under the Credit Agreement bear variable interest that, depending on the specific terms of the
loan, are calculated based on adjusted LIBOR plus an applicable margin of 1.5%. The effective interest rate was
approximately 7.1% for both the years ended December 31, 2009 and 2008, and 6.5% for the period May 1, 2007
to December 31, 2007. The Credit Agreement requires OMEC to maintain certain covenants, including debt
service coverage and debt to equity ratios, once the Plant commenced commercial operations, as well as certain
other funding and performance covenants.
As of December 31, 2009, the scheduled maturities of the project financing are as follows (in thousands):
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
9,949
9,949
9,949
9,949
9,949
324,768
374,513
Under GAAP, OMEC measures the fair value of its project financing using discounted cash flow analyses
based on current borrowing rates for similar types of borrowing arrangements. The estimated fair value of the
project financing was $339.4 million and $227.0 million as of December 31, 2009 and 2008, respectively, with
the increase in fair value primarily due to additional borrowings under the project financing in 2009.
202
OTAY MESA ENERGY CENTER, LLC
(Previously a Development Stage Company)
NOTES TO FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009 and 2008,
and the Period May 1, 2007 to December 31, 2007
6. Fair Value Measurements
Financial Instruments
OMEC has cash equivalents that are classified within level 1 of the fair value hierarchy as the amounts
approximate fair value. These financial instruments are invested in money market accounts and included in cash
and cash equivalents and restricted cash on the Balance Sheets.
Interest Rate Swaps
A significant portion of OMEC’s debt is indexed to LIBOR. Management uses interest rate swaps to
effectively convert a portion of the floating rate component of the debt to a fixed rate. These transactions act as
economic hedges for the interest cash flow. Interest rate swaps are measured at their fair value and recorded as
either assets or liabilities. OMEC does not use interest rate derivative instruments for trading purposes.
The fair value of OMEC’s interest rate swaps is determined based on observable market-based pricing
inputs, and the swaps are classified as level 2 derivative instruments. Generally, management obtains level 2
pricing inputs from markets such as Bloomberg. In certain instances, 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.
OMEC utilizes market data, such as pricing services and broker quotes, and assumptions that
management believes market participants would use in pricing assets or liabilities including assumptions about
risks and the risks inherent to the inputs in the valuation technique. These inputs can be 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
management’s assessment of fair value; however, other qualitative assessments are used to determine the level of
activity in any given market. OMEC primarily applies the market approach and income approach for recurring
fair value measurements and utilizes what management believes to be the best available information. The
valuation techniques used seek to maximize the use of observable inputs and minimize the use of unobservable
inputs. The fair value balances are classified based on the observability of those inputs.
The fair value of OMEC’s derivatives includes consideration of OMEC’s credit standing and the credit
standing of its counterparties. OMEC has also recorded credit reserves in the determination of fair value based on
management’s expectation of how market participants would determine fair value. Such valuation adjustments
are generally based on market evidence, if available, or management’s best estimate.
The following tables present OMEC’s financial assets and liabilities that were accounted for at fair value
on a recurring basis as of December 31, 2009 and 2008, by level within the fair value hierarchy. Financial assets
and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value
measurement. Management’s assessment of the significance of a particular input to the fair value measurement
203
OTAY MESA ENERGY CENTER, LLC
(Previously a Development Stage Company)
NOTES TO FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009 and 2008,
and the Period May 1, 2007 to December 31, 2007
requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the
fair value hierarchy levels.
Assets:
Cash equivalents(1) . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities:
Interest rate swaps . . . . . . . . . . . . . . . . . . . . . . . .
Total liabilities . . . . . . . . . . . . . . . . . . . . . . . .
Assets:
Cash equivalents(1) . . . . . . . . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . .
Liabilities:
Interest rate swaps . . . . . . . . . . . . . . . . . . . . . . . .
Total liabilities . . . . . . . . . . . . . . . . . . . . . . . .
Level 1
Level 2
Level 3
Total
December 31, 2009
(in thousands)
15,099
15,099
$
$
— $
— $
— $
— $
42,637
42,637
$
$
— $
— $
— $
— $
15,099
15,099
42,637
42,637
Level 1
Level 2
Level 3
Total
December 31, 2008
(in thousands)
11,556
11,556
$
$
— $
— $
— $
— $
84,573
84,573
$
$
— $
— $
— $
— $
11,556
11,556
84,573
84,573
$
$
$
$
$
$
$
$
(1) As of December 31, 2009, and 2008, cash equivalents of $7.4 million and $11.5 million were included in
cash and cash equivalents, and $7.7 million and $0.1 million were included in restricted cash, respectively.
7. Derivative Instruments
Accounting for Derivative Instruments
Cash Flow Hedges — OMEC reports 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 reclassifies
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 included in unrealized
gains and losses and are recognized currently in earnings as interest expense. If it is determined that the forecasted
transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively. If the
hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the
gain or loss associated with the hedge instrument remains deferred in OCI 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 — OMEC enters into interest rate transactions that
primarily act as economic hedges, but either do not qualify as hedges under hedge accounting guidelines or qualify
under the hedge accounting guidelines and the hedge accounting designation has not been elected. Changes in fair
value of derivatives not designated as hedging instruments are recognized currently in earnings as interest expense.
204
OTAY MESA ENERGY CENTER, LLC
(Previously a Development Stage Company)
NOTES TO FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009 and 2008,
and the Period May 1, 2007 to December 31, 2007
OMEC designated interest rate swap agreements as cash flow hedges of the project financing on
October 31, 2007 and discontinued the cash flow hedge designation on March 31, 2008. During this period,
changes in the fair value related to the effective portion of the swap agreements were recorded to AOCI. Prior to
October 31, 2007, changes in the fair value of interest rate swaps totaling $8.3 million were recorded as interest
expense in the Statement of Operations. During the three months ended March 31, 2008, OMEC recognized an
unrealized loss in AOCI totaling $17.0 million. Subsequent to March 31, 2008, changes in the fair value of the
swap agreements were recorded in earnings as a component of interest expense.
As of December 31, 2009, the net forward notional buy (sell) position of OMEC’s outstanding interest
rate swap contracts were as follows (in thousands):
Interest rate swaps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
374,513
Derivative Instruments
Notional
Volumes
Changes in the fair values of derivative instruments (both assets and liabilities) are reflected either in
OCI, net of tax, for the effective portion of derivative instruments which qualify for cash flow hedge accounting
treatment, or on the Statements of Operations as a component of interest expense within net income.
The following table details the components of total mark-to-market activity for both the net realized gain
(loss) and the net unrealized gain (loss) recognized from OMEC’s interest rate swaps included in interest expense
in the Statements of Operations for the years ended December 31, 2009 and 2008, and the period May 1, 2007 to
December 31, 2007 (in thousands):
Realized gain (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrealized gain (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total mark-to-market gain (loss) . . . . . . . . . . . . . . . . . . . . . . . . .
2009
2008
2007
$
$
(14,652) $
39,492
(3,631) $
(49,644)
24,840
$
(53,275) $
(38)
(8,561)
(8,599)
For the years ended December 31, 2009 and 2008, OMEC recorded losses to increase interest expense of
$2.1 million and $0, respectively, and $0 for the period May 1, 2007 to December 31, 2007, based on the
reclassification adjustment from AOCI into earnings. OMEC currently estimates that pre-tax losses of
approximately $6.9 million would be reclassified from AOCI into earnings during the 12 months ended
December 31, 2010.
8. Related Party Transactions
Project Management Agreement
On the Contribution Date, OMEC entered into an agreement (the “PMA”) with Calpine Construction
Management Company, Inc. (“CCMCI”), an indirect, wholly owned subsidiary of Calpine Corp., whereby
CCMCI would provide all project management and procurement services, installation services, commissioning
services and post completion services for the construction of the Plant. After completion of the performance
205
OTAY MESA ENERGY CENTER, LLC
(Previously a Development Stage Company)
NOTES TO FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009 and 2008,
and the Period May 1, 2007 to December 31, 2007
conditions stipulated in the PMA, including payment of outstanding balances, the PMA will be terminated.
Under the PMA, OMEC incurred costs of $19.7 million and $4.4 million for the years ended December 31, 2009
and 2008, respectively, and $3.0 million for the period May 1, 2007 to December 31, 2007, which were
capitalized to property, plant and equipment. Additionally, the PMA required CCMCI to pay delay liquidated
damages to OMEC in the amount of $101,000 per day in the event that the project completion did not occur on or
before the guaranteed completion date of May 1, 2009. Liquidating damages to OMEC under the PMA totaled
$15.1 million and were recorded as a reduction in amounts capitalized to property, plant and equipment. As of
December 31, 2009 and 2008, accounts payable to CCMCI totaled $0.3 million and $0.8 million, respectively.
Operations and Maintenance Agreement
OMEC has contracted with Calpine Operating Services Company, Inc. (“COSCI”), an indirect, wholly
owned subsidiary of Calpine Corp. for the operation and maintenance of the Plant under an agreement (the
“O&M Agreement”) dated May 1, 2007. The O&M Agreement is effective through the maturity date of the
project financing, with provisions for successive one-year renewals. Under the terms of the O&M Agreement,
COSCI is obligated to perform all operation and maintenance services in connection with the business, including
operation,
technical analyses and contract
administration. OMEC reimburses COSCI for its direct costs, including direct labor costs and other costs
incurred in the performance of the services. The O&M Agreement stipulates a quarterly administrative fee of
$125,000, which is subject to annual escalation. For the years ended December 31, 2009 and 2008, OMEC
recorded expenses under the O&M Agreement of $2.5 million and $0, respectively, and $0 for the period May 1,
2007 to December 31, 2007, inclusive of reimbursable expenses. As of December 31, 2009 and 2008, accounts
payable to COSCI totaled $0.9 million and $0, respectively.
repair and maintenance, administrative and billing services,
Activity with Calpine Corp.
On the Contribution Date, Calpine Corp. contributed cash, property, plant and equipment, other assets and
liabilities to OMEC under the Contribution and Transfer Agreement dated October 23, 2006. Calpine Corp.
contributed its benefit to payments under a note receivable in the amount of $1.7 million for the year ended
December 31, 2008, and $0.1 million for the period May 1, 2007 to December 31, 2007. In addition to the
payments due under the note receivable, Calpine Corp. contributed $4.3 million and $8.6 million of cash to
OMEC for the years ended December 31, 2009 and 2008, respectively, and $0.3 million for the period May 1,
2007 to December 31, 2007, to support construction-related activities.
During 2009, OMEC made a cash distribution to Calpine Corp. for $9.1 million in accordance with the
terms of the Credit Agreement. OMEC also recorded cost allocations from Calpine Corp. for centralized services
for $2.3 million, which are included in general and administrative expense in the Statement of Operations for the
year ended December 31, 2009.
At December 31, 2009 and 2008, OMEC had accounts payable to other Calpine Corp. affiliates of $3.3
million and $3.9 million, respectively, resulting from transactions in the ordinary course of business.
Amended and Restated Power Purchase Agreement
On May 1, 2007, OMEC entered into the PPA with SDG&E, a related party, to sell all power capacity of
the Plant upon achieving commercial operations. The PPA has a term of 10 years from the commencement of
206
OTAY MESA ENERGY CENTER, LLC
(Previously a Development Stage Company)
NOTES TO FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009 and 2008,
and the Period May 1, 2007 to December 31, 2007
commercial operation of the Plant. Under the terms of the PPA, OMEC receives monthly payments, primarily
consisting of a capacity component, variable operation and maintenance component and a start-up payment. In
addition, SDG&E is responsible for fuel supply and transportation to the Plant.
The PPA meets the criteria of an operating lease, with the capacity payments levelized on a straight-line
basis over the term of the agreement. Minimum payments due to OMEC under the PPA are as follows (in
thousands):
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
72,553
70,763
70,763
70,763
70,763
337,960
693,565
At December 31, 2009 and 2008, OMEC had accounts receivable from SDG&E related to the PPA of
$10.6 million and $0, respectively.
Under the terms of the PPA, OMEC was required to pay liquidating damages of $50,000 per day if
commercial operations did not commence before the guaranteed commercial operations date of May 30, 2009.
OMEC recorded liquidating damages to SDG&E totaling $6.1 million, which are included in the Statement of
Operations for the year ended December 31, 2009.
Restated Interconnection Facility Agreement
On May 1, 2007, Calpine Corp. assigned the Restated Interconnections Facility Agreement (“RIFA”) and
Restated Interconnection Agreement (“RIA”) with SDG&E to OMEC. The RIFA agreement requires SDG&E to
design, engineer, construct and install the switchyard facilities and perform transmission upgrades in which
OMEC will reimburse SDG&E. As of December 31, 2008, OMEC had recorded $22.7 million, including $8.6
million contributed from Calpine Corp., for network upgrades and accrued interest under the RIFA, which is
included in deferred transmission credits, related party in the balance sheet. During the year ended December 31,
2009, additional upgrade costs and accrued interest totaling $0.8 million were recorded under the RIFA. At the
Commercial Operations Date, OMEC was entitled to a repayment for the cost of the interconnection facilities
that were considered network upgrades, including interest from the time the original payments were made.
During the year ended December 31, 2009, OMEC received $23.5 million from SDG&E for repayment of the
cost of transmission facilities.
207
OTAY MESA ENERGY CENTER, LLC
(Previously a Development Stage Company)
NOTES TO FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009 and 2008,
and the Period May 1, 2007 to December 31, 2007
9. Income Taxes
OMEC accrues taxes at the enacted statutory rates. The income tax provision reflected in the statements
of operations for the years ended December 31, 2009 and 2008, and for the period May 1, 2007 to December 31,
2007, consisted of the following (in thousands):
2009
2008
2007
Current:
Federal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
— $
—
— $
28
Total current . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred:
Federal
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total deferred . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
—
—
—
Total income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
— $
28
—
—
—
28
$
—
—
—
—
—
—
—
A reconciliation of the U.S. federal statutory rate of 35% to the effective tax rate for the years ended
December 31, 2009 and 2008, and for the period May 1, 2007 to December 31, 2007, is as follows:
Federal statutory tax expense rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Effective income tax expense rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2009
2008
2007
35%
(35)
0%
35%
(35)
0%
35%
(35)
0%
The components of deferred taxes as of December 31, 2009 and 2008, are as follows (in thousands):
2009
2008
Deferred tax assets:
Deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Derivative instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Written call option . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net operating loss carryover . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
122
18,692
20,219
20,430
78,175
122
37,076
20,219
2,495
85,783
Deferred tax assets before valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total deferred tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
137,638
(118,080)
19,558
145,695
(125,476)
20,219
Deferred tax liabilities:
Intangible asset . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total deferred tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net deferred tax asset . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Current portion deferred tax asset . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(19,496)
(62)
(19,558)
—
387
Deferred income taxes, net of current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
(387) $
(20,219)
—
(20,219)
—
513
(513)
208
OTAY MESA ENERGY CENTER, LLC
(Previously a Development Stage Company)
NOTES TO FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009 and 2008,
and the Period May 1, 2007 to December 31, 2007
For the year ended December 31, 2009, OMEC had U.S. federal and state NOL carryforwards of $50.3
million and $31.9 million, respectively, which will expire between 2022 and 2029 for both state and U.S. federal
purposes if not utilized. These NOL carryforwards include the effects of activities conducted by Calpine Corp. on
OMEC’s behalf from 2002 to April 30, 2007, prior to the Contribution Date. In addition, as a result of the
bankruptcy filing discussed in Note 10 and other factors, Calpine Corp. concluded that impairment indicators
existed for certain long-lived assets during 2005. These long-lived assets were evaluated for impairment based on
probability-weighted alternatives of utilizing the assets versus reselling the assets to third parties. Prior to 2007,
impairment and other charges totaling approximately $195.0 million were recorded to reduce the assets to their
estimated realizable value which were included in Calpine Corp.’s original basis contributed to OMEC in
May 2007 and resulted in a deferred tax asset.
In assessing the realizability of deferred tax assets, management considers whether it is more likely than
not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax
assets is dependent upon the generation of future taxable income during the periods in which those temporary
differences become deductible. A valuation allowance is recorded when it is more likely than not that a deferred
tax asset will not be realized. Based on the weight of available positive and negative evidence, management
determined it was appropriate to record a valuation allowance on all deferred tax assets at both December 31,
2009 and 2008, to the extent not offset by taxable income generated by reversing temporary differences of the
appropriate character within the carryback or carryforward periods. As a result, OMEC has provided a valuation
allowance of $118.1 million and $125.5 million as of December 31, 2009 and 2008, respectively.
OMEC’s unrecognized tax benefit decreased during 2009, due to elimination of the uncertain tax
position. When the Plant achieved commercial operations, management reassessed the tax basis of the assets. As
the tax basis of the assets was adjusted, the uncertain tax position was resolved. A reconciliation of the beginning
and ending amount of the unrecognized tax benefits is as follows (in thousands):
Balance, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Increase related to current year tax positions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Decrease related to prior year tax positions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
$
2,107
—
(2,107)
Balance, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
— $
2,091
16
—
2,107
2009
2008
10. Impact of Calpine Corp.’s Bankruptcy
On December 20, 2005, Calpine Corp. and certain of its subsidiaries, including CCMCI and COSCI, but
not OMEC, filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy
Court. The Calpine Debtors’ plan of reorganization, as approved by its creditors, was confirmed by the
Bankruptcy Court on December 19, 2007, and became effective on January 31, 2008. While OMEC was not a
Calpine Debtor, it did have agreements with Calpine Debtors. During the bankruptcy cases, both CCMCI and
COSCI assumed and continued to perform under their agreements with OMEC.
209
OTAY MESA ENERGY CENTER, LLC
(Previously a Development Stage Company)
NOTES TO FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009 and 2008,
and the Period May 1, 2007 to December 31, 2007
11. Commitments and Contingencies
Letter of Credit
As of December 31, 2008, OMEC had a letter of credit available, but not drawn upon, of $25.0 million.
The purpose of the letter of credit was to secure OMEC’s obligations to SDG&E during the construction period,
as required under the PPA. The letter of credit was cancelled in October 2009.
Ground Sublease and Easement Agreement
On May 1, 2007, OMEC entered into the Sublease Agreement with Calpine Corp. Calpine Corp.
subsequently assigned its leasehold interest under the Sublease Agreement to SDG&E. The Sublease Agreement
expires on July 7, 2032, and has provisions for two ten-year renewal terms. As subrent under this agreement,
OMEC shall pay to SDG&E base subrent equal to $1.00 per year and shall pay directly to the lessor on
SDG&E’s behalf all of the other amounts owing by SDG&E under the original ground lease (whether as rent,
additional rent or otherwise) including taxes and similar charges that SDG&E is obligated to pay under the
original ground lease. Under the Sublease Agreement, OMEC has an option to require SDG&E to sell its
leasehold interest in the site to OMEC if the call and put options discussed in Note 3 are not exercised. Ground
lease expense is levelized over the term of the agreement. Ground lease expense totaled $0.3 million and $0, net
of expenses capitalized to property, plant and equipment of $0.9 million and $1.2 million, for the years ended
December 31, 2009 and 2008, respectively. Costs incurred under the Sublease Agreement totaled $0.8 million for
the period May 1, 2007 to December 31, 2007, and were capitalized to property, plant and equipment. The
Sublease Agreement is accounted for as an operating lease. Minimum lease payments are levelized over the term
of the agreement, and the resulting deferred lease levelization liability is included in other long-term liabilities on
the Balance Sheets.
As of December 31, 2009, minimum lease payments are as follows (in thousands):
2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2013 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
903
931
958
987
1,017
23,801
28,597
Parcel One Lease Agreement
On May 1, 2007, Calpine Corp. assigned the Parcel One Lease Agreement to OMEC whereby OMEC
paid an annual reservation fee, which was amortized monthly to construction in progress until such time as the
land was parceled and available for lease. On January 10, 2008, OMEC made the annual reservation fee payment
of $0.6 million for the year ended December 31, 2008. On June 17, 2008, the Parcel One Lease Agreement was
amended to reflect reparcelization of the lessor’s land and to identify the specific parcels, now called Parcel 1
210
OTAY MESA ENERGY CENTER, LLC
(Previously a Development Stage Company)
NOTES TO FINANCIAL STATEMENTS — (Continued)
For the Years Ended December 31, 2009 and 2008,
and the Period May 1, 2007 to December 31, 2007
and Parcel 2, which the lessor leased to OMEC. The amended lease expired on June 30, 2009 and was not
renewed by OMEC.
Litigation
OMEC is involved in various legal and litigation matters arising in the normal course of business.
Management does not expect that the outcome of these proceedings will have a material adverse effect on
OMEC’s financial position, results of operations or cash flows.
211
BOARD OF DIRECTORS
William J. Patterson*
Chairman of the Board
Managing Director, SPO Partners & Co.
W. Benjamin Moreland¤
President and Chief Executive Officer,
Crown Castle International Corp.
Frank Cassidy†
Retired President and Chief Operating Officer,
PSEG Power LLC
Robert A. Mosbacher, Jr.† *
Former President and Chief Executive Officer,
Overseas Private Investment Corporation
Jack A. Fusco
President and Chief Executive Officer, Calpine Corp.
Denise M. O’Leary† *
Private Venture Capital Investor
Robert Hinckley¤ *
Chairman and Managing Director, MCL Intellectual
Property, Inc.
David Merritt¤
President, BC Partners, Inc.
EXECUTIVE MANAGEMENT
J. Stuart Ryan†
Founding Owner and President, Rydout LLC
¤ Audit Committee
† Compensation Committee
* Nominating and Governance Committee
Jack A. Fusco
President and Chief Executive Officer
Zamir Rauf
Executive Vice President and Chief Financial Officer
W. Thaddeus Miller
Executive Vice President, Chief Legal Officer and
Corporate Secretary
Gary M. Germeroth
Executive Vice President and Chief Risk Officer
John B. (Thad) Hill
Executive Vice President and Chief Commercial 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
Certifications
Jack A. Fusco and Zamir Rauf have provided certifications to
the Securities and Exchange Commission as required by sections
302 and 906 of the Sarbanes-Oxley Act of 2002. These certi-
fications are included as exhibits 31.1, 31.2 and 32.1 of the
company’s Form 10-K for the year ended December 31, 2009.
On March 8, 2010, Jack A. Fusco submitted an annual certifi-
cation to the New York Stock Exchange (“NYSE”) that stated
he was not aware of any violation by the company of the
NYSE corporate governance listing standards.
Form 10-K
The Company’s Annual Report on Form 10-K for the year ended
December 31, 2009, 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 Wednesday, May 19, 2010, at 10 a.m. Central Time at
The Magnolia Hotel located at 1100 Texas Ave, Houston Texas
77002. All shareholders are cordially invited to attend.
Stock Information
Calpine Corporation’s common stock is listed on the NYSE under
the symbol CPN.
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, 2009, 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